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CANADA ENERGY REGULATOR
IN THE MATTER OF the Canadian Energy Regulator Act, SC 2019, c 28, s 10 and the regulations made thereunder;
AND IN THE MATTER OF an application by Enbridge Pipelines Inc. for approval of the Transportation Service and Toll Methodology for the Canadian Mainline;
AND IN THE MATTER OF Hearing Order RH-001-2020.
Written Argument of the Canadian Shippers Group
July 7, 2021
To: Mr. Jean-Denis Charlebois Secretary of the Commission Suite 210, 517 10 Ave SW Calgary, AB T2R 0A8
LEGAL_CAL:15526888.10 TABLE OF CONTENTS
I. INTRODUCTION ...... 4
II. EXECUTIVE SUMMARY ...... 5
III. BACKGROUND ...... 11
IV. LEGISLATIVE FRAMEWORK ...... 12
Canadian Public Interest ...... 14 Just and Reasonable Tolls ...... 16 No Unjust Discrimination ...... 17 Burden of Proof ...... 18
V. CONSULTATION AND NEGOTIATIONS WERE NEITHER FAIR, OPEN NOR TRANSPARENT, AND THE DEGREE OF OPPOSITION IS UNPRECEDENTED ...... 19
Proposed “Negotiated” Tolls Did Not Result from a Fair and Transparent Negotiation Process ...... 19 Bilateral Negotiations Were Unreasonable and Unfair in the Circumstances ...... 24 Enbridge Abused its Dominant Market Position During the Course of Negotiations ...... 27 Degree of Opposition to the Application...... 30
VI. ENBRIDGE HAS NOT PROVIDED ADEQUATE JUSTIFICATION FOR INTRODUCING MAINLINE CONTRACTING ...... 31
Enbridge has not Demonstrated that it Faces any Material Volume Risk ...... 32 Enbridge has not Demonstrated that Mainline Contracting Is Necessary to Enable Future Expansion ...... 37
VII. CONVERTING THE CANADIAN MAINLINE TO FIRM SERVICE IS NOT IN THE PUBLIC INTEREST ...... 38
Mainline Contracting Would Result in Adverse Impacts on Netbacks and Government Revenues ...... 39 Adverse Impacts on Aggregators and Small to Mid-size Producers ...... 55 Adverse Impacts on Shippers of Refined Products and NGLs ...... 58 Adverse Impacts on Eastern Canadian Refineries ...... 64
VIII. CONTRACTED SERVICE IN THE ABSENCE OF NEW FACILITIES IS UNREASONABLE ...... 66
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TABLE OF CONTENTS (continued)
IX. CONTRACTED SERVICE WOULD RESULT IN THE CREATION OF TWO CLASSES OF SHIPPERS AND UNDUE DISCRIMINATION ...... 69
X. THE PROPOSED OPEN SEASON PROCEDURES AND TSA TERMS ARE UNREASONABLE AND UNJUSTLY DISCRIMINATORY ...... 71
XI. THE PROPOSED TOLLS AND TOLL METHODOLOGIES SHOULD BE REFLECTIVE OF COST OF SERVICE AND TOLL PRINCIPLES ...... 76
Tolls Should Be Cost-Based ...... 76 The Commission’s Requirement for Cost of Service Rate-Making ...... 78 A Cost of Service Review is Necessary ...... 80 A Cost of Service Review is Timely ...... 82
XII. THE PROPOSED TOLLS ARE NOT JUST AND REASONABLE ...... 83
There is Insufficient Information for the Commission to Conclude the Proposed Tolls Are Just and Reasonable ...... 83 The Evidence Demonstrates that the Proposed Tolls Exceed a Reasonable Cost of Service Toll ...... 88 The CER Cannot Rely Upon the Simplified Mainline Contracting Earnings Model Prepared by Concentric ...... 89 Enbridge’s Proposed Toll Methodology Improperly Makes the Revenue Requirement for the Canadian Mainline Dependent Upon Tolls Set in the United States and Establishes “ad hoc” Tolls ...... 98 The Toll Structure is Discriminatory ...... 101 Toll Stability is Not a Significant Consideration ...... 103
XIII. ENBRIDGE SHOULD NOT BE EXEMPT FROM KEEPING A SYSTEM OF ACCOUNTS UNDER THE OPUAR OR FROM FULL REPORTING UNDER GUIDE BB ...... 105
XIV. CSG COMMENTS REGARDING ENBRIDGE’S WRITTEN ARGUMENT ...... 106
Volume Risk ...... 107 Over Subscription ...... 111 Negotiations and Cost Information ...... 111 DSV Requirement Renders the Mainline Unsuitable for Contracting .... 112 CSG Proposal for Rebasing Is Not Regressive ...... 115 Tolling Methodology Should Result in Cost-Based Tolls...... 116 Market-based Solutions ...... 117 Enbridge Fails To Apply Appropriate Principles ...... 118 Enbridge Justification for a Higher ROE Is Not Supported...... 118 Enbridge Advocates An Inappropriate Resolution ...... 119 Drazen Modelling ...... 119 Exemption for OPUAR ...... 123
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TABLE OF CONTENTS (continued)
Divide and conquer ...... 123 Prematurity ...... 124
XV. CONCLUSION AND REQUESTED RELIEF ...... 125
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I. INTRODUCTION
1. This written argument is submitted on behalf of the Canadian Shippers Group1 (the “CSG”) regarding Enbridge Pipelines Inc. (“Enbridge”)’s application for Mainline contracting (the “Application”).
2. Enbridge has applied to the Commission of the Canada Energy Regulator (“Commission” or “CER”) for approval of:
(a) a new service and tolling framework for the Canadian Mainline pipeline system (“Canadian Mainline” or “Mainline”) including:
(i) converting 90% of the Mainline’s current common carrier capacity to contracted service, leaving just 10% remaining for uncommitted (spot) service;
(ii) proposed tolls and terms and conditions of service for contract and uncommitted service, and
(iii) proposed Open Season Procedures;
and
(b) an exemption from the requirement to keep the system of accounts described in the Oil Pipeline Uniform Accounting Regulations, CRC, c 1058 (“OPUAR”).
3. For the reasons set out below, the CSG submits that the Commission must deny the Application. The CSG requests that, in addition to denying the Application, the Commission also direct Enbridge to file an application by January 31, 2022, for tolls calculated on a cost-of-service basis for the Mainline under continued 100% common carrier service.
1 The CSG members are: Canadian Natural Resources Limited (“Canadian Natural”); MEG Energy Corp. (“MEG”); Shell Canada Limited (“Shell Canada”); and Total Energies EP Canada Ltd. (“TOTAL Canada”).
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II. EXECUTIVE SUMMARY
4. The CSG members have distinct and diverse commercial interests. Each CSG member has a unique set of assets and operations, which include oil production, marketing and aggregating, downstream offtake capabilities, refining, natural gas liquids (“NGLs”)2 and refined products distribution and retail operations. However, despite the varied and frequently competing commercial interests of the CSG members, the group is united in its opposition to Enbridge’s Mainline contracting proposal.
5. Enbridge’s evidence presented to the Commission in this proceeding has been internally inconsistent, and in some notable instances, diametrically opposed to communications by Enbridge’s senior management and CEO to its investors and securities regulators. In short, Enbridge’s evidence on key issues, including volume risk, competitiveness of rail, reasonableness of tolls, potential adverse pricing impacts based on what was observed as a result of the 2018 change in Supply Verification Procedures (“SVP”), and the proposition that Mainline contracting is required to assess the demand for expansions, lacks credibility. The Commission should give little weight to Enbridge’s evidence on these issues, which are foundational to Enbridge’s Application.
6. It is for the following reasons that the Application is not in the public interest and must be denied:
(a) Enbridge’s proposal would result in the virtual elimination of common carriage access from the Western Canada Sedimentary Basin (“WCSB”) for the next 20 years (and potentially up to 30 years when contract extension terms are accounted for). This comes at a time when the western Canadian oil industry is suffering from a lack of pipeline egress. Redistributing this scarce pipeline capacity in favour of a small number of companies with significant downstream refining interests will change the functioning of the Canadian crude oil markets and likely result in reduced prices for Canadian oil production to the detriment of Canadian-based companies, governments and the Canadian public at large.
(b) There is strong opposition from a broad array of stakeholders, including a significant majority of pure WCSB-based producers, some Canadian refiners, a feeder pipeline, and the Government of Saskatchewan. Despite support from a minority group of downstream parties, all crude flowing on the Mainline was produced by a WCSB producer, and the level of opposition challenging a proposed “negotiated” contract offering and tolling methodology is unprecedented. Although Enbridge endeavours to characterize its support as broad, the reality is that most supporting companies are organizations with significant U.S. downstream refining
2 Shell Canada is also one of a limited number of shippers of NGLs on the Canadian Mainline, shipping approximately 8,000 bpd. See Transcript Vol. 19, PDF 24, paras 18990 – 18991; Transcript Vol. 17, PDF 37, paras 16853 – 16859.
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assets. Enbridge relies on what it calls support from shippers transporting 70-75 percent of the volume of the crude oil on the Mainline. In reality, these supporters are a small minority of the Mainline’s stakeholders – which include Canadian producers, aggregators and refiners that may not always be shippers of record on the Canadian Mainline. In fact, the production from the opposing producers represents roughly 92% of the Mainline’s capacity.3 Enbridge has failed to reach a negotiated settlement with the vast majority of affected stakeholders and in the CSG’s view, did not genuinely seek to reach a broad-based settlement.
(c) The unique configuration of the Mainline, which delivers to dispersed refineries spread out along the Mainline, requires, for operational reasons, Downstream Verification (“DSV”). DSV is not required on other pipelines that deliver to liquid hubs. The DSV requirement, while necessary given the nature of the Mainline system, provides an advantage to parties who possess significant DSV capability because they are able to physically ship verified supply as they have an approved outlet to clear the supply. This particular ability is not available to a large portion of the WCSB market, particularly producing stakeholders, and therefore, in a constrained pipeline environment, puts such stakeholders at a significant disadvantage relative to parties with significant DSV capability. Enbridge’s Mainline contracting proposal, if approved, would solidify that disadvantage for 8-30 years,4 favouring those parties with significant DSV capability relative to those without.
(d) Mainline contracting would very likely increase the crude oil market bargaining power of parties who have significant DSV capability, which would be expected to result in lower prices for WCSB producers, and accordingly, lower royalties and tax revenues for Canadian governments. Put another way, the Application would place the scarcity value of the Mainline in the hands of market participants that have DSV capability, to the detriment of the Canadian public interest. Unlike the change to Enbridge’s SVP in 2018 that allocated capacity on the Mainline based on historical usage, and caused a dramatic decrease in prices (difference in price of $16/bbl5 between barrels at the inlet and barrels already injected), Mainline contracting cannot be reversed and any negative price impacts would be expected to continue for up to 20 years, and possibly 30 years under Enbridge’s proposed TSA extensions.
3 Transcript Vol. 17, PDF 123, para 17731.
4 The application proposes initial contract terms of 8 – 20 years’ duration, with possible extensions for further 10 year terms.
5 Transcript Vol. 16, PDF 114, para 16553.
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(e) Enbridge’s Application, if approved, is discriminatory. It will create two classes of shippers, committed and uncommitted, out of one class of shippers who are currently receiving the same service on existing capacity. The Commission should have regard to the U.S. Federal Energy Regulatory Commission (“FERC”) Colonial decision. The FERC denied an attempt to shift from common carriage to contract carriage precisely because, like the Application, no new capacity was offered. In the Colonial decision, FERC succinctly described Colonial’s proposal as creating two classes of shippers, committed and uncommitted, out of one class of shippers who were currently receiving the same service on existing capacity, as “unduly discriminatory”.6
(f) The western Canadian producing industry has been suffering from a lack of egress from the WCSB and a lack of access to liquid hubs that would provide transparent price discovery. The Application does nothing to address these fundamental issues: it does not provide any enhanced access to liquid hubs, access to new markets, or additional egress capacity. Instead, the Application is an attempt by Enbridge to monetize the significant value of scarce egress capacity by selling it to shippers with DSV capability that are willing to pay excessive tolls that are well above cost of service.
(g) If approved, Enbridge’s Mainline contracting proposal would force shippers with existing downstream pipeline commitments into a difficult position. If a shipper with downstream contracted capacity chose to participate in the open season, it would be faced with a no-win situation. If the shipper bids its downstream needs, and the open season is oversubscribed, as is expected, the shipper would be awarded much less than matching capacity on the Mainline and it would have a mismatch of capacity on the Mainline and the downstream pipeline for years to come.7 Alternatively the shipper can try to guess at the level of oversubscription that will occur in the open season and bid accordingly, but risks guessing incorrectly, and being stuck with that outcome for an 8 to 20-year contract.
(h) The likelihood of over-subscription and pro-rationing of capacity under Enbridge’s proposed Open Season risks impairing the ability of Mainline dependent, eastern Canadian refiners from securing sufficient volumes to support their existing operations, and risks locking in such deficiencies for up to 20 years, and possibly 30 years under TSA extensions.
(i) The Application does not provide a basis for the Commission to assess whether Enbridge’s proposed tolls are just and reasonable. It is not a
6 Colonial Pipeline Co., 146 FERC 61, 206 (2014), at 12.
7 The CSG notes that for some shippers, such as Shell Canada (Sarnia Refinery) or FCCL, there are no other comparable crude supply options available to mitigate this mismatching.
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negotiated settlement, it does not have broad support, it is not cost-based, and there is insufficient information on the public record for the Commission to understand the basis for the “negotiated package” or to assess its reasonableness. Further, Enbridge has not committed to how it will allocate international joint toll (“IJT”) revenues between Canada and the U.S. nor has it provided a cost breakdown of its proposed US$5.70/bbl base toll by jurisdiction. This prevents the Commission and other stakeholders from determining whether the Mainline revenues are appropriate and whether the Canadian Mainline toll is just and reasonable.
(j) Enbridge has indicated its wish to apply a residual methodology for allocating toll revenue to the Canadian Mainline (i.e. the Canadian Mainline would receive the residual amount after deduction of the Lakehead toll revenue from the proposed IJT), however this would mean that the Canadian Mainline toll would effectively be determined by U.S. law, precedent and business considerations, leaving the Commission unable to satisfy its statutory duty to set just and reasonable tolls. A more appropriate approach is to apply a straightforward methodology where, periodically and as required, the CER approves the Canadian Mainline toll and the FERC approves the Lakehead Toll, and the sum of the two is invoiced to shippers.
(k) Although Enbridge failed to provide rate base quality cost information sufficient to support a definitive cost of service determination, the Drazen and Brattle evidence demonstrates that the proposed tolls are in fact not just and reasonable. Their evidence indicates that the base toll exceeds a reasonable cost-of-service toll by well over US$1/bbl8 and would result in Enbridge over-earning at the expense of upstream producers (who receive netbacks based on the market price, minus the cost of transportation). The Application would result in an annual excess payment to Enbridge of over CDN$1.5 billion compared to cost-based tolls. This would compound the erosion of revenues for producers, with a commensurate reduction in royalties and tax payments to Canadian governments. The excessive, unjust, and unreasonable tolls proposed by Enbridge would be particularly harmful to the upstream industry at a time when producer cost competitiveness is imperative to effectively compete globally during the energy transition.
(l) The Application does not propose any new facilities or expansions, and it is not clear how future expansions on the Mainline would be tolled. The intent of the TSAs is to protect signatories from toll escalation from future expansions. Therefore, approval of the Application could result in the implementation of incremental tolling for potential Mainline expansion in the future, with the likely effect of disincentivizing such expansion, and thereby
8 Blackline Revised Written Evidence of Drazen Consulting, PDF 21, A28 (C12665-2) and Written Evidence of the Brattle group, PDF 18, A31 (C10215-3).
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contributing to the continued situation of constrained egress pipeline capacity out of western Canada.
7. In the CSG’s view, when deliberating on the Application, the Commission must have regard to the unique operational complexities and physical configuration of the Mainline and connected facilities. In particular, it is important to consider that, unlike other oil pipelines on which contracting has been approved, the Mainline delivers to a dispersed set of PADD II and eastern Canadian refineries but does not deliver to a liquid market. The need for DSV makes the Mainline unsuitable for contract carriage because it introduces unjustified discrimination. Parties without sufficient DSV would face the untenable choice of either missing out on the last available egress from the WCSB or signing up for significant long-term financial commitments that they may be prevented from using in the event a third party is unwilling to provide DSV.
8. Enbridge has argued that these long-term contracts will benefit shippers and producers, based on its unfounded assertion that common carriage tolls based on cost of service would be higher and subject shippers to toll escalation due to volume risk. In fact, the proposed contract terms and tolls are slanted in Enbridge’s favour (and are significantly higher than a cost of service based toll) and would serve to insulate Enbridge from volume risk at the expense of producers and other stakeholders.
9. Approval of the Application would effectively force non-supporting shippers to enter into long-term financial commitments for transportation service, which would unreasonably and unnecessarily expose them to significant financial costs and risks beyond their control, create a barrier to participation for many producers, dis- incentivize expansion, and deter investment in the Canadian petroleum industry. It is a particular concern that the length of the contracts means that there would be no real opportunity for any party, including the Commission, to react in a timely manner to correct any adverse or unexpected consequences.
10. The Enbridge’s Mainline contracting proposal would also impose costs on eastern Canadian refineries and refined product and NGLs shippers in the form of higher transportation costs, long-term financial liabilities, and sub-optimal operations due to the inability to predict or obtain optimal supply sources for many years. If approved, Mainline contracting would likely result in higher consumer prices for refined products, including gasoline, diesel, propane, and butane, in Canadian markets, most notably Manitoba, Saskatchewan, and a large part of Ontario, an outcome which is contrary to the Canadian public interest.
11. Enbridge has argued that a secondary market will address many of the concerns raised by the CSG and other stakeholders. Contrary to Enbridge’s assertions during the oral hearing in this Application, no such liquid secondary market for Canadian pipeline capacity currently exists and it is unlikely that one would evolve were Mainline contracting to be implemented. In the CSG’s view, a secondary market under Mainline contracting, if it were to develop, would not remedy the harm to the primary market and would instead enable those shippers that will hold
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and control large volumes of Mainline capacity, primarily PADD II refiners and integrated companies, to extract value for the scarce capacity they are likely to obtain.
12. When considering the balance of the Canadian public interest, the onus is on Enbridge to demonstrate that it would suffer considerable harm if it were not allowed to implement contract carriage. Enbridge has completely failed to make this case, and has not provided any market evidence to demonstrate that it faces a serious risk of offloading. In fact, the present reality is that the Mainline continues to be in apportionment as production has rebounded to pre-COVID levels.
13. In summary, given the potential harm to the Canadian upstream industry, the implications for Canadian government revenues, the potential harm to Canadian consumers from higher prices, and Enbridge’s complete failure to demonstrate that it is at risk of material financial harm, Enbridge’s Application is clearly not in the Canadian public interest. The Commission should deny the Application and direct Enbridge to file an application by January 31, 2022 for Mainline tolls calculated on a cost-of-service basis under continued 100% common carrier service, which tolls shall take effect from July 1, 2021.
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III. BACKGROUND
14. On August 2, 2019, Enbridge announced the commencement of an open season process for firm capacity on the Mainline (the “2019 Open Season”), which was scheduled to conclude on October 2, 2019. In the 2019 Open Season, Enbridge proposed to implement a new tolling and contracting framework for the Mainline following the expiry of the Competitive Toll Settlement (“CTS”). The proposal would replace common carrier service for 90% of the Mainline’s capacity for up to 30 years leaving 10% for uncommitted capacity following the expiration of the CTS. Through Enbridge’s short-lived 2019 Open Season process, it sought to solicit sufficient support from interested parties so that it could present the proposal to the Commission for approval.
15. Between August 23 and 26, 2019, Suncor Energy Inc. (“Suncor”), Shell Canada, the Explorers and Producers Association of Canada (“EPAC”), and Canadian Natural submitted complaints to the National Energy Board (“NEB” or “Board”) regarding the 2019 Open Season (the “Complaints”). On August 27, 2019, the NEB initiated a comment process on the Complaints (the “Complaint Proceeding”) and the CER issued a decision on September 27, 2019, ordering that Enbridge could not offer firm service to prospective shippers on the Mainline until such firm service, including all associated tolls and terms and conditions of service, had been approved by the Commission.9 The Commission also stated that the effect of the order was that Enbridge could not continue the 2019 Open Season.
16. At that time, the Commission recognized the specific and unique circumstances that contribute to Enbridge’s market power with respect to the Mainline, noting the following:
1. Enbridge’s control of over 70% of oil transportation capacity out of the Western Canadian Sedimentary Basin, via pipeline or rail;
2. The lack of alternative transportation options for potential shippers (all other Canadian crude oil export pipelines are contracted and/or fully utilized, and rail is more expensive, involves long lead times in arranging transportation, and moves only a small portion of total western Canadian crude oil production);
3. The impact that proposed Mainline firm service would have on aggregate uncommitted oil pipeline capacity from western Canada (aggregate uncommitted oil pipeline capacity would be reduced from approximately 80% to 15% of total oil pipeline capacity);
4. The fact that Enbridge’s proposed firm service offering only involves existing, rather than new, pipeline capacity; and
9 CER Letter Decision, Complaints regarding Enbridge Mainline Open Season, September 27, 2019 (C01893-1).
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5. The considerable opposition to Enbridge’s current open season.
These specific and unique circumstances, when considered together, put Enbridge in a dominant position in the market. As a result, the Commission has concerns regarding the fairness of Enbridge’s open season process 10 and the perception of abuse of Enbridge’s market power.
17. On December 19, 2019, Enbridge filed the Application.11 Notwithstanding the concerns raised by the Commission, Canadian producers, and other stakeholders regarding the proposed switch to firm service, Enbridge did not modify its Mainline contracting proposal. In fact, Enbridge’s proposed terms and conditions of service, as reflected in the pro-forma transportation service agreements (“TSAs”), and proposed tolls are essentially identical to those presented to shippers and stakeholders during the 2019 Open Season that elicited the Complaints.12
18. In short, Enbridge made absolutely no changes to address any of the numerous concerns raised by Canadian producers and by the Commission prior to filing its Application.13
IV. LEGISLATIVE FRAMEWORK
19. Part 3, sections 225 through 239 of the Canadian Energy Regulator Act14 (“CER Act”) govern applications for pipeline tolls and tariffs. The following are the key provisions of the CER Act applicable to this proceeding:
(a) Section 226, which authorizes the Commission to make orders with respect to all matters relating to traffic, tolls or tariffs;
(b) Section 229(b), which prohibits a company from charging a toll unless approved by an order of the Commission;
(c) Section 230, which requires that tolls must be just and reasonable, and must always, under substantially similar circumstances and conditions with respect to all traffic of the same description carried over the same route, be charged equally to all persons at the same rate;
10 CER Letter Decision, Complaints regarding Enbridge Mainline Open Season, September 27, 2019, PDF 2 (C01893-1).
11 Enbridge Pipelines Inc., Canadian Mainline Contracting Application (C03823-2) [MLC Application or Application].
12 Written Evidence of the Canadian Shippers Group, PDF 102, paras 314-315 (C10237-2).
13 Written Evidence of the Canadian Shippers Group, PDF 102, paras 316, (C10237-2).
14 Canadian Energy Regulator Act, SC 2019, c 28, s 10 [CER Act].
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(d) Sections 235 and 236, which prohibit unjust discrimination in tolls, services and facilities and establish the burden of the company imposing any discrimination to demonstrate that their discrimination is justified;
(e) Section 231, which authorizes the Commission to determine whether a company has complied with the requirements in sections 230 and 235 of the CER Act;
(f) Section 233, which provides the Commission with discretion to disallow tariffs that are contrary to the CER Act or to a Commission Order, and to substitute a suitable tariff for the one proposed by the company; and
(g) Section 239(1) which sets out oil pipeline operator’s common carrier obligations to receive, transport and deliver all oil offered for transmission by means of its pipeline.
20. The Commission must assess a proposed service and tolling framework by considering:
(a) whether the tolls are just and reasonable, will be charged equally to all persons under substantially similar circumstances and conditions, and will not result in any unjust discrimination; and,
(b) in the case of an oil pipeline, whether the pipeline would receive, transport, and deliver all oil offered to it for transmission in accordance with a pipeline’s common carrier obligations.
21. Enbridge also seeks an Order of the Commission approving its proposed tolling framework and tolling methodologies and continuing its exemption from the system of accounts requirements under the OPUAR. Section 389(2) of the CER Act allows the CER to, by order, exempt a company from the application of regulations respecting account, on any condition the CER considers appropriate. Previously, the NEB has granted exemptions for sections of the OPUAR based on the Board’s discretion on whether the requested exemption is reasonable in the circumstances.15 The Commission and its predecessor have typically granted OPUAR exemptions in cases where there were no third-party shippers who might benefit from audited financial statements.16 Given Enbridge’s ongoing reluctance to provide basic financial and cost information to shippers and stakeholders as part of Mainline negotiations and this proceeding, the CSG is of the view that it would be unreasonable for the Commission to grant Enbridge’s requested exemption in this case.
15 See e.g. CER Letter and Order MO-030-2019 to Trans Quebec and Maritimes Pipeline Inc., 29 October 2020 (C09218).
16 See e.g. NEB Letter Decision, Plains Midstream Canada ULC – Exemption from OPUAR requirement to file Audited Financial Statements for the Kerrobert Pipeline, 14 May 2013 (A3H6T5).
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22. Although Enbridge is silent in its Application with respect to financial reporting, Enbridge has stated under cross examination that it does not intend to comply with the CER’s full Guide BB requirements.17 Given that the Application is not a negotiated settlement, is widely opposed, and that Enbridge continues to resist sharing basic information necessary for cost assessment, the CSG is of the view that it would be unreasonable for the Commission to allow Enbridge any exemptions from the full Guide BB reporting requirements.
Canadian Public Interest
23. Additionally, the Commission must decide whether Enbridge’s Application is in the Canadian public interest. Section 32(c) of the CER Act sets out the Commission’s overarching jurisdiction to inquire into, hear, and determine any matter if the Commission considers that the circumstances may require the Commission, in the public interest, to make any order or give any direction, leave, sanction or approval that it is authorized to make or give.
24. Broadly, the CER defines the public interest as “inclusive of all Canadians and refer[s] to a balance of economic, environmental, and social interests that changes as society’s values and preferences evolve over time.”18
25. The Commission has wide discretion to determine the relevant public interest factors depending on the specific circumstances of the case before it.19
26. In assessing the Canadian public interest in regard to the Application, the preponderance of weight should be given to the provinces as owners of the resources being exploited and to businesses which lease those resources and invest in oil exploration, development, and production, sometimes termed “the upstream industry.”20
17 See Transcript Vol. 10, PDF 91, paras 9829 - 9830.
18 NEB Reasons for Decision OH-3-2007, Enbridge Southern Lights GP – Application for the Southern Lights Project (February 2008) at 5; NEB Reasons for Decision OH-3-2011, Vantage Pipeline Canada ULC – Application for the Vantage Pipeline Project (1 January 2012) at 5; NEB Reasons for Decision OH-01-2011, Enbridge Bakken Pipeline Company Inc. – Application for the Bakken Pipeline Project Canada, (December 2011) at 7.
19 NEB Reasons for Decision MH-1-2006, TransCanada PipeLines Limited and TransCanada Keystone Pipeline GP Ltd – Application for leave to transfer pipeline facilities and for a determination of the transfer price (February 2007) at 8-9, 16; NEB Reasons for Decision OH-1-2007, TransCanada Keystone Pipeline GP Ltd – Section 52 Application for the Keystone Pipeline Project (September 2007) at 55.
20 Written Evidence of Mr. Roland Priddle, PDF 30 – 31, A27 & 28 (C10237-5). See also Written Evidence of the Canadian Shippers Group, PDF 10 - 12 (C10237-2) summarizing the importance of the oil producing industry to Canada’s national economic wellbeing in relation to export revenues, investment, and the industry’s contribution to the national economy.
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27. The upstream oil sector is an enormous contributor to Canada’s economic well- being.21 The sector is the largest contributor to real Canadian exports, has led the nation in investment for many years, and contributes billions annually to both provincial and federal governments in taxes and royalties. In addition, the sector purchases billions of dollars in inputs from across the country annually and supports employment nation-wide.
28. In addition, the historical context in which the Mainline was established, constructed, operated, and regulated is relevant to the Commission’s consideration of the Canadian public interest in respect of the Application. This historical context demonstrates the fundamental public interest role the Mainline has played in supporting the efficient and responsible development of Canada’s natural resources by the upstream sector, and the wealth of benefits that has generated for all Canadians.
29. The key role of the upstream industry has been reflected in regulatory decisions and in negotiated settlements relating to IPL and Enbridge over a period of some 45 years. The purpose of the Interprovincial Pipe Line Company (“IPL”), now the Enbridge Mainline, as stated in its first annual report (1949), is “to provide an outlet for the extensive crude oil reserves discovered in the Province of Alberta.”22 This echoed the debate on the special act of the Parliament of Canada (1949) to create IPL, where it was asserted that “oil lines in particular are absolutely essential to the development of our industry in Alberta.”23 In this context, the Joint Review Panel in OH-4-2011 agreed with Enbridge Northern Gateway that the “petroleum industry [clearly meaning the upstream industry] is a significant driver of the Canadian economy and an important contributor to the Canadian standard of living.” The Panel also expressed the view that it is in the Canadian public interest to maximize prices received for western Canadian crude oil.24
30. During the “settlements era” 1995-2021, the preponderance of the producer interest was reflected in the fact that in the Mainline negotiations of 1995, 2000, 2005, 2010 and the 2011 Incentive Toll Settlement, the sole counterparty was the Canadian Association of Petroleum Producers (“CAPP”), the voice of Canada’s upstream oil and gas industry.25
21 As detailed in the Written Evidence of the Canadian Shippers Group, Chapter III, PDF 10-12 (C10237- 2).
22 Written Evidence of Mr. Roland Priddle, PDF 15 - 16, A12 (C10237-5).
23 Written Evidence of Mr. Roland Priddle, PDF 10 - 13, A9 (C10237-5).
24 CSG Response to Enbridge IR 1.75(d), PDF 131 (C11771-2).
25 Written Evidence of Mr. Roland Priddle, A19, A28 and A29, PDF 22 – 23 and 31 - 32 (C10237-5).
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31. The Enbridge Board of Directors and the CAPP Board of Governors approved the principles that were reflected in and comprised the 2011 Competitive Toll Settlement which has just expired.26
32. To conclude, in its assessment of whether the Application is in the Canadian public interest, the Commission should give preponderant weight to the interests of the producing provinces and the Canadian oil producing industry. This will achieve the balance of economic interest of all Canadians which the Commission considers in its definition of the public interest.
33. Conversely, there is minimal Canadian public interest in sustaining or enhancing the commercial interests per se of United States refiners who comprise the majority of the parties27 seeking firm service and are prepared to accept the new tolling framework for the Canadian Mainline.28 This said, it is acknowledged that United States refiners have been and are an important market for Canadian crude oil.29 However, as noted in the oral testimony of various supporting shippers, these refiners will neither cease to operate nor cease to rely on WCSB/Mainline sourced crude if the application is denied.30
Just and Reasonable Tolls
34. The Commission has broad discretion to determine whether tolls are just and reasonable and is not bound to follow any particular methodology.31 Nonetheless, the Commission and its predecessor have articulated principles that guide the
26 Enbridge Pipelines Inc. Competitive Toll Settlement Application, PDF 12 (A1Y9R6).
27 Application, Appendix 4, Shipper Support Letters (C03823-6).
28 Application, PDF 7, para 3 (C03823-2).
29 Written Evidence of Mr. Roland Priddle, A30, PDF 32 – 33 (C10237-5).
30 Several supporting shippers stated in the oral hearing that their long-term economic viability is not at risk without firm service. See Transcript Vol. 14, PDF 30, paras 12982 – 12983 (United Refining Company); Transcript Vol. 14, PDF 138, paras 14170 – 14171 (Cenovus Energy Inc.); Transcript Vol. 15, PDF 76 - 77, paras 15053 – 15054 (BP Products North America Inc.); Transcript Vol. 15, PDF 106, paras 15363 – 15364 (Motiva Enterprises LLC); Transcript Vol. 16, PDF 86, paras 16287 – 16288 (Imperial Oil Limited).
31 British Columbia Hydro & Power Authority v Westcoast Transmission Co, [1981] 2 FC 646 (FCA) at paras 17 and 52; NEB Reasons for Decision RH-1-2007 - TransCanada PipeLines Limited (July 2007) at 21; CER Letter Decision RH-002-2020 - Campus Energy Partners Suffield LP (7 April 2021) at 6 – 7; Trans Mountain Pipeline Company Ltd v National Energy Board, [1979] 2 FC 118 (FCA); TransCanada Pipelines Limited v National Energy Board, 2004 FCA 149.
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determination of just and reasonable tolls, including the cost-based/user-pay principle.32
35. The Commission has stated that it will not depart from the cost-based/user-pay principle to favour a more economically efficient outcome absent strong reasons33 and, in any event, there is no credible evidence in this proceeding that Mainline contracting would result in improved economic efficiency. To the contrary, approval of the Application would result in various and significant inefficient economic outcomes, given the expected negative impacts on Canada’s upstream and refined products industries.
No Unjust Discrimination
36. The Commission similarly has broad discretion to determine the presence or absence of unjust discrimination.34 The principles relevant to assessing whether tolls are just and reasonable tolls are also relevant to determining whether the proposal would result in unjust discrimination in tolls, service or facilities.35
37. Generally, the Commission and its predecessor’s practice has been to consider whether similarly situated parties are treated equally.36 If a company discriminates, it bears the burden of showing the discrimination is justified.37 To determine whether differential treatment is justified, the Commission considers whether such treatment is reasonable in the circumstances.38
32 See CER Letter Decision RH-002-2020 - Campus Energy Partners Suffield LP (7 April 2021) at 7; Reasons for Decision RH-1-2007 - TransCanada PipeLines Limited (July 2007) at 21 - 23.
33 Reasons for Decision RH-1-2007 - TransCanada PipeLines Limited (July 2007) at 22 citing NEB Reasons for Decision RH-2-91 – Interprovincial Pipe Line Inc. (June 1992) at 68.
34 See NEB Reasons for Decision MH-4-96 - PanCanadian Petroleum Limited (February 1997) at 12.
35 See NEB Reasons for Decision RH-001-2016 - TransCanada Pipelines Limited (March 2016) at 32 – 33.
36 See CER Reasons for Decision RH-001-2019 - NOVA Gas Transmission Ltd. (March 2020) at 3; NEB Reasons for Decision RH-001-2016 TransCanada Pipelines Limited (March 2016) at 1 and 33; CER Reasons for Decision RH-002-2019 - NOVA Gas Transportation Tariff Amendments (13 November 2019) at 5.
37 CER Act, s 236. See also NEB Reasons for Decision - MH-4-96 PanCanadian Petroleum Limited (February 1997) at 12 relied on in various NEB and Commission decisions, e.g.CER Letter Decision with Reasons C12183-1 - EPAC Extension of NGTL TSA Tariff Provision (30 March 2021) at 8; CER Reasons for Decision RH-001-2019 - NOVA Gas Transmission Ltd. (March 2020) at 3.
38 See e.g. CER Reasons for Decision RH-002-2019 - NOVA Gas Transportation Tariff Amendments (13 November 2019) at 6, stating “in this case, it is reasonable to distinguish between receipt and delivery services during curtailments as receipt and delivery services are predominantly situated in different locations of the NGTL system and are impacted differently by constraints on the system.” [emphasis added]
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Burden of Proof
38. As the applicant in this case, Enbridge bears the burden of demonstrating, on a balance of probabilities, that the Application should be granted.39 The NEB has stated clearly that when determining whether an applicant has discharged its burden of proof, the regulator considers the totality and weight of the evidence before it.40 An application will be denied where the applicant does not provide sufficient information and analysis for the regulator to make an informed decision.41
39. In this case, for the Commission to approve the Application, Enbridge must demonstrate, on a balance of probabilities, that:
(a) the proposed tolls under Mainline Contracting are just and reasonable and not unjustly discriminatory;
(b) its request to convert 90% of Mainline capacity to contract carriage, in the absence of providing any new market access or ex-WCSB egress capacity, is consistent with its common carrier obligations;
(c) Enbridge’s proposal does not reflect the actual or perceived abuse by Enbridge of its dominant position in the market;
(d) the proposed terms and conditions of service do not unjustly discriminate in favour of one shipper class over another;
(e) Enbridge’s Mainline contracting proposal is otherwise in the public interest; and
(f) A continued exemption from the OPUAR system of account requirements is reasonable in the circumstances.
40. As set out in this written argument, the CSG submits that Enbridge has failed to satisfy its burden and, as a result, the Application must be denied.
39 NEB Reasons for Decision GH-2-87 TransCanada PipeLines Limited– Applications for Facilities and Approval of toll Methodology and Related Tariff Matters (July 1988) at 80-81 (An applicant has the burden of establishing on the balance of probability that the relief sought in its application should be granted).
40 NEB Reasons for Decision RH-R-2-2005 - Coral Energy Canada Inc. and the Cogenerators Alliance (May 2005) at 11.
41 NEB Decision and Order XG-T211-008-2012, TransCanada PipeLines Limited – Application pursuant to section 58 of the National Energy Board Act and subsection 45.1(1) of the Onshore Pipeline Regulations, 1999 for the 2012 Eastern Mainline Expansion (May 2012) at 6.
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V. CONSULTATION AND NEGOTIATIONS WERE NEITHER FAIR, OPEN NOR TRANSPARENT, AND THE DEGREE OF OPPOSITION IS UNPRECEDENTED
Proposed “Negotiated” Tolls Did Not Result from a Fair and Transparent Negotiation Process
41. The “default” mode of financial regulation of Group 1 pipelines is based on the fundamental principle that just and reasonable tolls are those that allow the owner of the pipeline a reasonable opportunity to recover its prudent costs of providing pipeline transportation service, including a fair return on its investment. Regulated pipeline owners, such as Enbridge, are not allowed to unilaterally set their own rates because of the potential for pipelines, which are typically natural monopolies, to abuse their market power.
42. Enbridge states that the proposed tolls and tariffs were “negotiated.” However, these so-called negotiations were not conducted pursuant to the NEB’s Guidelines for Negotiated Settlements (the “Guidelines”). There is no mention of the Guidelines in either of the Application or Mr. Reed’s report.42 Enbridge acknowledges that it failed to reach a “Negotiated Settlement” with the interested parties.43 In any event, there is no reasonable basis on which the Commission can conclude that Enbridge’s Mainline contracting proposal and “negotiated” tolls were the result of fair, open, and transparent negotiations, and not the result of Enbridge’s exercise of market power.
43. The Guidelines and the established principles of the Commission and its predecessor require that a negotiation process “be open and all interested parties should be invited to participate in the settlement negotiation”, and that the process “should be clearly understood and agreed upon by all interested parties”.44 While historically the NEB has encouraged “Negotiated Settlements” between a regulated pipeline owner and its customers, such proposals must comply with the principles articulated in the Guidelines.
44. Consistent with the principles set out in the Guidelines, in a 2014 letter decision regarding the TransCanada PipeLines Limited application for approval of a 2013 to 2030 settlement agreement45 the Board set out several criteria necessary to
42 Application (C03823-2); Evidence of John Reed (C03823-7).
43 See Additional Directed Information from Enbridge, Guide P - Tolls and Tariffs P.1 Cost of Service, PDF 3 (C08319-31): “Enbridge has not presented its Application as a negotiated settlement under the settlement guidelines.”
44 NEB Revised Guidelines for Negotiated Settlements of Traffic Tolls and Tariffs, PDF 4 (C13339-2) [Guidelines].
45 NEB Letter – Results of Comment Period (31 March 2014) (A3V5J6). (Application denied by the NEB).
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support a fair and open settlement process that could be accepted by the Board, stating as follows:
The Board’s Settlement Guidelines set out several criteria that should be satisfied for a settlement to be acceptable. The Board relies on an open and fair settlement process where a full range of interested parties are involved to result in a settlement that reflects the public interest. The Board uses the open settlement process to help in its assessment that the resulting agreement tolls are just and reasonable and not unjustly discriminatory.
Negotiated settlements are a give and take process where one party will give up something to gain something else. In assessing whether an applicant has justified the approval of a contested settlement, the Board will consider among other things, whether there is sufficient support for the settlement, based on the comments submitted by interested parties.
The settlement process must produce adequate information on the public record for the Board to understand the basis for the agreement, assess its reasonableness, and to be able to determine that the resulting tolls are 46 just and reasonable and not unjustly discriminatory.
45. For the past 25 years, the tolls on the Canadian Mainline have been determined by negotiated tolling settlements, which enjoyed broad support by all stakeholders, including the upstream oil-producing sector.47 Generally, tolls under these incentive settlements were initially based on cost-of-service principles established by the NEB in regulatory proceedings.48 It follows that a key element of meaningful negotiations is for a pipeline to provide transparent cost information so that negotiating counterparties are able to independently assess the justness and reasonableness of negotiated tolls. Enbridge’s steadfast refusal to share essential cost information with stakeholders during the course of negotiations made it impossible for counterparties to meaningfully consider whether the tolls Enbridge is proposing are just and reasonable.49
46. What Enbridge describes as a “negotiated package” is simply a bargain reached between the pipeline company and a relatively small group of primarily US based refiners and integrated companies who, due to the nature and location of their operations and facilities, are favourably situated to benefit from controlling scarce Mainline capacity under long-term contracting, given their DSV capabilities.50 The reality is, many supporters are sole sourced refiners and will ship on the Mainline
46 NEB Letter – Results of Comment Period (31 March 2014), PDF 2 - 3 (A3V5J6).
47 Written Evidence of Mr. Roland Priddle, A7, PDF 7 (C10237-5).
48 Written Evidence of Mr. Roland Priddle, A7, PDF 7 (C10237-5).
49 See Transcript Vol. 20, PDF 28 – 29, paras 19842 – 19848; Transcript Vol. 19, PDF 101-102, paras 19634– 19640.
50 Transcript Vol. 1, PDF 57, paras 569 and PDF 64, paras 644 - 646.
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with or without Mainline contracting. What Mainline contracting provides supporters, however, is the opportunity to solidify capacity on a heavily apportioned pipeline and increase their bargaining power, which will translate into lower crude prices at the inlet of the Canadian Mainline. As supporters have indicated, a main driver for supporting Mainline Contracting is to reduce feedstock costs.51 While in its Written Final Argument Enbridge variously refers to the desire of supporting shippers for “certainty of access”, “certainty of capacity”, and “certainty of tolling”52 it is clear that these terms are being used as a proxy for what supporting shippers truly desire, namely certainty of long-term access to heavily discounted crude from the WCSB, as discussed further in section VII(A)(ii) below.
47. On the other hand, the Application is the subject of unprecedented opposition from a broad spectrum of Canadian oil producers, refiners, and other stakeholders who reject the imposition of unjust and unreasonable tolls and terms and conditions of service and who reject the proposed contracting terms on the basis that they unjustly favour a certain class of shippers. For Canadian refiners with no other supply option available, Mainline contracting will significantly change their competitiveness and undoubtedly increase product prices for Canadian consumers.
48. Key prerequisites outlined in the Guidelines and discussed in the Board’s 2014 Letter were wholly absent from the negotiation process. Enbridge’s reliance on Mr. Reed’s evidence that the negotiation produced tolls and terms and conditions of service that are just and reasonable and not unjustly discriminatory is untenable. In particular:
(a) The process was not open and fair and did not address the needs and concerns of a full range of interested parties because Enbridge focused its attention on US based refiners who were amenable to long-term contracting.53
(b) There was no real “give and take” in the process. Enbridge was focused on converting the Mainline to contract service from the outset and, as Enbridge itself acknowledges, the critical base toll amount of US$5.70/bbl did not effectively change throughout the discussions.54 Enbridge puts forward the
51 See Transcript Vol. 14, PDF 91, paras 13683 - 13686.
52 See for e.g. Enbridge Written Final Argument, PDF 12 - 13, 74 and 78 - 79, paras 27, 29, 223, 235 (C13899-2).
53 Transcript Vol. 7, PDF 30, paras 6585-6588.
54 Application, Appendix 18 – Summary of Changes to Mainline Contracting, PDF 2 (C03823-20); Transcript Vol. 11, PDF 16 - 17, paras 10115 - 10130.
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volume discounts as evidence of give and take on tolling negotiations.55 However, Enbridge’s testimony omits that the roughly US$5.70/bbl CTS exit toll was linked to an expected throughput of about 2.8 million bpd. At the expected post-Line 3 throughput of approximately 3 million bpd, the Line 3 IRS56 included a toll ratchet system with similar discounts to all shippers. Hence Enbridge’s current proposal is simply reflecting discounts that had been previously negotiated, and restricting them to contract holders under Mainline contracting.
(c) There is insufficient support for a settlement. Enbridge’s Summary of Stakeholders Involved in Negotiations57 (the “Support Summary”) shows that only 13 (14 subsequent to filing the Application) of approximately 125, or roughly 10%, of the stakeholders Enbridge engaged with provided a letter indicating that if the Application were to be approved, those parties would participate in the Open Season.
49. Despite offering no new capacity or market access, Enbridge asserts that the Application is similar to previous tolling applications for negotiated tolls not filed under the Guidelines. For instance, Enbridge seeks to rely on the NEB’s decisions regarding the Keystone XL Project (Reasons for Decision OH-1-2009) and TMEP (Reasons for Decisions RH-001-2012) to argue that it is reasonable in this case for Enbridge’s Application for “negotiated” tolls to not be filed under the Guidelines. However, in both of those decisions, the applicants were still required to demonstrate that the negotiation process was fair and transparent, and free from abuse of a dominant market position. Notably, both those applications for negotiated tolls reflected agreed-to sharing of capital cost overruns and flow through cost items.
50. In RH-001-2012, the Board found the negotiations and outcome were reasonable for three reasons:
(a) The large majority of parties supported the process and the resulting toll methodology (11 out of 13);58
(b) Any concern that Trans Mountain was exercising market power was mitigated by considerable choice and competition in the market (Northern
55 See Transcript Vol. 7, PDF 32, para 6607: “MR. HEINZ: And Mr. Langen, it’s Brent Heinz here. I would also note that in exchange for those longer terms shippers negotiated with Enbridge, Enbridge conceded to additional discounts associated with that, so there was give and take.”
56 See IRS# 2013-02-A (Canada) (Line 3 IRS Canada), PDF 4 (C13168-12).
57 Enbridge Response to CER IR 4.5, Attachment - Summary of Stakeholders Involved in Negotiations (C08985-6).
58 Reasons for Decision RH-001-2012, PDF 13 and 40 (C13524-23).
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Gateway, KXL, and Energy East were all competing to attract contracts from producers);59 and
(c) The overall application was for expanded capacity to a new market.60
51. The OH-1-2009 decision was grounded in the fact that the Keystone XL application included “[t]he opening of new markets for Canadian crude oil [that] would alleviate economic risk”.61 Contract carriage in that case also underpinned new facilities (the Keystone XL pipeline),62 and the application faced “no opposition…by petroleum producers…or by governments of producing…provinces.”63
52. This is in stark contrast to the current application in which we see:
(a) extensive opposition to the Application from producers and other Canadian- based stakeholders, as well as from the Government of Saskatchewan;
(b) little competition since KXL has been cancelled and the Mainline retains its dominant market position;
(c) no expanded capacity;
(d) no new facilities;
(e) no new market access; and
(f) the Application’s numerous negative impacts on Canadian-based interests.
53. In its NEB Decision RH-2-2011 regarding Trans Mountain’s application for firm service to the Westridge Marine Terminal, the Board found that Trans Mountain had provided a fair and equal opportunity for participation in different phases of the Open Season. In coming to this determination, the Board considered the extensive group and one-on-one discussions that all interested parties had the opportunity to participate in prior to commencement of the Open Season. The parties were able to make decisions based on their own economic judgement, and no party in
59 Reasons for Decision RH-001-2012, PDF 13 and 30 (C13524-23).
60 See Transcript Vol. 18, PDF 14, paras 17945 – 17946; Written Evidence of Mr. Roland Priddle, PDF 57 (C10237-5).
61 NEB Reasons for Decision OH-1-2009 – TransCanada Keystone Pipeline GP Ltd. at 17; Written Evidence of Mr. Roland Priddle, PDF 56 (C10237-5).
62 NEB Reasons for Decision OH-1-2009 – TransCanada Keystone Pipeline GP Ltd. at 12; Written Evidence of Mr. Roland Priddle, PDF 56 (C10237-5).
63 NEB Reasons for Decision OH-1-2009 – TransCanada Keystone Pipeline GP Ltd. at 54; Written Evidence of Mr. Roland Priddle, PDF 56 (C10237-5).
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the proceeding disputed the validity of the procedural aspects of the Open Season.64
54. In contrast, Enbridge’s negotiation process has been unfair and opaque.
55. The CSG has detailed the lack of meaningful consultation and lack of negotiation that was undertaken by Enbridge with Canadian producers and certain Canadian refiners prior to holding discussions with its broader shipper base.65
56. It is uncontested that Enbridge has not presented a negotiated settlement that conforms to the Guidelines. More importantly, Enbridge has failed to conduct negotiations with stakeholders in a manner consistent with the principles articulated by the Commission and its predecessor in respect of fair, open, and transparent negotiations. A negotiated settlement needs to consider all stakeholders, not merely a subset willing to make financial commitments for existing egress and sufficient DSV capability to ensure access to the capacity they contract for. In the absence of a negotiated agreement supported by a broad range of stakeholders (including Canadian producers and Mainline-beholden Canadian refiners with limited DSV capability), the CSG submits that post-CTS tolls for the Canadian Mainline must be determined on a cost-of-service basis.
Bilateral Negotiations Were Unreasonable and Unfair in the Circumstances
57. Transparency and access to economic and operational information are necessary to facilitate fair and transparent negotiations. Absent these conditions, shippers and other parties are placed at a significant disadvantage and must expend considerable cost, time, and resources to obtain the necessary information controlled by Enbridge.
58. In the fall of 2017, Enbridge negotiated on a limited bilateral basis what became the foundational terms of its Mainline contracting offering with a core group of only seven shippers.66 Following those discussions, Enbridge presented a term sheet and draft TSAs to the balance of prospective shippers. Those initial terms, as now reflected in the Application, represents a negotiated outcome that only considered the interests of the initial core group of seven supporting shippers and Enbridge.
59. At the same time, Enbridge refused to allow its 2021 Negotiating Team to negotiate a new settlement or discuss alternatives to contract carriage. Instead, the 2021 Negotiating Team was limited only to negotiating the spot toll for the 10% of
64 NEB Reasons for Decision RH-2-2011 – Trans Mountain Pipeline ULC on behalf of Trans Mountain Pipeline LP at 26.
65 Written Evidence of the Canadian Shippers Group, PDF 102 - 103, paras 317 - 321 (C10237-2). See also Transcript Vol. 7, PDF 91, paras 7259 – 7264.
66 Enbridge Revised Response to Valero IR No. 2 (C09948-6).
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capacity reserved for uncommitted service that would be applicable under its Mainline contracting proposal.
60. What Enbridge characterizes as a negotiated toll and service offering is in fact an arrangement reached between Enbridge and a limited group of primarily US refiners and integrated companies who are similarly situated and whose interests are focused more on securing low-cost (price-advantaged) and consistent crude oil supply than on toll levels.67 The negotiation process catered to the interests of this subset of the market to the detriment of other market participants and stakeholders with interests in the Mainline.
61. Although Enbridge maintains that it continued to negotiate with existing and potential shippers from 2018 to 2019, making modifications to the terms of its contract offering, as is evident from an examination of the blacklined TSAs provided by Enbridge, only minor changes were made during that time frame. Particularly illustrative of the lack of true negotiation is the fact that the declared base toll of $5.70 did not effectively change throughout discussions. 68
62. In fact, Enbridge presented to the balance of its shippers the fundamental arrangement it had already negotiated with its core shippers but failed to “negotiate” with the other shippers in any real commercial sense of the term. It was clear that the foundational terms of the proposed TSA had already been determined through its initial discussions with the core group.69 Even existing Mainline shippers with downstream contract commitments were treated differently during the negotiation, whereby Enbridge offered renewal opportunities to only some of the shippers with contractual commitments on downstream pipelines.70 Notably, the proposed spot toll increased over the same period.71
63. Enbridge repeatedly asserts that the interests of shippers of record should be given greater weight than the interests of other stakeholders. There is no merit to this assertion. The evidence in this proceeding establishes the historical and operational reasons why it is predominantly shippers with DSV who become shippers of record. Enbridge acknowledges that this “commercial dynamic is long standing and efficient as it allows refiners to effectively manage their crude oil
67 See Enbridge Day Presentation – Liquid Pipelines, PDF 4, slide 8 (C13116-7 ): “Our core Mid-west and USGC markets generates the strongest refinery margins globally”; Transcript Vol 13, PDF 94 - 95, paras 12591 – 12597.
68 Application, Appendix 18 - Summary of Changes to Mainline Contract Offering (C03823-20). The CSG notes that Mr. Varsanyi did not admit this fact in cross examination by Mr. Yates (See Transcript Vol. 11, PDF 17). However, the fact is evident from a review of Appendix 18.
69 Transcript Vol. 7, PDF 29, paras 6574 - 6583.
70 Transcript Vol. 7, PDF 63 – 64, paras 6951 - 6964.
71 Transcript Vol. 7, PDF 63 – 64, paras 6951 - 6964.
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requirements and the timing of crude oil deliveries off the Enbridge Mainline system.”72 The fact producers and others have not challenged this commercial dynamic does not constitute a waiver of their interests as fundamental stakeholders on the regulated Mainline. It is therefore irrelevant for the purpose of the Commission’s decision on the Application whether a stakeholder is a shipper of record or not. What is relevant, is the impact of the Application on all stakeholders.
64. The NEB has previously denied an application in which the pipeline operator focused on one group of large shippers resulting in the marginalization of other shippers. In its RH-001-2014 decision, the Board stated:
In this instance, the Board finds that the process used is insufficient to allow the Board to approve the Settlement as a contested settlement. The agreement negotiations included only TransCanada and its three biggest shippers, with other shippers being minimally involved after the agreement 73 was nearly final.
65. In this case, Enbridge ignored those parties who raised concerns about the lack of fairness in its process. Enbridge was steadfast in carrying out its skewed negotiation process despite feedback from the CSG members and numerous other stakeholders.74
66. Enbridge has stated that its Mainline contracting proposal was developed through bilateral negotiations between Enbridge and its stakeholders, wherein ‘stakeholders’ included parties that shipped on the Mainline.75 However, the actual identity of all stakeholders with whom Enbridge negotiated remains unclear.76
67. Enbridge has stated that it provided shippers with all necessary information as part of its negotiations. However, CAPP confirmed that requests for additional information were not provided77 and shippers, including members of the CSG, were not provided with the basic cost information required to assess the reasonableness of Enbridge’s proposed tolls.78
72 Application, PDF 14, para 22 (C03823-2).
73 NEB Reasons for Decision RH-001-2014 - TransCanada PipeLines Limited 2015 – 2030 Tolls and Tariffs, Appendix IV - Letter dated 31 March 2014 at 98.
74 Written Evidence of the Canadian Shippers Group, PDF 100, paras 305 - 306 (C10237-2).
75 Enbridge Reply Evidence, PDF 7, para 8 (C12447-2).
76 Transcript Vol. 5, PDF 93, paras 5439-5450.
77 C10212-1 – CAPP Letter of Comment to CER, PDF 2 (C13212-13).
78 Written Evidence of the Canadian Shippers Group, PDF 100, para 304 (C10237-2).
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68. Enbridge has also asserted that information regarding the content of its bilateral negotiations is confidential,79 including the logs of the negotiation that Mr. Reed says he relied on to conclude that Enbridge’s negotiations were fair.80 Mr. Reed clarified that Enbridge both prepared these negotiation logs and determined what would be included in them.81 It’s not credible for Enbridge to rely on Mr. Reed’s review of information created and controlled by Enbridge itself as constituting a reliable independent assessment. Mr. Reed was retained to represent Enbridge’s interests in this case. No reliance can be placed on these records or Mr. Reed’s review given that Enbridge has admitted that the records were of such poor detail that “Enbridge did not track exactly which shipper(s) requested or supported every term and condition or toll change during nearly two years of negotiations.”82 In the absence of complete and objective factual evidence regarding the extent and nature of Enbridge’s negotiations, it is not possible for the Commission to assess the fairness of the process.
Enbridge Abused its Dominant Market Position During the Course of Negotiations
69. A fundamental part of the Commission’s mandate in respect of financial regulation of pipelines and their owners is to prevent the potential abuse of market power, and the CSG submits that the Commission must deny the Application on this basis, among many others.
70. Regulation of public utilities and common carriers exists to protect the public from monopolistic behaviour of service providers and to ensure the reliable and safe supply of essential services to customers on a non-discriminatory and open manner.83 The NEB has recognized that preventing potential market abuse is economic regulation’s core concern:
[E]conomic regulation is designed to prevent the potential abuse of market power by a company operating in a monopolistic environment or in one with limited competition. Regulation ensures that such a company charges rates which are fair to customers and provides the company with a reasonable opportunity to earn a fair return on its capital investment. The [NEB] agrees with Murphy that effective competition exists when customers of a service have the ability to obtain comparable services at
79 Enbridge Response to Canadian Natural IR No 1.2(a), PDF 6 (C11771).
80 Transcript Vol. 2, PDF 47, paras 1739 - 1740.
81 Transcript Vol. 7, PDF 12, paras 6393 - 6396.
82 Transcript, Vol. 2, PDF 45, para 1717.
83 ATCO Gas & Pipelines Ltd. v Alberta (Energy & Utilities Board), 2006 SCC 4 at para 3 citing A. E. Kahn, The Economics of Regulation: Principles and Institutions (1988), Vol. 1 at 11.
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reasonable prices from alternative suppliers and market participants are 84 not in a position to exercise market power.
71. This Commission recently affirmed that “[t]he role of the Commission to prevent the potential abuse of market power remains important.”85
72. The NEB has further stated that it must intervene to prevent both substantive and perceived market power abuse.86 Intervening to prevent perceived abuse is necessary to economic efficiency, because “an apprehension that some market players are abusing their power may lead to inefficient outcomes, and the occurrence of expensive and non-productive transactions and interactions. This kind of situation takes away from economic efficiency and needs to be addressed.”87
73. It is uncontested by Enbridge that it has market power in the market for pipeline capacity out of the WCSB, defined as a large share of the market or a dominant position.88 The Enbridge Mainline accounts for approximately 70% of the egress capacity from the WCSB.89 This means that producers, as well as many Canadian refiners, are heavily dependent upon the Mainline, and Enbridge has considerable market power as a result of its dominant position.
74. Enbridge’s own evidence suggests that the Commission’s oversight and regulation of the market are shippers’ only effective recourse against abuse by Enbridge of its market.90 For example, Enbridge has submitted:
Enbridge has no ability to establish tolls or terms of service on the Mainline that reflect the exercise of market power, because both Enbridge and all shippers know that such conduct will not be permitted by the CER, and any terms that result from the exercise of market power will be rejected by the regulator. As long as all shippers are free to protest the terms of service
84 NEB Letter Decision TO-4-2020 - Murphy Oil Company Ltd., Concerning Tolls for the Milk River Pipeline (Milk River) (August 2001) at 4.
85 Commission Aid 1: CER Letter Decision Campus Energy Partners Suffield LP, RH-002-2020, PDF 4 (C13426-2).
86 Transcript Vol. 9, PDF 58 - 59, para 8546; NEB Reasons for Decision RH-3-2004 – TransCanada North Bay Junction (December 2004) at 8.
87 Transcript Vol. 9, PDF 58 - 59, para 8546; NEB Reasons for Decision RH-3-2004 – TransCanada North Bay Junction (December 2004) at 8.
88 Enbridge Response to CER IR No. 2.27, PDF 108 (C07648-2); Transcript Vol. 3, PDF 27, paras 2738 – 2745.
89 CER Letter Decision, Complaints regarding Enbridge Mainline Open Season, September 27, 2019, PDF 2 (C01893-1).
90 See Enbridge Response to CER IR No. 2.27, PDF 108 (C07648-2); Transcript Vol. 3, PDF 28, paras 2751 – 2755.
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without any detrimental impact on their rights to access and use the Mainline, the shippers have effective recourse to overcome any attempt at 91 market power abuse by Enbridge.
75. Enbridge effectively stated that it would exercise market power, but for the Commission’s intervention. This underscores the central importance of the Commission’s scrutiny regarding the potential abuse of market power at play in this Application.
76. In the CSG’s view, Enbridge’s approach to consultations and negotiations in relation to its Mainline contracting proposal did constitute a real abuse of its dominant position in the market. Enbridge did not attempt to address the concerns of pure producers who are opposed to Mainline contracting because it knows that those producers have few alternatives for shipping their products to market. Enbridge’s contracting proposal will force producers into making multi-million or billion dollar long-term commitments in the event they do not want to be left out of the last remaining egress from the WCSB. Producers would be forced to make these long-term and significant financial commitments despite the fact that:
(a) they would have to do so without knowing whether those contracts would allow them to ship because of a lack of DSV; and
(b) they cannot assess the price that they will receive for their product due to the additional opaqueness that Mainline contracting would introduce to an already illiquid market hub.92
77. Enbridge understood the divergent interests of stakeholders and targeted its offering to a small subset of shippers who, based on their rational economic interests, would be likely to support Enbridge’s proposal to convert the Mainline to contract carriage. By conducting only bilateral negotiations and refusing to provide basic cost of service information, Enbridge was able to leverage its dominant position to its benefit.93
78. The CSG asks the Commission to exercise its statutory obligation to prevent market power abuse. In the case of Enbridge’s present application, preventing abuse is essential to ensuring that Canadians obtain full value for their natural resource production.
91 Enbridge Response to CER IR No. 2.27, PDF 108 (C07648-2).
92 Transcript Vol. 19, PDF 19, paras 18940 – 18943.
93 Transcript Vol. 16, PDF 113, para 16551.
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Degree of Opposition to the Application
79. The Application faces an unprecedented degree of opposition. Enbridge’s characterization of the Application having broad support is not true. While Enbridge repeatedly points to the level of volume its supporting shippers ship on the Mainline as shippers of record, the production from the opposing producers represents roughly 92% of the Mainline’s capacity.94
80. As shown in the figure below,95 in addition to virtually all pure producers, the Application is opposed by various Canadian and American refining interests, including CCRL&FCL, Shell Canada, Valero, and Phillips 66; by aggregator interests as represented by Shell Canada; by the majority of refined product shippers (Suncor, CCRL&FCL and Shell Canada); by Shell Canada in its capacity as an NGL shipper; a Canadian pipeline company, and by the Government of Saskatchewan, which has adduced evidence on the potential negative impacts to that Province’s upstream industry.
81. Enbridge’s expert witness, Mr. Reed, has attempted to characterize the outcome as typical of industry negotiations in which some parties may win and others may lose. Mr. Reed has suggested that the CER should not concern itself with these effects.96 In cross examination by counsel for the Government of Saskatchewan, Mr. Reed stated:
94 Transcript Vol. 17, PDF 123, para 17731.
95 EPAC Evidence to the CER, PDF 11 (C10190-2).
96 See Transcript Vol. 6, PDF 13, paras 5605 – 5609.
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MR. REED: There are parties that may consider themselves to be losers. My view is it should not be -- the case should not turn on the identity of those winners and losers. I think the Commission very definitely should consider the entirety of the benefits and any burdens that may go along with it.
But I don’t want that to be interpreted as agreeing to really the submission, the evidence of Saskatchewan here, that this is a zero-sum game. That’s the phrase you used in your evidence and I would definitely not agree with that. I think it is a very positive net outcome. It is not a zero-sum game when you look at the entirety of the benefits and any potential cost or burdens that go along with it.
MS. KENNEDY: And just so that I’m clear, you have not done any analysis to determine the geographic location of potential winners and losers as a result of Mainline contracting; correct?
MR. REED: That’s correct. The geographic dispersion, if you will, of U.S. versus Canadian or Alberta versus Saskatchewan versus Manitoba or Minnesota or any other state, no. So -- and again, we didn’t think geographic dispersion represented a point of differentiation in terms of 97 benefits or burdens.
82. The CSG emphatically disagrees with the Mr. Reed’s suggestion that the CER should not consider the identity of the “winners and losers” when considering whether the Application is in the Canadian public interest. The majority of supporting parties are US-based refiners or integrated oil companies with refining interests in the US, while the vast majority of the opposing parties are represented by Canadian-based interests.
83. The CER’s mandate is to regulate in the Canadian public interest and, in this case, it is incumbent on the Commission to have regard to the potential winners and losers, and the implications for Canadian interests, that would result if it were to approve Enbridge’s Mainline contracting proposal.
VI. ENBRIDGE HAS NOT PROVIDED ADEQUATE JUSTIFICATION FOR INTRODUCING MAINLINE CONTRACTING
84. Enbridge asserts that the conversion to contract service is justified because of: “the desire of Enbridge to retain volumes on the Enbridge Mainline and reduce its long-term volume risk.”98 Enbridge asserts that another reason Mainline contracting is required is that “it will provide the appropriate price signals about if and when to undertake expansions of the Mainline”99 and that Enbridge “requires
97 Transcript Vol. 6, PDF 13, paras 5606 – 5609.
98 Application, PDF 7, para 3 (C03823-2); Enbridge Reply Evidence, PDF 11 (C12447-2).
99 Enbridge Reply Evidence, PDF 12 (C12447-2).
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assurance that the existing Mainline capacity will be utilized before it will invest in additional capacity.”100 Respectfully, these assertions are specious.
85. Contrary to Enbridge’s assertions, the CSG submits that the following key justifications on which Enbridge seeks to rely are categorically untrue. Specifically:
(a) There is no demonstrated material volume risk as a result of pipeline competition or decarbonization initiatives.
(b) Contracting is not necessary to support future expansions, and may in fact inhibit future expansions. In fact, Enbridge has successfully expanded its the Mainline system by over 1 MMbpd 101 since 2010 under the current 100% uncommitted service structure.
86. Enbridge’s evidence and submission presented to the Commission on these issues have been inconsistent and in many instances diametrically opposed to communications by Enbridge’s senior management, including its CEO, to its investors and securities regulators. In short, Enbridge’s evidence lacks credibility.
87. The Commission should give little weight to Enbridge’s evidence on these issues, which are foundational to Enbridge’s Application, and which are discussed in turn below.
Enbridge has not Demonstrated that it Faces any Material Volume Risk
88. Enbridge has claimed that one of the primary reasons for moving away from the 70-year history of common carriage on the Mainline to a new contract carriage model is the alleged risk Enbridge currently faces of volume loss on its system. As stated by Enbridge’s expert witness, Mr. Reed:
The long-term competitive risks Enbridge faces present a risk of declining usage on the Canadian Mainline and a potential tolling spiral and associated stranded costs. Enbridge faces this competitive risk in part because, as an existing pipeline, Enbridge is at a distinct competitive disadvantage relative to its competitors as the only major export pipeline 102 that is not able to offer firm service.
89. In fact, Enbridge has completely failed to demonstrate this risk in its evidence and has consistently advised its investors that Enbridge represents a low risk investment even without long-term contracts. The Mainline faces no material volume risk, and – as elaborated below – has represented its positive financial outlook regardless of whether or not Mainline contracting is approved. Enbridge’s
100 Enbridge Reply Evidence, PDF 12 (C12447-2).
101 CNRL IR 1.8.c Attachment 2 – Historical Mainline Available (C07659-8).
102 Application, Appendix 5 – Evidence of John Reed, A38, PDF 31 (A7C1I7).
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assertion that it requires assurance the Mainline’s capacity will be utilized is particularly absurd given the rate of apportionment experienced on the Mainline.103
Enbridge’s Communications to Investors and Securities Regulators
90. The Mainline’s existing right of way affords Enbridge a competitive advantage.104 In the oral hearing of this Application, Mr. Varsanyi confirmed that Enbridge Management’s Discussion and Analysis (“MD&A”) regarding Future Operations105 recognizes this competitive advantage. Unbelievably, Mr. Varsanyi asserted that all statements in Enbridge MD&A are conditional on Mainline contracting being approved.106 Mr. Varsanyi pointed to language under the heading “Forward Looking Information” to support this assertion. That language does not state that the MD&A is conditional on approval of Mainline contracting.107 Enbridge provided this information to its investors without any sort of caveat that continued performance is conditional on the Commission approving its Mainline contracting proposal.108 It is clear that the Mainline’s existing right of way provides a competitive advantage regardless of whether contracting is approved, and that view is endorsed by the highest levels of Enbridge’s management and presented to the investor community and securities regulators.
91. In 2018, Enbridge communicated to its investors that it was confident that throughput on its system would remain strong even if both Keystone XL and TMEP were brought into service in 2021 and 2023 respectively.109 In the oral hearing, several shippers supportive of the Application confirmed that their demand for the
103 See CER IR 1.11.a.2 Attachment – Enbridge Mainline Apportionment (C06801-19) showing heavy apportionment between 49% and 53% in January – March, 2020; Reply Evidence of Neil Earnest, PDF 27 (C12447-9) showing heavy apportionment on the Mainline above 30% in January 2021; Transcript Vol. 19, PDF 42, para 19126, CSG Transcript Corrections - Volumes 17 – 20, PDF 13 (C13806-1) (Currently, 52% apportionment for heavy).
104 Transcript Vol. 1, PDF 50, paras 507 – 509.
105 Enbridge – Management’s Discussion and Analysis (MDA) (December 31, 2020), PDF 10 (C13116-4).
106 Transcript Vol. 1, PDF 51, para 512.
107 See Enbridge – Management’s Discussion and Analysis (MDA) (December 31, 2020), PDF 3 (C13116- 4).
108 Enbridge Day Presentation – Liquid Pipelines (C13116-7); Transcript Vol. 1, PDF 61, paras 611 - 613.
109 Enbridge Response to Suncor IR 1, PDF 8 (C07660-2) – 2018 Enbridge Day – Annual Investment Community Conference, 11 Dec 2018, Transcript available online: https://www.enbridge.com/~/media/Enb/Documents/Investor%20Relations/2018/ENBDay/ENBDay20 18_Transcript.pdf.
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Mainline is unaffected by the Trans Mountain Expansion expected to come on-line, the suspension of Keystone XL, and accelerated decarbonization policies.110
92. In a presentation to its investors in December 2020,111 Enbridge said it was highly confident in the longevity of its cash flows for years to come and communicated that it faces very little risk of losing volumes off the Mainline despite significant black swan events such as COVID 19. According to Enbridge, much of the system’s refining base is sole sourced (approximately 2.0 million bpd) and, accordingly, these connected refineries should be considered captive to the Enbridge Mainline with or without priority access. In addition, shippers already have in place over 1 million bpd of long-term downstream take-or-pay contract commitments, and given that the only upstream connection for these connections is the Enbridge Mainline, it can be expected that 3.1 million bpd of volumes will necessarily flow on the Mainline as opposed to potential pipeline alternatives. As communicated by Enbridge to its investors and shown below, the Mainline is part of the “[l]argest and most competitively positioned crude oil system in [North] America”:112
93. The combination of refinery volumes that are sole-sourced along the Mainline, plus downstream commitments, adds up to over 3 million bpd, or just about the current capacity of the Mainline (after completion of Line 3).
110 Transcript Vol. 15, PDF 75, paras 15036 – 15041 (BP); Transcript Vol. 15, PDF 104, paras 15350 – 15351 (Motiva).
111 Enbridge Day Presentation – Liquid Pipelines (C13116-7).
112 Enbridge Day Presentation – Liquid Pipelines, PDF 2, Slide 4 (C13116-7).
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94. On May 7, 2021, just weeks before the oral portion of this hearing, Enbridge issued a press release in which its CEO, Mr. Monaco, is quoted as saying “We’ve had a strong start to the year. Each of our four blue chip businesses were very highly utilized in the first quarter, reflecting their resilient demand-pull franchises, top- notch customers and the ongoing recovery of global economic activity.”113
95. If one trusts that Enbridge is painting an accurate picture to its investors, the Mainline is clearly not a system that faces any material risk of offloading now, or in the foreseeable future.
No Material Competitive Risk and Cancellation of Keystone XL
96. Similarly, there is no credible evidence that the Mainline faces significant competitive risk that would justify Mainline contracting. At the time Enbridge filed the Application, it viewed the Keystone XL project as a threat that could potentially offload volumes from the Mainline. However, the Keystone XL project has since been cancelled by TC Energy, and any remaining ‘threat’ to Enbridge has been greatly reduced as a result. Current monthly apportionment levels between 30% to 53% indicate that demand for pipeline capacity remains very strong despite the impact of a world-wide pandemic that crushed energy demand and challenged the viability of producers.114 The uncontroverted evidence in this proceeding is that production has rebounded to pre-COVID levels and that there are additional projects ready to proceed if there were additional export pipeline capacity.115
Supply Forecasts
97. Enbridge’s own statements to investors and all available forecasts fatally undermine Enbridge’s assertion that volume risk justifies its application to convert the Mainline to contract service.
98. In its Application materials, Enbridge relies on the CAPP 2019 forecast to model WCSB crude supply.116 This forecast shows western Canada oil sands and conventional supply increasing from under 5 million barrels per day to over 6 million bpd by 2035, a production increase of more than 20%.117
113 Release Details – Enbridge Inc., PDF 3 (C13116-6); Transcript Vol. 1, PDF 57, paras 562 - 569.
114 See CER IR 1.11.a.2 Attachment – Enbridge Mainline Apportionment (C06801-19) showing heavy apportionment between 49% and 53% in January – March, 2020; Reply Evidence of Neil Earnest, PDF 27 (C12447-9) showing heavy apportionment on the Mainline above 30% in January 2021; Transcript Vol. 19, PDF 42, para 19126, CSG Transcript Corrections - Volumes 17 – 20, PDF 13 (C13806-1) (Currently, 52% apportionment for heavy).
115 Transcript Vol. 19, PDF 42, para 19128.
116 Enbridge Response to CNRL IR No 1.9 (a) to (c), PDF 23 (C07659-2).
117 CAPP 2019 Crude Oil Forecast, Markets and Transportation, PDF 10, Figure 2.7 (C13222-2).
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99. Likewise, the conservative forecasts provided by Wood Mackenzie and the CER’s “Evolving Case” both show that there will be increased production that will rely on Mainline transportation service to access markets for the foreseeable future.
100. Under the CER’s Evolving Scenario, Mainline utilization reaches a low of 93% in 2023, assuming the Line 3 Replacement project, a Keystone 50,000 bpd expansion, and TMEP have all entered service by that time. By any reasonable standard, a pipeline with a 93% utilization rate is a highly utilized pipeline.118 In fact, an annual Mainline utilization rate of 93% is likely to be insufficient to meet peak winter blending volumes and therefore may be subject to apportionment for parts of the year.119 This is because the forecasts present supply and egress on an annual basis. In the higher blending months in the winter, there will be a greater supply volume than the annual average.120
101. Under the Wood Mackenzie supply forecast,121 Mainline utilization is assumed to be equivalent to the 90% contracted level and rail movements must expand beyond historic peaks in order to ensure WCSB production continues to flow. Assuming TMEP and the Keystone 50,000 bpd expansion project are both in service by 2024, aggregate excess egress pipeline capacity out of the WCSB reaches a maximum of only 340,000 bpd before production increases start to refill the surplus.
102. Drazen’s evidence shows, in its figure 4, that the cost of service toll would remain below the proposed MLC toll over the range of throughputs in each of the above forecasts.122
Rail Is Not a Competitive Alternative to the Mainline
103. Enbridge presented rail as a competitor to the Mainline.123 This is not true. Rail market participants124 have confirmed rail is not competitive to pipeline options. Not only is rail a higher cost option, access to rail requires a significant lead time for a
118 Transcript Vol. 20, PDF 46, paras 19997 - 19998.
119 See Transcript Vol. 18, PDF 86, para 18681; .Transcript Vol. 17, PDF 138 – 139, paras 17890 - 17891.
120 One example being under the Wood Mackenzie scenario, discussed by Ms. Day in Transcript Vol. 18, PDF 86, para 18681.
121 U-10 and U-11 – Requested Revisions to Wood Mackenzie Western Canadian Supply and Pipeline Takeaway Capacity (C13537-3).
122 Blackline Revised Written Evidence of Drazen Consulting, PDF 31, Figure 4 (C12665-2).
123 Transcript Vol. 8, PDF 32, para 7662.
124 Transcript Vol. 22, PDF 113, para 23130.
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new rail player to put in place all of the necessary elements to initiate service. For example, in an exchange with CER legal counsel, Valero explained as follows:
MR. HAWKINS: No. The only way rail works is when the pipeline is full and discounts get wide enough to make additional transportation costs justified.
MS. GAGNÉ: Do you believe that some companies would choose to use rail instead of a pipeline, even if there was pipeline capacity available in the area?
MR. HAWKINS: If one refiner had the option of taking pipe versus rail, and nothing else changed, no, I don’t believe that they would choose to do rail instead of pipe. There’s logistics, headaches, the offloading. Yeah, the risk of derailments. There’s -- I don’t believe anyone would choose to do rail 125 instead of pipe, equal, you know, supply basis.
Enbridge’s Subjective “Risk-Catalogue” Is Not Credible
104. Enbridge has also put forward a five-page “risk catalogue” assembled by Concentric Energy Advisors Inc. through “informational interviews” with Enbridge’s staff.126 As Dr. Makholm notes in his written evidence, the point of this catalogue is unclear. The CER is well acquainted with how risk is relevant to its regulatory responsibilities and has for decades set risk-adjusted returns on owners’ capital, based on objective evidence from capital markets.127 As Dr. Makholm stated in response to questions from the Commission’s counsel, Enbridge does not decide what matters in terms of risks – capital markets do.128
105. Subjective internally produced surveys, such as the one underlying Concentric’s analysis, do not provide a credible or reasonable basis for determining whether the implied rate of return for the tolls proposed in Enbridge’s Application are just and reasonable.
Enbridge has not Demonstrated that Mainline Contracting Is Necessary to Enable Future Expansion
106. Enbridge claims that long-term contracts will better facilitate future Mainline Expansions.129 This claim is without merit and circular given that Enbridge is not
125 Transcript Vol. 22, PDF 113, paras 23133 – 23134, as corrected by VEI Corrections to Volume 22 of the Transcript (C13818-2).
126 Attachment 2: Risk Catalogue (C06800-5); Additional Written Evidence of Concentric Energy Advisors, Inc. (C06800-3).
127 Written Evidence of Dr. Jeff D. Maholm, PDF 12 – 13 (C10237-4).
128 Transcript Vol. 20, PDF 18 – 19, paras 19761 – 19763.
129 Application, Appendix 6: Evidence of Jeffrey Church, PDF 30, para 102 (C03823-8).
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making any new investments or offering expansion capacity that would arguably require long-term financial commitments by shippers as part of its Mainline contracting proposal.
107. The uncontroverted evidence before the Commission clearly demonstrates that common carriage on the Mainline has not inhibited expansion.130 History shows that Enbridge has been able to expand without long-term contracts, and can do so in the future.131
108. Even with long-term contracts that were strongly supported by producers, many pipeline projects have faced delay or cancellation (e.g. Keystone XL, Enbridge’s own Northern Gateway Project,132 TMEP, and Energy East).
VII. CONVERTING THE CANADIAN MAINLINE TO FIRM SERVICE IS NOT IN THE PUBLIC INTEREST
109. The CSG expects that if the CER were to approve the Application and Enbridge’s Mainline contracting proposal were to be implemented, it would have significant and long-lasting adverse impacts on the Canadian public interest, including:133
(a) negative impacts on netbacks to Canadian producers and, by extension, negative impacts on royalties and taxes payable to Canadian governments;
(b) negative impacts on aggregators and small producers, including potentially driving them out of business, with adverse implications for the upstream industry as a whole;
(c) potentially negative impacts in the form of increased prices of refined products and NGLs to Canadian consumers; and
(d) potentially negative impacts on certain Canadian refiners that are dependent upon the Mainline.
130 Written Evidence of Mr. Roland Priddle, PDF 26 – 28 (C10237-5).
131 Written Evidence of Mr. Roland Priddle, PDF 26 – 28 (C10237-5).
132 The CSG notes that, strictly speaking, Northern Gateway pipeline never had long-term contracts. A group of 10 shippers agreed to contribute $10 million each to pay for the regulatory process, but did not make binding shipping commitments. In our view, the Northern Gateway case again demonstrates the lengths to which producers have gone to gain new access (most of the 10 shippers were producers). See Joint Review Panel Report OH-004-2011 – Enbridge Northern Gateway Project, Vol. 1: Connections at 28.
133 Written Evidence of the Canadian Shippers Group, PDF 8- 9, para 17 – 23 (C10237-2).
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Mainline Contracting Would Result in Adverse Impacts on Netbacks and Government Revenues
110. A central feature of the WCSB crude oil market is that pipeline egress capacity has been constrained for many years, and is expected to be constrained for the foreseeable future. While there may be a brief reprieve when TMEP comes into service, growth in production is expected to quickly fill any excess capacity.134
111. With a shortage of egress capacity, scarce Mainline capacity has become highly valuable. Enbridge’s Mainline contracting proposal, if approved, would effectively place this scarce and valuable capacity in the hands of parties with DSV capability, which would result in a significant transfer of wealth away from Canadian producers and resource owners to mainly US-based PADD II refiners, including integrated companies that have Canadian production operations.
June 2018 SVP Experiment is a Preview to Price Impacts of Mainline Contracting
112. What happens when a small subset of downstream parties with significant DSV capability gain control of scarce Mainline capacity was demonstrated by Enbridge’s change in SVP in 2018 that allocated space to shippers based on historical shipments.135 The effect of the new SVP methodology was that shippers with significant DSV capabilities gained the ability to effectively control access to scarce Mainline capacity and thereby reduce, or eliminate, the competitive buying pressure to acquire supply from producers. What happened then is similar to what can be expected to occur if Mainline contracting is approved.
113. The 2018 changes to the SVP resulted in a collapsing local price for WCSB crude oil that was only remedied when parties complained, and Enbridge reversed the SVP policy.136 As a result of such problems, and later evident shortages of capacity and a further collapsing local price, Alberta imposed production limits in 2019 to counterbalance the ability of Enbridge’s downstream shippers to appropriate for themselves the consequences of the practical difficulty of expanding adequate pipeline capacity out of the WCSB.137
134 Transcript Vol. 20, PDF 45 – 47, paras 19989 – 20003.
135 BPPNA Enbridge Supply Verification Procedure, PDF 5 - 10 (C13116-8).
136 Written Evidence of Dr. Jeff Makholm, PDF 10 (C10237-4).
137 Written Evidence of Dr. Jeff Makholm, PDF 10 (C10237-4).
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114. As shown in the figure below, there was a significant collapse in the WCS price when SVP was announced.138 WCS differentials dropped by US$8/bbl for the June post-apportionment market, and by US$8.80/bbl for the July index.
115. During the 2018 SVP experience, there was also a dramatic widening in the difference between the value of inline trades and the value of trades at the inlet of the Canadian Mainline of about US $16/bbl.139 This price differential, about twice that reflected in the index price differential, suggests the effect on actual prices and producer netbacks was much more significant than that reflected by the index price differential.
116. As stated by Ms. Day:
We saw what happened in June of ‘18. We saw barrels trade outside the flange of Enbridge at minus $26.00. At the same time, barrels were trading inside Enbridge at minus $10.00. That’s entirely related to who has that 140 space. That’s a $16.00 difference to who has that space.
117. Prices recovered immediately after Enbridge announced the reversal of the SVP ‘experiment’.141 Enbridge agrees.142
138 CSG Responses to Enbridge IR No. 1, PDF 81 (C11771-2).
139 Transcript Vol. 16, PDF 114, para 16553.
140 Transcript Vol. 18, PDF 84, para 18657.
141 Written Evidence of the Canadian Shippers Group, PDF 67, para 215 (C10237-2).
142 Transcript Vol. 1, PDF 113, paras 1189 - 1190.
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118. While the correlation between the 2018 SVP change and impact on prices is clear and had not previously been disputed, Enbridge, late in this proceeding, has attempted to point to other reasons for the dramatic drop in prices.
119. Enbridge stated in response to CER IR No. 6 that it “… does not believe that the introduction of the [SVP] in mid-2018 resulted in significant market price impacts.”143 Enbridge has tried to identify other events, specifically within that general time period, to cast doubt on the connection between the implementation of 2018 the dramatic coinciding decline in western Canadian crude prices. Enbridge has noted events such as:
(a) growth in WCSB supply in 2017;
(b) a Keystone Pipeline leak;
(c) storage reaching capacity in mid-2018;
(d) a CP Rail strike;144 and
(e) wildfires.
120. Enbridge’s theories about alternative events145 are unsupported by the evidence. All the contemporaneous evidence shows the introduction of SVP caused the price changes. For example:
(a) Dr. Church was not able to identify a single incident of crude rail shipments being interrupted by the 2018 CP rail strike.146
(b) Dr. Church admitted that in his review of pricing data, he had never observed such a large price change in the space of just three hours, as was seen on the morning of June 4, 2018, when the SVP was revoked.147
(c) In its 2018 letters, Enbridge did not suggest the rail strike or wildfire caused the price changes.148 To the contrary:
143 Enbridge Response to CER IR No. 6, PDF 17 - 18 (C11746-2).
144 Reply Evidence of Dr. Jeffrey Church, PDF 86, para 217 (C12447-10)
145 Transcript Vol. 1, PDF 114, paras 1211 – 1212.
146 Transcript Vol. 1, PDF 114, paras 1209 – 1210.
147 Transcript Vol. 2, PDF 20, paras 1405 – 1406.
148 Transcript Vol. 1, PDF 111 – 112, paras 1170 – 1180.
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(i) Enbridge’s June 4, 2018 letter to the NEB clearly acknowledges the impacts of introducing the SVP and that Enbridge failed to foresee the outcome.149
(ii) Enbridge’s June 11, 2018 letter to the Board discusses the behaviour in response to SVP’s introduction “causing significant unforeseen and unforeseeable financial harm for many of Enbridge’s customers.”150
(iii) Enbridge’s June 18, 2018 letter to the CER acknowledged the “unintended consequences” associated with the introduction of SVP.151
(d) None of the shippers filing letters of concerns at that time noted any potential contributing event other than the change in SVP.152
121. Dr. Church confirmed in the oral hearing that he conducted no analysis of the impacts of wild fires on crude oil prices. Under cross-examination, Dr. Church made admissions that fatally undermine the credibility of his assertions about other factors that may have caused the significant drop in western Canadian crude oil prices during the 2018 SVP changes. For example:
MR. IGNASIAK: And so you referenced some Alberta government websites that show the status of forest fires and do you know what Firebag’s production was in each of April, May, and June of 2018?
DR. CHURCH: I do not.
MR. IGNASIAK: And so you don’t know if it went up or down during those months?
153 DR. CHURCH: I do not.
122. After some discussion of whether a market reaction to wild fires would tend to decrease (or increase) crude oil prices, counsel for the CSG and Dr. Church had the following exchange, which bears reproducing:
MR. IGNASIAK: All right. I didn’t follow that, but that’s fine.
149 Written Evidence of the Canadian Shippers Group, PDF 67, para 216 (C10237-2).
150 Letter to NEB re Enbridge Response to BP Notice of Complaint, PDF 3 (C13116-12).
151 Letter to NEB re Enbridge Additional Comments to BP Notice of Complaint, PDF 2 (C13116-16).
152 Nexen Letter to NEB re Complaint against Enbridge (C13116-13); Letter to NEB from Statoil (C13116- 14); Response to NEB Letter of June 7, 2018 (CITGO) (C13116-15).
153 Transcript Vol. 1, PDF 96, paras 1026 – 1029.
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So I think the key thing was you agreed that if there is a fire threatening the supply of oil in the basin, that would likely result in prices going up, correct?
DR. CHURCH: That’s correct, yes.
MR. IGNASIAK: Right. Okay.
DR. CHURCH: That would be the expectation, right? If this fire was a significant impact, that would be a factor which would raise the price.
MR. IGNASIAK: Sir, you’re familiar with the Fort McMurray wild fires in 2016, that caused the largest evacuation in Alberta’s history? I’m assuming you recall that?
DR. CHURCH: I recall that.
MR. IGNASIAK: And did you do any analysis of what happened to prices during the course of that fire?
DR. CHURCH: I did not.
MR. IGNASIAK: No. So you were just really zoned in on May, June of 2018 and how to explain the SVP price change. So you just looked to see if there were any fires at the time, but you didn’t do any bigger analysis about the impact fires generally have on oil prices when there were fires in Fort McMurray region, right?
DR. CHURCH: I did not. That was not -- in my view, it was not an exercise that I had to do. The exercise here was to try and identify whether there were other factors besides SVP, which might have affected the 154 price. [Emphasis added.]
123. In this exchange, Dr. Church testified that he expressly sought out any other explanation for this significant drop, aside from the 2018 SVP.
124. Regarding Dr. Church’s assertion that a CP rail strike caused the June and July 2018 drop in crude prices, Dr. Church again admitted he conducted no analysis. Rather, his conclusions were based on unsupported assumptions. The following exchange makes this clear:
MR. IGNASIAK: … Dr. Church, when preparing your reply evidence, you carefully assessed the impact of the May 2018 CP Rail strike on the crude market, correct?
DR. CHURCH: I’m sorry; I don’t think I understand what you mean by carefully considered the impact of the CP Rail strike on the oil market.
MR. IGNASIAK: All right, sir, well, you have indicated that the rail strike may have been a contributing factor to prices, correct?
154 Transcript Vol. 1, PDF 97 – 98, paras 1036 – 1047.
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DR. CHURCH: I have indicated that, in my view, there was confounding factors, confounding influences, on the price of crude oil during the SVP period. One of them might have been the rail strike.
MR. IGNASIAK: And when you were looking at that issue, were you able to identify a single confirmed case of crude shipments by rail being interrupted?
DR. CHURCH: No. And as I indicated before, when we were dealing with developments in industry, the key causal factor is how it affects people’s expectations about what was going to happen in the next month.
MR. IGNASIAK: So you’re making an assumption, then, that the rail strike may have impacted traders’ behaviour during that time; is that correct?
DR. CHURCH: Well, I mean, that’s what we’re dealing with, especially on 155 the trades on June 1st and June 4th.
125. Dr. Church did not even look at the impacts of other rail strikes on crude oil prices, and instead simply assumed that the 2018 strike lowered the cost of WCSB crude oil without any verifiable basis for this assertion.156
126. In the CSG’s view, it is clear that Enbridge is ex-post simply trying to come up with alternative explanations. These alternatives are totally lacking in credibility or corroboration and should be soundly rejected by the Commission. Further, Enbridge admitted that the SVP contributed to price changes and contract cancellations and acknowledged it was disruptive to introduce it on short notice.157 Enbridge’s current narrative on the 2018 SVP lacks credibility and demonstrates its total lack of consideration for a large portion of its stakeholder community, especially the producer interests, in this proceeding.
127. Dr. Makholm’s written evidence describes how, under the new SVP “US refineries connected to the Mainline received a disproportionately large share of the Mainline capacity”.158 The announcement of SVP “resulted in an immediate drop in WCS (due to the change in the aforementioned procedures) and as a result, producers were forced to accept lower prices.”159
155 Transcript Vol. 1, PDF 114, paras 1204 – 1212.
156 Transcript Vol. 1, PDF 114 - 115, paras 1213 – 1214.
157 Transcript Vol. 1, PDF 110, paras 1161-1167.
158 Written Evidence of Dr. Jeff Makholm, PDF 40 (C10237-4).
159 Written Evidence of Dr. Jeff Makholm, PDF 40 (C10237-4).
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128. Dr. Makholm described Enbridge’s 2018 changes to the SVP as “a virtual controlled experiment”,160 and concluded that the episode’s impacts “are illustrative of what would occur if Enbridge’s Contracting Application were to proceed” 161 and “illustrates what could happen in a contract carriage scenario: harm to producers and royalty owners.”162
129. In the CSG’s view, Enbridge’s Mainline contracting proposal, if approved, can be expected to have a similar impact to the 2018 SVP changes, although the impact would endure for many years, rather than a few days.163 Dr. Makholm estimated the losses could be as high as $14.5 billion per year.164 The consequences of the present Application are potentially much graver than the short-lived experience with SVP because these contracts are locked in for 20 years, and potentially 30 years considering extensions, so cannot be reversed on short notice if dramatic problems arise following any approval and implementation of Enbridge’s Mainline contracting proposal.165
130. Enbridge has suggested that due to the two years of advance notice about Mainline contracting being implemented, the price impacts associated with the SVP will not happen again. However, Enbridge did not provide any evidence as to how advance notice would somehow avoid the negative price impacts that can be expected to occur when parties gain control of scarce Mainline capacity and have the ability to monetize that capacity to their best economic benefit. Two years of planning will only enable parties to develop additional strategies to exploit their control of that capacity – advance notice will not change the expected outcome when a few parties are able to secure the scarce Mainline capacity.
Market Pricing Dynamics
131. As stated in the CSG’s evidence and in the evidence of Mr. Earnest, Enbridge’s expert market witness, producers in the WCSB generally receive the market price at the destination (e.g. US Gulf Coast) minus the cost of the marginal transportation option (i.e., the highest cost option in use).166 This is an essential
160 Written Evidence of Dr. Jeff Makholm, PDF 10 (C10237-4).
161 Written Evidence of Dr. Jeff Makholm, PDF 33 (C10237-4).
162 Written Evidence of Dr. Jeff Makholm, PDF 41 (C10237-4).
163 Written Evidence of Dr. Jeff Makholm, PDF 11 (C10237-4); Written Evidence of the Canadian Shippers Group, PDF 65 - 66, para 210 (C10237-2).
164 Written Evidence of Dr. Jeff Makholm, PDF 10 (C10237-4).
165 See discussion in Transcript Vol. 1, PDF 105 – 1-6, paras 1122 – 1132.
166 CSG Response to Enbridge IR 1.18, PDF 38 – 47 (C11771-2); Application, Appendix 7 – Evidence of Neil Earnest, Chapter 4, PDF 19 - 25 (C03823-9).
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feature of the market that must be understood if one is to understand the likely impacts of Enbridge’s proposal on producer netbacks.
132. As shown in Table 7 of Mr. Earnest’s direct evidence,167 the netbacks that WCSB producers would receive based on a Houston price of US $55/bbl would be $47.04 when Enbridge/Flanagan South is acting as the marginal transport option, but only US $37.27/bbl when rail is acting as the marginal transport option – a difference of US $9.77/bbl.
133. Unfortunately, with inadequate pipeline capacity for many years now, the second situation has been the norm more often than not and WCSB producers have been forced to accept lower netback prices. As detailed throughout the CSG’s evidence, this is a key driver behind producers’ desire for additional egress capacity to a liquid hub.168
134. A critical feature of this constrained market is that it has enabled PADD II refiners to access discounted WCSB crude oil.169 In the above example, based on Mr. Earnest’s evidence, PADD II refiners would be able to access WCSB crude at the netback price in Edmonton of US $37.27 plus the toll on Enbridge, which at US $5.70/bbl, would mean a delivered price of $42.77 in PADD II, compared to the going market price of US $55/bbl in the Gulf Coast (Houston).
135. It is clear that refiners in PADD II have been the beneficiaries of constrained capacity and it is in their economic interest to support Mainline contracting to lock in this favourable position for decades to come. This market situation and the fact that Enbridge has not proposed additional egress capacity combine to ensure that approval of the Application would be contrary to the Canadian public interest.
136. Given the lack of new capacity being offered by Enbridge, approval of the Application would ensure that Enbridge and parties with DSV assets, primarily in PADD II, would capture the value created by WCSB producers for up to 30 years. Under Mainline contracting, producers can expect to receive a lower price at the Mainline inlet, whereas supporting shippers have indicated they expect to benefit from lower feedstock costs through secure access to constrained and discounted WCSB supply.
137. Supporting shippers are willing to pay a toll well over a representative cost of service option because they expect to avoid apportionment and enjoy lower feedstock costs for the long-term. Testimony from US-based refiners confirm their motivations:
167 Application, Appendix 7 – Evidence of Neil Earnest, PDF 23, Table 7, Illustration of Heavy Crude Oil Netbacks (C03823-9).
168 See Written Evidence of the Canadian Shippers Group, PDF 13 – 15 (C10237-2).
169 See Written Evidence of the Canadian Shippers Group, PDF 68 – 69, para 223 (C10237-2).
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138. As stated by BP:
In addition, firm service on the Canadian Mainline will provide BP with access to a reliable and secure supply of Canadian crude oil for its US Midwest refineries, avoiding apportionment driven variability. This provides BP with certainty for its operations and helps to avoid costs associated with seeking alternative and potentially less optimal sources of 170 crude oil supply.
139. And by United Refining:
MS. SLIPP: And your conclusion, I take it, was that you support the proposed toll because it’s less than the price you pay for crude in the post- apportionment market? Am I drawing the right conclusion there?
MR. SPARLING: Generally speaking you are. We feel that under firm service and the tolls that have been proposed, and the volumes that we expect to receive, that the total cost of our delivery of crude versus uncommitted service will be more reasonable than they have been under uncommitted service.171
140. And by Motiva:
MS. SLIPP: And are those non-Mainline sources of supply potentially more costly than the WCSB sourced barrels that you would have received, absent Mainline apportionment?
MR. McINNES: They can be. It depends on the market and other factors of supply and demand. But those alternatives can be economically hurtful because you’re looking to buy crude in a market that has some constraints in it, and then you’re also looking along down the U.S. side at Cushing, Oklahoma or the U.S. Gulf Coast where those prices may be highly elevated, and that’s what we’re having to look at on.172
141. The reality is that prices at Cushing and the US Gulf Coast are benchmarks used by the entire industry as markers of fair market prices at liquid hubs. The fact that Mr. McInnes views these prices as “highly elevated” further demonstrates that refiners connected to the Mainline have been able to access crude supplies at prices below the fair market value one would expect in the absence of constrained pipeline capacity out of the WCSB.
142. The advantages expected to accrue to US-based PADD II refiners and integrated companies under Mainline contracting were also confirmed by Dr. Church in his reply evidence. Dr. Church stated that parties who gain control of Mainline
170 Written Evidence of BP, PDF 5, para 20 (C10226-2).
171 Transcript Vol. 14, PDF 22 – 23, paras 12908 – 12909.
172 Transcript Vol. 15, PDF 89, paras 15192 – 15193.
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capacity, if approved, would earn ‘scarcity rents’.173 Dr. Church stated that these scarcity rents would be equal to the difference between the cost of rail transport and the cost of transport by pipeline from Edmonton to the US Gulf Coast. Using the figures provided by Mr. Earnest on behalf of Enbridge, the cost of rail is about US$17.73 and the committed toll on Enbridge/Flanagan South is about US $7.96 (Table 6). Therefore, the scarcity rents earned by holders of Mainline capacity with downstream verification capacity according to Dr. Church would be about US$17.73 - US$7.96 = US$9.77/bbl, or over CDN$12/bbl.
143. Given that about 1 billion barrels are transported on the Mainline each year,174 over CDN$12 billion would be transferred from Canadian producers to mainly US- based PADD II refiners each year. The CSG notes that not the entire amount would represent a transfer away from Canadian producers because they may hold some capacity on the Mainline, but the evidence of Enbridge’s own witnesses nonetheless clearly demonstrates the huge transfer in wealth away from Canada that would occur if Enbridge’s Application were to be approved by the Commission.
144. As Dr. Makholm stated in his evidence, Enbridge cannot directly capture these scarcity rents because of regulation by the CER. However, the Application, if approved, would allow Enbridge to indirectly capture a share of these rents by selling control over scarce capacity to a subset of shippers who are in turn supporting tolls that far exceed any reasonable estimate of Enbridge’s cost of service.175
145. At times when rail cannot absorb the excess production, netback prices will be further depressed.176. In this situation, producers’ next best alternative is storage or shut-in, and the bargaining power of buyers is further enhanced, resulting in
173 Reply Evidence of Dr. Jeffrey Church, PDF 66, para 154 (C12447-10).
174 Transcript Vol 1, PDF 36, paras 347 – 348.
175 Written Evidence of Dr. Jeff Makholm, PDF 38 – 40, A35 (C10237-4).
176 CSG Response to Enbridge IR 1.18 (e), PDF 43 – 45 (C11771-2).
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prices dropping below the netbacks that would be determined by rail, as shown in the figure below: 177
146. Enbridge’s market expert, Mr. Earnest, stated that under certain conditions, Mainline contracting could actually increase netbacks to producers. Mr. Earnest stated that this would occur when there was adequate egress and all crude oil would be flowing out of the WCSB under contracts; i.e. no oil would be flowing under uncommitted tolls.178
147. With respect, the CSG is of the view that it is unreasonable, unsupported by the evidence, and frankly absurd to suggest Mainline contracting might result in higher netbacks to producers.
148. Rather, under any credible scenario, the Mainline will continue to be highly utilized. Enbridge’s capacity is fully utilized now179 and given the approximately 2.0 million bpd of sole sourced refinery demand and 1 million bpd of connected downstream commitments, demand pull for Mainline capacity will continue to be strong. Thus uncommitted capacity will be highly utilized, even with TMEP in-service. Any plausible demand and supply scenario would provide benefits to shippers who obtain contracted Mainline capacity and have the DSV capability to back it up.
149. If supporting shippers are successful in obtaining control of the capacity on a long term basis through Mainline contracting, they are in a no lose situation. Whether
177 Written Evidence of the Canadian Shippers Group, PDF 64, para 200 and Figure 9: WCS Prices Disconnect from Netbacks Set by Rail (C10237-2).
178 Appendix 7 – Evidence of Neil Earnest, PDF 22 (C03823-9).
179 Transcript Vol. 19, PDF 42, para 19126, CSG Transcript Corrections - Volumes 17 – 20, PDF 13 (C13806-1) (Currently, 52% apportionment for heavy).
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rail, uncommitted pipeline capacity to the Gulf Coast, or uncommitted capacity to the US Midwest (PADD II) is acting as the marginal transportation option, under Mainline contracting, buyers of crude would be advantaged by having access to crude oil that would be discounted relative to the market price, regardless of whether egress is constrained or not. Even in an excess egress capacity scenario, committed shippers would pay a discounted toll relative to the uncommitted toll to receive a secure supply of feedstock for their refineries at the toll they have supported in this proceeding. In other words, under Mainline contracting, there is no downside risk to downstream shippers who hold significant DSV capacity, such as PADD II refiners.
150. Further, in all scenarios under Mainline contracting in which producers’ netbacks are adversely impacted, there will be a knock-on effect on Canadian government revenues. The prices producers receive directly affect the royalties they pay to provincial governments, and lower prices will impact profitability and therefore negatively impact corporate income taxes. Dr. Makholm estimated that the impact on royalties payable to the government of Alberta alone could be about CDN$1.2 billion per year.180
Pricing in the Post-Apportionment Market
151. As discussed throughout the hearing and in the CSG’s evidence, the monthly trade cycle for crude oil sales via the Mainline can be broken into two periods: pre-apportionment and post-apportionment.181
152. In the Hearing, Enbridge stated that, presently, when apportionment occurs, parties that nominate capacity but do not receive their full nomination push back barrels in most circumstances because there is no capacity to transport those barrels on the Mainline.182 Producers seeking to sell pushed back barrels in the same month must find alternative transportation, or risk shutting their production in.183
153. Enbridge has downplayed the current impact (from both a volumetric and a price perspective) of apportionment on producers. Informed by the CSG members’ vast commercial and crude oil marketing experience that spans decades and millions of barrels in transactional history, the CSG disagrees with this assessment.
180 Written Evidence of Dr. Jeff Makholm, PDF 10 (C10237-4).
181 Written Evidence of the Canadian Shippers Group, PDF 18 - 21 (C10237-2).
182 Transcript Vol. 3, PDF 85 – 86, paras 3410 – 3419.
183 Transcript Vol. 3, PDF 86, paras 3420 – 3423.
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154. In the CSG’s view, the fact that prices are normally lower in the post-apportionment market is yet another real market demonstration that producer netbacks suffer when buyers have greater bargaining power in negotiations.
155. The evidence of the CSG is clear that prices in the post-apportionment market are normally negative compared to the pre-apportionment market. Ms. Day stated that:
… when we revisited this data and looked at 2018 to 2020 and took out the market events, there was 25 discounts that averaged to $3.77, and there was 5 premiums that averaged 88 cents in value. So there was very much a -- it’s very biased towards a negative post-apportionment pricing 184 environment.
156. As per Ms. Day’s testimony of her commercial experience, apportionment discounts are significant and real, and they are incorporated into company projections due to their impacts on cash flow and the expectation they will be negative:
… in my experience, when I was at Devon, I was director of marketing, and it became such a important part of our cash flow that I ended up having to forecast what the post-apportionment discount would be, as well as the percentage, so that we could try to get our cash flow more -- a more accurate cash flow from our Canadian business because it was negatively impacting our cash flow. And I know at CNRL we have had to do the same thing in periods of very high apportionment and large discounts, because when you take, you know, $3.80 or $4.00 off 40 percent of your barrels, it 185 certainly changes the cash flow in your forward-looking guidance.
157. Similarly, Mr. Alson of MEG Energy provided the following testimony on post- apportionment prices:
I think there were two months -- I want to say February and April -- where the supply dynamics -- supply/demand dynamics were such that we saw improved pricing post-apportionment. I think what you have seen here more recently is the return to the longer-term trend, which is discounts, sometimes very significant discounts in the post-apportionment market. So if you looked at it over the long term, you would still see that circa $3, 186 $4 discount in the post-apportionment market.
158. Post-apportionment sales are primarily conducted on the bilateral market and while there may be some price discovery value from the trade screen activity, it in no way represents the volume of barrels priced in the post-apportionment market.
184 Transcript Vol. 19, PDF 69, para 19364.
185 Transcript Vol. 19, PDF 69 – 70, para 19365.
186 Transcript Vol. 17, PDF 52, para 17003.
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159. The CSG provided a chart that showed the WCS post-apportionment trade differential is more often than not negative.187 Enbridge and its witness Dr. Church attempted to refute this observation. Figure 4 in Enbridge’s Reply Evidence is a chart that purports to show that post-apportionment prices were as likely to be positive as negative relative to pre-apportionment prices.188 The CSG submits that little if any weight should be put on Dr. Church’s evidence that prices in the post- apportionment market show no particular pattern. Contrary to Dr. Church’s assertion, the chart clearly shows that negative pricing, both in frequency and magnitude, far exceeds the instances where positive prices are experienced. The data in Figure 4 also covers a ten-year period (2010-2019) which is not representative of the current market dynamic because significant supply was brought onstream in late 2017 in anticipation of additional egress being available.
160. Nonetheless, Dr. Church himself admitted that prices could fall quickly in the post- apportionment market when there are a lot of pushback barrels, referring to a ‘waterfall’ effect:
If the price-setting mechanism can absorb those barrels, for instance, if there was lots of rail capacity available, then the expected price would not fall by very much. If, on the other hand, there’s lots of pushback barrels and the price-setting mechanism is close to capacity and we move kind of down the waterfall to the next alternative, then the price would fall.189
161. Dr. Church’s analysis highlights his unfamiliarity with crude market dynamics and shows a lack of understanding of basic commercial realities and how the apportionment market works. It is fundamental to recognize that buyers have a free option to return barrels to producers when apportionment is announced.
162. If there is no apportionment, the value of trades in the post-apportionment window are meaningless and should be excluded from assessing the post-apportionment discount over time because buyers cannot return barrels to sellers.
163. If the flat price (WTI)190 increases, or there is a supply disruption, the value of crude in the post-apportionment window increases as the delivery price for the month following is expected to be higher. Purchasers may then choose to not return crude because barrels traded in the post-apportionment window will reflect the higher
187 CSG Response to Enbridge IR 1.19, PDF 50 (C11771-2).
188 Enbridge Reply Evidence, PDF 24, Figure 4 (C12447-2).
189 Transcript Vol. 3, PDF 87, para 3434.
190 Transcript Vol. 21, para 21333: “MR. VAN HEYST: I would suggest given that I think pre- nomination, yes. Post-nomination we think the activity on that is probably not high enough to give a true accurate picture. So I think doing that comparison pre and post nominations from the index pricing is I think there's some pause for concern there. I think our trader's view is unless things are -- unless there's some, you know, other market activities on the go to otherwise, you know, is flat price rising, for example, from month to month, that generally, the post-nomination crude price is lower than the pre- nomination price.” (Emphasis added).
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value of the following trade month. In this case producers are still receiving a lesser value for their crude because they would also be able to capture the following month price if apportionment returns were not optional.
164. If there is apportionment, there is a limited timeframe (typically less than 10 business days) during which buyers and sellers must rearrange and balance their purchases and sales in order to meet Enbridge’s nomination deadline191] (for shippers) or revise production estimates in order to adjust feeder nominations for crude flow in the delivery month. Given the intense pressure to market barrels to a small number of purchasers, prices are generally below the trade month index.
165. Dr Church has grossly understated the level of apportionment returned barrels, and thus the impact to producers who must manage these pushbacks as indicated by both supporting and opposing intervenors in this hearing with actual market experience.
166. Ms. Day stated that:
But it’s safe to say that over the past year, we probably -- we think it’s around probably 25 to 30 percent returns on a 40 percent apportionment market. That would be like, kind of our best guess of how much we’re getting back.192
167. Mr Van Heyst supported this view:
MR. VAN HEYST: I would suggest given that I think pre-nomination, yes. Postnomination we think the activity on that is probably not high enough to give a true accurate picture. So I think doing that comparison pre and post nominations from the index pricing is I think there’s some cause for concern there. I think our trader’s view is unless things are -- unless there’s some, you know, other market activities on the go to otherwise, you know, is flat price rising, for example, from month to month, that generally, the postnomination crude price is lower than the pre-nomination price.193
168. Cenovus, a shipper who supports the Application, also agreed:
Right now, we have experienced underutilization of downstream pipelines that ranges from very small in one month to -- I can’t put my finger on a percentage, but when apportionment is 50 percent, you know, by -- depending on how we manage our business, it could be as much as that. Often, we use other methods to mitigate those risks and make that a little bit smaller, but we by sort of pure math could be as exposed to the 194 apportionment percentage level of impact and underutilization.
191 Written Evidence of the Canadian Shippers Group, PDF 18 and 20, Figure 1 and para 58 (C10237-2).
192 Transcript Vol. 19, PDF 68, para 19356.
193 Transcript Vol. 21, PDF 55, para 21329.
194 Transcript Vol. 14, PDF 139, para 14178.
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169. Therefore, contrary to suggestions by Enbridge, the pricing impacts in the post- apportionment market are very significant in terms of both price and volume for producers.
170. The CSG notes that a type of insurance market has evolved for WCS in the WCSB, called the X-APP market in which producers can presell their crude at a discount to the trade month index in order to avoid receiving pushback barrels and having to sell them in the post-apportionment market.195 Clearly, an insurance market like this would only evolve if there were persistent and significant risks of being in a position to continuously sell one’s barrels for lower prices in the post- apportionment market due to lack of access to WCSB egress.
171. Enbridge claims that Mainline Contracting will reduce apportionment.196 In fact, the MLC open season is likely to lock in the typical apportionment allocation currently experienced on a monthly basis for up to 20 years. Thereafter, the CSG expects that monthly apportionment will continue, and likely increase, under Mainline contracting.
172. It is expected that there will be significant competition for the remaining uncommitted capacity and, under current upstream and downstream verification procedures, even higher levels of apportionment would continue for the dramatically reduced amount of uncommitted capacity.197
173. The CSG notes testimony from refiners confirms that they expect apportionment will continue and therefore barrels will be pushed back after Mainline Contracting is implemented.
174. BP stated that, due to apportionment on the Mainline, it has “continually had to look for alternative feed stocks through different logistics options”, but declined to provide information about the frequency or percentage of volumes at which it pushes back barrels.198 BP acknowledged that pushing back barrels would continue to be an option to deal with apportionment from its perspective, subject to contractual terms, should Mainline contracting be implemented.199
175. Similarly, Cenovus confirmed that there could be circumstances under Mainline contracting in which spot capacity is apportioned and Cenovus might need to push
195 Transcript Vol. 19, PDF 70, para 19366; CSG Transcript Corrections – Volumes 17 – 20, PDF 17 (C13806-1).
196 Enbridge Response to CER IR No. 2, PDF 7 (C07648-2).
197 Written Evidence of the Canadian Shippers Group, PDF 29, para 84 (C10237-2).
198 Transcript Vol. 15, PDF 18, para 14443; PDF 19, paras 14446 – 144451.
199 Transcript Vol. 15, PDF 28-29, paras 14548 – 14549.
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back apportioned barrels to producers, or where Cenovus’ own barrels are pushed back.200
176. These shippers with significant DSV capability can ultimately push back barrels, initially designated for their committed capacity, each month due to the apportionment. Under a contracting framework, these parties would likely not be obligated to disclose how much capacity they won through the open season, how much firm capacity they have fulfilled from a volume purchase perspective already in the month and how much capacity they require in the spot market. They could look at each crude grade opportunistically and determine which grade would be the most price advantaged (or in other words, the most distressed relative to alternatives) to push back.
177. Nor would the Failure to Tender for Charge deter downstream shippers. Though nominations may be binding, with insufficient egress, downstream shippers would have the benefit of knowing excess supply would be available to purchase in the post-apportionment market.201
178. In summary, the CSG submits that the evidence is clear that prices are normally considerably lower in the post-apportionment market. Further, it is likely that apportionment will continue after Mainline Contracting were implemented and the percentage of apportionment on the remaining uncommitted capacity would likely be very high. Consequently, we can expect distressed prices for producers who are forced to place their barrels in the post-apportionment market under Mainline Contracting.
Adverse Impacts on Aggregators and Small to Mid-size Producers
179. Mainline contracting will be detrimental to small to mid-size producers in Western Canada as well as the Aggregators that enable them to market their production.202
180. The success of small to mid-sized producers is invaluable to the efficient development of WCSB resources as a whole because these producers bring innovative approaches to the industry, and tend to develop resources that larger producers may not, thereby maximizing the overall value of provincial resources.203 The viability of small to mid-sized producers is in the Canadian public interest, and often depends on successful collaboration with Aggregators.
181. Aggregators, such as Shell Canada, source crude oil production from many producers active in the WCSB and market their production to downstream
200 Transcript Vol. 14, PDF 96, paras 13724 – 13725.
201 Written Evidence of the Canadian Shippers Group, PDF 28 - 30, paras 83-92 (C10237-2).
202 Written Evidence of the Canadian Shippers Group, PDF 70 - 73, paras 224 - 238 (C10237-2).
203 Written Evidence of the Canadian Shippers Group, PDF 73, para 237 (C10237-2).
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customers. Many small to mid-size producers have historically relied on Aggregators to provide flow assurance and connect their production to downstream market hubs. 204
182. Aggregators serve an important role in a well-functioning oil market. Many of the smaller producers they contract with are unable to (a) independently manage the logistics of marketing crude oil in a complex North American oil market, or (b) meet the minimum shipping quantities or DSV requirements that the Mainline requires.205 Without Aggregators, many producers would struggle to market their product and the upstream oil and gas industry in the WCSB would become much less efficient than it is today.
183. Liquid market hubs, pricing transparency and open access to common carriage on the Mainline are critical elements of an Aggregator’s business model; each of these features is threatened by Mainline contracting. To the extent that Mainline contracting negatively impacts all three of these pertinent market components, the operations of Aggregators and the small to mid-size production they facilitate stand to be seriously and adversely impacted. There is a serious potential that many Aggregators could cease to operate under Mainline contracting because their value proposition would be compromised under Mainline contracting.
184. Oil and gas trading and marketing is a competitive and dynamic business. The market in which Aggregators operate has evolved such that the month-to-month placement of crude oil sales and nominations serves all parties well, in part because it best accommodates the variable production and demand profiles of producers, refiners and customers in a way that fixed long-term contracting does not.
185. Without access to common carrier export capacity, Aggregators and small to mid- size producers will have no choice but to either subscribe for long-term committed capacity, even though such commitments will be financially onerous and an unnatural fit to their business,206 or gamble that they will be able to access sufficient spot capacity for them to ship their volumes on the Mainline. On a potentially oversubscribed pipeline, this is a high-risk proposition. Irrespective of which strategy an Aggregator adopts, either option will increase the risk and cost of transporting hydrocarbons on the Mainline.207
204 EPAC Evidence to CER, PDF 42, para 115 (C10190-2). See also Transcript Vol. 22, PDF 14, para 22143.
205 See for e.g. EPAC Evidence to CER, PDF 42, para 115 (C10190-2).
206 Transcript Vol. 20, PDF 39, paras 19930 and 19933.
207 Transcript Vol. 20, PDF 41, para 19949.
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186. Aggregators do not typically have the balance sheet strength required to support 8- to 20-year transportation commitments208 and may be required to provide additional financial assurance to Enbridge in order to secure whatever pipeline capacity they are awarded,209 increasing the cost of doing business. In addition, the contracting options available to Aggregators under Mainline contracting,210 coupled with Enbridge’s DSV requirements, do not align with their operating models and will shift significant risk to Aggregators with no commensurate benefit.
187. The CSG notes that the impacts of Mainline contracting on Aggregators has received very little attention in this Hearing. Through the CSG, Shell Canada is one of the only Aggregators to participate in this Hearing. As a result, the CSG’s evidence concerning the impact of Mainline contacting on Aggregators comprises the majority of the record on this topic. Accordingly, the concerns outlined in paras 224 to 238 of the CSG’s Written Evidence remain valid and unrefuted. In particular:
(a) Mainline contracting pushes the risk of contracting onto Aggregators, including as a result of the possibility that Aggregators may be required to accept assignment of producers’ TSAs to maintain continuity of operations.211 But if an Aggregator takes assignment of a producer’s contract, they will (i) expose themselves to that producer’s liability to meet its obligations under the terms of its TSA, and (ii) bear the responsibility for any failure or default, the consequences of which may include having to make deficiency payments.212 This reallocation of risk will increase operating costs for Aggregators and producers, neither of which is a desirable or fair outcome.
(b) The limited contracting options outlined in the Application are not responsive to the unique features of the market in which Aggregators and small to mid-size producers are active. This lack of responsiveness will, in turn, make it difficult for such parties to meaningfully participate in a potential open season.213
208 Written Evidence of the Canadian Shippers Group, PDF 71, para 227 (C10237-2).
209 Written Evidence of the Canadian Shippers Group, PDF 72, para 232 (C10237-2).
210 I.e., to subscribe for 8- or 20-year committed transportation terms or Tranche 2 Flex contracts, or rely on uncommitted capacity and risk significant apportionment.
211 Written Evidence of the Canadian Shippers Group, PDF 71, para 231 (C10237-2).
212 Written Evidence of the Canadian Shippers Group, PDF 72, para 232 (C10237-2).
213 Written Evidence of the Canadian Shippers Group, PDF 72, para 232 (C10237-2).
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(c) Fewer counterparties and a reduction of nearly 3 million bpd of common carriage capacity will reduce liquidity at market hubs and decrease pricing transparency to the detriment of Aggregators and the market as a whole.214
188. Small to mid-size producers are valuable participants in the development of the WCSB, bringing innovation and dynamism to an industry that plays an important role in the Canadian economy.215 The potentially negative impacts of Mainline contracting on the Aggregators that market crude oil on their behalf are clear: increased business risk, higher costs and a more challenging business environment. The CSG is concerned that these impacts may serve to reduce the number of Aggregators operating in the WCSB, to the detriment of the market. Given the unique function Aggregators serve and the current value proposition that they offer, this is clearly not in the interest of small to mid-size producers in the WCSB, nor in the Canadian public interest.
Adverse Impacts on Shippers of Refined Products and NGLs
189. NGLs and refined products are transported exclusively on Line 1216 and, as a shipper of both classes of products on the Mainline,217 Shell Canada stands to be uniquely impacted by Mainline contracting. Its perspective in this respect is therefore distinct and important. Indeed, Shell Canada is the only shipper of NGLs involved in this Hearing, and is one of only four refined products shippers participating. As a member of the CSG, Shell Canada is strongly opposed to Mainline contracting, in part because of its adverse impact on Line 1 and Shell Canada’s ability to continue shipping NGLs and refined products in the manner its business requires.
190. As is clearly demonstrated by the lack of any support for Mainline contracting from any NGL shipper, and the opposition from all but one shipper of refined products218 Mainline contracting is not a market response to requests from these shippers, nor is it responsive to the commercial or operational needs of shippers that transport refined products and NGLs on Line 1. It is an unwelcome and unnecessary development. With respect (and as has been apparent since Enbridge first filed its Application), the proposed contracting of refined products and NGLs appears to be an afterthought to Enbridge’s desire to implement Mainline contracting and the
214 Written Evidence of the Canadian Shippers Group, PDF 72 - 73, paras 233-235 (C10237-2).
215 Transcript Vol. 20, PDF 39, para 19933; Transcript Vol. 22, PDF 21 - 22 and 33, paras 22191-22196 and 22289.
216 Transcript Vol. 2, PDF 98 - 99, paras 2361-2364.
217 Written Evidence of the Canadian Shippers Group – Appendix A, PDF 137, paras 1 and 5 - 8 (C10237- 2); Opening Statement of CSG, PDF 1, para 2 and footnote 1 (C13530-2); Transcript Vol. 17, PDF 37, paras 16854 - 16856.
218 Transcript Vol. 2, PDF 105 and 108, paras 2439 and 2474 - 2478.
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desire of a small minority of companies seeking to lock-in long-term commitments to ship heavy crude from the WCSB to PADD II and, to some degree, PADD III (Motiva, for example).219 From an NGL and refined products perspective, it is clear that this Application is a case of the crude oil tail wagging the NGL and refined products dog.
191. At section 8.2.1.3 of its Written Final Argument, Enbridge has attempted to cast the concerns of the CSG and those of CCRL/FCL as somehow irreconcilable or diametrically opposed and “illustrative of the tensions among shippers that Enbridge has encountered through the negotiation and the balancing required to arrive at the Mainline Contracting Offering”.220 This is incorrect. The concerns of Shell Canada/the CSG and CCRL/FCL are closely aligned. Both parties are concerned about the implications of the imposition of contracting on the availability of capacity on Line 1, an issue to which Enbridge appears to have paid almost no heed in advancing its Mainline contracting Application.
192. Under cross-examination, Enbridge confirmed that Line 1 has an expected operating capacity of 187,000 bpd.221 Assuming 100% contracting in an open season and based on an aggregate contracting limit of 165,000 bpd, Line 1 would only have spare capacity of approximately 22,000 bpd to accept spot nominations of additional volumes of any hydrocarbon product that the Mainline carries, whether refined products, NGLs or crude oil.222
193. However, if spot capacity is limited to 10% of the contracting limit for each of refined products and NGLs, the spare operating capacity of Line 1 will be limited to 5,500 bpd. While Line 1 has not historically been apportioned,223 in the event that both NGLs and refined products are fully subscribed, Enbridge would have little buffer to manage potential operating issues, such as future flow restrictions, while still providing the meaningful volumes of spot capacity that the CSG expects will likely be required given anticipated seasonal variances in demand for these products.224 Moreover, Enbridge has failed to adequately explain how spot volumes for NGLs and refined products will be allocated among shippers of refined products and
219 See Application, PDF 7 - 8, para 4 (C03823-2) in which Enbridge’s implicitly acknowledges that it is not possible to balance the interests of all stakeholders. See also CER IR 4.5 Attachment – Summary of Stakeholders Involved in Negotiations (C08985-6).
220 Enbridge Written Final Argument, PDF 67, para 198 (C13899-2).
221 Transcript Vol. 2, PDF 100, paras 2381; CER IR 2.36.b Attachment – Contractible Capacity Limits, PDF 1 (C07683-15).
222 CER IR 2.36.b Attachment – Contractible Capacity Limits, PDF 1 (C07683-15); Transcript Vol. 9, PDF 36, para 8361; Transcript Vol. 2, PDF 105, paras 2439 and 2474 – 2478.
223 Enbridge Reply Evidence, PDF 43 – 44, para 110 (C12447-2).
224 Transcript Vol. 19, PDF 24 and 37, paras 18991, 19085 and 19146; Transcript Vol. 22, PDF 49 and 69 – 70, paras 22445 – 22447 and 22667 – 22670.
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NGLs,225 giving rise to significant uncertainty regarding future flexibility and capacity constraints.
194. Exacerbating this uncertainty is the fact that the current tariff does not stipulate that Line 1 is limited to carrying NGLs and refined products. Instead, Enbridge confirmed that this is an “operational capability” and that the proposed Mainline contracting tariff will similarly not contain any such restriction or codify this practice.226
195. There is nothing that prevents Enbridge from changing its operating practices or the operational capability of Line 1. The CSG is concerned that if Mainline contracting is approved, Enbridge may be incentivized to shift additional light crude volumes to Line 1, which could potentially serve to limit its available capacity for refined products and NGLs. This concern is heightened in a scenario where NGLs and refined products are undersubscribed, which Enbridge has suggested is likely (despite limited evidence, other than Enbridge’s assertion, that this will be the case).
196. Enbridge suggests that there will be no real change to how NGLs and refined products are shipped, but has provided no assurance in this regard, effectively asking shippers to simply take their word that they will not introduce any new operational protocols. This reassurance rings hollow in the context of:
(a) an Application clearly driven by a desire to accommodate the interests of a limited number of heavy crude shippers, that was largely conducted without meaningful consultation with refined product or NGL shippers;227 and
(b) the fact that no party expressly requested contracting for NGLs or refined products, nor even indicated that the contracting of NGLs or refined products would be to their benefit or the benefit of the markets they serve.
In fact, the record is clear—Mainline contracting will likely function to the detriment of these shippers and the markets they serve.
197. As a result of the operational limits and uncertainties outlined above, Enbridge’s statement in its Reply Evidence that there will be “no restriction” on volumes that shippers can nominate on an uncommitted basis is not accurate.228 There is an
225 Transcript Vol. 2, PDF 103 – 105, paras 2411 - 2434.
226 Transcript Vol. 2, PDF 100 – 102, paras 2390 – 2392, 2397, 2400 – 2402.
227 Written Evidence of the Canadian Shippers Group, PDF 102-103, paras 317-321 (C10237-2); CCRL – FCL Written Evidence (December 7, 2020), PDF 10 – 11, paras 35 - 37 (C10225-2).
228 Enbridge Reply Evidence, PDF 43, para 111 (C12447-2).
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operational ceiling that is very close to the total capacity that Enbridge proposes to make available to refined products and NGLs for Mainline contracting.
198. The specific concerns of the CSG in respect of refined products and NGLs are discussed in greater detail below.
Impacts of Contracting on the Shipment of Refined Products
199. The CSG has outlined the adverse impacts that Mainline contracting will have on refined products in its Written Evidence.229 This evidence remains largely unrefuted on the record, other than Enbridge’s bare statement that certain of these “assertions are not supported by the facts.”230 However, the CSG notes that in Enbridge’s Reply Evidence, Enbridge limited its comments to the CSG’s evidence regarding apportionment despite the fact that the CSG’s Written Evidence goes beyond this specific issue.
200. As outlined in its evidence, the CSG submits that tolls for the shipment of refined products will increase under Mainline contracting, which increase will likely be borne by consumers in Saskatchewan and Manitoba.231
201. Costs for shippers and consumers could also increase if current or prospective shippers adopt game theory-based contracting strategies that may have the effect of reducing competition in the refined products market or create a more expensive secondary market, further increasing costs to consumers.232 While Enbridge has stated it does not encourage these practices233 and indicated that a potential secondary market could alleviate some of these concerns,234 there are no systems in place to prevent their use (and abuse), and game theory-based bidding being utilized in a Mainline contracting open season is clearly a risk that Enbridge and other interested parties have acknowledged in this hearing.
202. In light of the foregoing and considered alongside the CSG’s concerns regarding the operation of Line 1 and the lack of certainty regarding capacity and apportionment, the CSG submits that the terms of Mainline contracting proposed
229 Written Evidence of the Canadian Shippers Group, PDF 81 – 84, paras 260 – 266 (C10237-2).
230 Enbridge Reply Evidence, PDF 43, para 110 (C12447-2).
231 Written Evidence of the Canadian Shippers Group, PDF 81, paras 261 – 263 (C10237-2).
232 Written Evidence of the Canadian Shippers Group. PDF 81, paras 264 – 266 (C10237-2).
233 Transcript Vol. 6, PDF 91, para 6339; Transcript Vol. 9. PDF 17 – 19, paras 8188 – 8200.
234 As discussed in the evidence of Dr. Makholm, however, it is unlikely that the secondary market will be the panacea that Enbridge claims. See: Written Evidence of the Canadian Shippers Group, PDF 56, para 173; and PDF 78, para 252 (C10237-2). See also Transcript Vol. 19, PDF 28 – 30, paras 19023 – 19034.
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in the Application are neither desired by refined products shippers, nor are they in the Canadian public interest.
Impacts of Contracting on the Shipment of NGLs
203. In its Reply Evidence, Enbridge sought to rebut the CSG’s evidence regarding the impacts of Mainline contracting on NGLs, stating it is “noteworthy that the only two shippers of NGLs on the Mainline are not members of the CSG, and neither has opposed the Application.”235
204. While the two shippers of record have not intervened to oppose the Application, it is equally as noteworthy that they have not intervened to support the Application. Moreover, Shell Canada is a Mainline shipper that relies on the Mainline to transport approximately 8,000 bpd236 of NGLs from Western Canada to the Sarnia NGL Fractionation Facility.
205. Although Shell Canada is not a “shipper of record” in the manner that Enbridge sought to distinguish during cross examination,237 its interest in NGLs is not insignificant. Volumes shipped for Shell account for approximately 12% of the total NGL volumes currently transported on Line 1238 and equate to slightly more than 10% of total capacity available for NGLs under Mainline contracting.239 It is therefore incorrect to infer that Mainline contracting is not opposed by shippers of NGLs simply because the two shippers of record have not taken an active role in this Hearing. Moreover, Enbridge’s evasiveness and reluctance to acknowledge the existence of other NGL shippers during cross-examination does not mean that other parties, such as Shell Canada, do not have an interest that stands to be negatively impacted by Mainline contracting.240 To the contrary, though not currently a “shipper of record” of NGLs, Shell Canada nonetheless ships NGLs on the Mainline and, like non-shipper of record upstream producers, is very much an interested stakeholder in this proceeding.
235 Enbridge Reply Evidence, PDF 44, para 113 (C12447-2).
236 Opening Statement of CSG, PDF 1, para 2 and footnote 1 (C13530-2). See also Transcript Vol 17, PDF 37, paras 16854 – 16859.
237 Transcript Vol. 2, PDF 85, paras 2211 – 2218. See also Transcript Vol. 17, PDF 38 – 39, paras 16868 – 16878.
238 Opening Statement of CSG, PDF 1, para 2 and footnote 1 (C13530-2). See also Transcript Vol. 17, PDF 37, paras 16854 – 16859.
239 Appendix 17 – Open Season Procedures, s III(A)(4)(a), PDF 21 (C0823-19); Transcript Vol. 2, PDF 102, paras 2405 – 2406.
240 Transcript Vol. 17, PDF 39, paras 16880 – 16883.
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206. The Sarnia NGL Fractionation Facility is highly dependent on NGLs transported on Line 1.241 Because the facility sole sources its supply of NGLs from the Enbridge Mainline system, the contracting limits and minimal common carriage capacity will effectively lock-in the operational capabilities of the facility, failing to adequately accommodate the realities of seasonal variance and limiting future opportunities for growth.242 This lack of flexibility will have the likely effect of increasing operating costs at the Sarnia NGL Fractionation Facility. Not only does this shift the risk of contracting to facilities such as Shell Canada’s, but, coupled with the anticipated increase in tolls,243 it will likely have the effect of increasing costs for Canadian consumers.244
207. While Enbridge has attempted, unsuccessfully, to dispute the CSG’s Written Evidence concerning the anticipated de facto cap on nominations,245 it has failed to provide any evidence to demonstrate that Mainline contracting will not negatively impact operational flexibility and future opportunities for growth. In addition, Enbridge has not addressed the possibility of game theory-based contracting strategies (other than to state that it does not encourage these practices246 and to allude to the fact that a potential secondary market could alleviate some of these concerns247). Enbridge has also failed to address the increased costs that long- term contracting will impose on NGL facilities.
208. In light of the foregoing and considered alongside the CSG’s concerns regarding the operation of Line 1 and the lack of certainty regarding capacity and allocation, the CSG submits that the terms of Mainline contracting proposed in the Application are neither desired by, or responsive to the needs of, NGL shippers on Line 1, nor are they in the Canadian public interest.
241 Written Evidence of the Canadian Shippers Group, PDF 84, para 269 (C10237-2).
242 Written Evidence of the Canadian Shippers Group, PDF 84 – 85, paras 269 – 270 (C10237-2).
243 Written Evidence of the Canadian Shippers Group, PDF 81 – 85 (C10237-2).
244 Written Evidence of the Canadian Shippers Group, PDF 84 – 85, paras 270 – 271(C10237-2).
245 Enbridge Reply Evidence. PDF 44, paras 111 – 112 (C12447-2).
246 Transcript Vol 6., PDF 91, para 6339; Transcript Vol. 9, PDF 17 – 19, paras 8188 – 8200.
247 As discussed in the evidence of Dr. Jeff D. Makholm, however, it is unlikely that the secondary market will be the panacea that Enbridge claims. See Written Evidence of the Canadian Shippers Group, PDF 56, para 173; and PDF 78, para 252 (C10237-2). See also Transcript Vol. 19, PDF 28-30, paras 19023 – 19034; Transcript Vol. 22, PDF 16 – 19, 70 – 71 and 103 – 104, paras 22159 – 22163, 22167 - 22177, 22675 – 22682, 23040 – 23046.
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Adverse Impacts on Eastern Canadian Refineries
209. Eastern Canadian refineries rely almost entirely on the Mainline for their crude oil feedstock.248 Shell Canada’s Sarnia Refinery is one of these Eastern Canadian refineries that sources its feedstock exclusively from the Mainline.249 As a result, it is vulnerable to operational disruptions on the Mainline as well as the impacts of commercial changes, such as Mainline contracting.250
210. It is noteworthy that of the three Eastern Canadian refiners that are participating in this Hearing, only Imperial Oil Limited has expressed clear and unqualified support for Mainline contracting. However, Imperial occupies a relatively unique position in the Canadian oil market, with diverse affiliate refining capabilities and relationships in addition to a large producing stake in the WCSB.251 Imperial’s interests in Mainline contracting are not limited to its own interests, but arguably include those of its US-based controlling shareholder, ExxonMobil, and therefore extend well beyond the impacts of contracting on Imperial’s Eastern Canadian refineries.252
211. The terms of Mainline contracting that Enbridge has proposed require Eastern Canadian refineries that rely exclusively on the Mainline for their crude oil supply to lock-in a fixed volume commitment for 8 or 20 years, notwithstanding the operational challenges posed by seasonal demand swings, refinery upsets and maintenance requirements.253 This “one time gamble” detracts from the flexibility that the Mainline has historically offered and exposes these refineries to increased risk and uncertainty as well as complex logistical challenges.254
212. If a potential future Open Season results in an oversubscription of committed capacity (which the CSG and many of opposed parties believe is a likely outcome),255 Eastern Canadian refineries — and, indeed, all other committed
248 Written Evidence of the Canadian Shippers Group, PDF 74, para 242 (C10237-2).
249 Written Evidence of the Canadian Shippers Group, PDF 74 – 75, para 242 – 243 (C10237-2); Transcript Vol. 17, PDF 36, para 16847; Transcript Vol. 20, PDF 23 – 23, paras 18972 and 18988.
250 Written Evidence of the Canadian Shippers Group at PDF 74-75, para 242-243 (C10237-2); Transcript Vol. 20, PDF 23 – 23, paras 18972 and 18988.
251 Written Evidence of Imperial Oil Limited, PDF 2 – 3, lines 18 – 40; Transcript Vol. 16, PDF 19, paras 15585 - 15586.
252 Transcript Vol. 16, PDF 24-25, paras 15644 – 15655.
253 Written Evidence of the Canadian Shippers Group, PDF 76, para 244 (C10237-2).
254 Written Evidence of the Canadian Shippers Group, PDF 76, para 244 (C10237-2).
255 Application, PDF 18, paras 32 – 33 (C03823-2). See Transcript Vol. 19, PDF 31– 32, 42, 45 – 46 and 49, paras 19045, 19048, 19124, 19156 and 19181; Transcript Vol. 21, PDF 36, 46 - 47 and 49, paras
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shippers on the Mainline — will be subject to apportionment in the proposed Open Season. While theoretically fair, the possibility of apportionment is likely to incentivize potential shippers to adopt a sub-optimal game theory-based approach to bidding, which further increases the uncertainty in contracting and introduces unique challenges to Eastern Canadian refineries that require access to the Mainline, but also requires more flexibility than Mainline contracting will provide.
213. As highlighted in the oral testimony of Mr. Van Heyst on behalf of Suncor, contracting for chronically apportioned capacity in an open season that does not propose additional egress is a zero-sum game: “…if shipper x gets their needs, there’s a shipper y out there who’s not going to get what they want, and we have institutionalized that for 8 to 20 years.”256
214. It is also unlikely that, in the event of oversubscription, there will be sufficient spot capacity to provide the flexibility necessary for all of the Eastern Canadian refineries to maintain efficient operations. This could, at various times throughout the year, result in the oversupply or undersupply of refined products in local markets as well as increased costs to Canadian consumers.
215. While secondary markets might be a potential solution to some of these problems, they come with their own uncertainties, such as the fact that (a) any potential secondary market is currently entirely hypothetical since no viable secondary market for oil pipeline capacity currently exists in North America for pipelines connected to illiquid trading hubs,257 and (b) capacity in any secondary market that does materialize will likely be sold at a premium. In the event that Eastern Canadian refiners are not able to secure their desired capacity in a Mainline contracting Open Season and fail to successfully match their secured Mainline capacity to their operational needs, such that they are forced to seek capacity in a secondary market, this will likely both increase costs to Canadian consumers and result in a transfer of wealth out of Eastern Canada to the PADD II refineries that are better positioned, due to access to other supply alternatives, to bid in the Open Season and commit to long-term firm service contracts.258
216. Additionally, the terms and conditions of the contract hamper the flexibility and agility that is required to run a refinery optimally. A refiner can choose between Edmonton and Hardisty for injection points; it can also split volumes between the two injection sites. However, the Edmonton injection point is not as flexible as the Hardisty injection point as it will charge the full toll (for example Edmonton to a long
21660, 21247 and 21276 – 21277; Transcript Vol. 22, PDF 19, 20, 70, 74, 99, 107 and 110, paras 22180 – 22185, 22674, 22706 – 22709, 22989, 23070 – 23071 and 23107.
256 Transcript Vol. 21, PDF 37 – 38, para 21175.
257 Transcript Vol. 19, PDF 27 – 31, paras 19014 – 19040; Transcript Vol. 21, PDF 41 – 45, paras 21201 – 21233.
258 Written Evidence of the Canadian Shippers Group, PDF 78, paras 250 - 252 (C10237-2).
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haul destination) to the shipper even if that shipper injects at an injection point downstream of Edmonton.
217. On the other hand, if the same refiner elected to inject at Hardisty, and made the same movement from Kerrobert, it would pay the toll attributed to the long haul delivery point from Kerrobert. This difference in treatment between the injection sites will skew the demand for Hardisty over Edmonton and will create unbalanced apportionment levels at each location, during Open Season allocation. This can cause further costs to the refinery and force it to run suboptimally as it will not get the allocation of space, at the injection site from which it intends to receive from. Furthermore, if the refinery was to purchase crude from an injection location that is on the Lakehead system, after securing capacity on the Canadian Mainline through the Open Season, it would still have to pay the toll associated with its contractually elected injection location to its delivery location creating another suboptimal outcome for the refiner due to the deficiency burden that the shorter haul barrels would have to bear.
218. For the foregoing reasons, the CSG submits that, in the context of its adverse impacts on Eastern Canadian refineries, Mainline contracting is clearly not in the Canadian public interest.
VIII. CONTRACTED SERVICE IN THE ABSENCE OF NEW FACILITIES IS UNREASONABLE
219. Section 239(1) of the CER Act, also known as the “common carriage” provision, states:
239 (1) Subject to any regulations that the Commission may prescribe and any exemptions or conditions it may impose, a company operating a pipeline for the transmission of oil must, according to its powers, without delay and with due care and diligence, receive, transport and deliver all oil offered for transmission by means of its pipeline.
220. Section 239(1) obliges companies transporting oil via pipeline to receive, transport and deliver all oil offered for transmission by means of its pipeline. Common carriage ensures that all prospective shippers have equal access to pipeline systems and ensures that there will not be any discrimination between shippers based on their business circumstances. By virtue of being a CER regulated oil pipeline, the Mainline is subject to the common carriage provision.
221. In his direct evidence, Mr. Priddle reviewed the significant cases in which the NEB approved contract carriage on oil pipeline facilities. Mr. Priddle identified four common ‘markers’ which were present in almost all these cases, including whether:
(a) there was a linkage between the toll application and new facilities;
(b) the application would result in new markets being served;
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(c) contract carriage was being requested to support new facilities construction; and
(d) the application for contract carriage was unopposed by oil producers.
222. None of these markers are present in Enbridge’s Application.259
223. Enbridge has argued that the precedents and markers identified by Mr. Priddle are irrelevant.260 Enbridge is effectively arguing that it is irrelevant that: i) no new facilities or services are being offered; ii) there is broad opposition to the Application; and iii) there is substantial evidence on the record that Mainline Contracting would be detrimental to the Canadian public interest. The CSG submits that Mr. Priddle’s evidence on previous instances in which contract carriage has been granted is in fact highly relevant to the current Application.
224. Enbridge also has referred repeatedly to the unique circumstances around Trans Mountain’s Westridge dock as providing a precedent for approving firm service without providing new services or facilities. In fact, as noted in Mr. Priddle’s evidence, the Westridge dock is a very unique case:261
(a) firm service was required for operational reasons to ensure that deliveries to the dock would match tanker capacities;
(b) the Application was supported by the vast majority of parties, was found to be in the public interest, and was for only 18% of Trans Mountain’s capacity; and
(c) the excess revenues from the firm dock service were required to be set aside as capital for future expansion that would benefit all shippers.262
225. Importantly, the Westridge dock case involved contracting only 54,000 bpd versus the proposed contracting of 2,760,000 bpd sought by Enbridge. For comparison sake, these volumes equate to roughly 1.3% and 63% of total pipeline egress from the WCSB, respectively. The circumstances of the Westridge dock case bear absolutely no resemblance to this Application and the difference in the order of magnitude of the proposal is staggering. The CSG submits that the basis on which the Board approved firm service in the Westridge dock case are inapplicable to this Application, and provide no basis for its approval.
259 Written Evidence of Mr. Roland Priddle, PDF 42 (C10237-5).
260 See Enbridge Written Final Argument, PDF 31, paras 86 – 88 (C13899-2).
261 Written Evidence of Mr. Roland Priddle, PDF 43 (C10237-5).
262 NEB Reasons for Decision, RH-002-2011 (C13524-26).
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226. In contrast to Enbridge’s Application, Mr. Priddle’s carefully documented matrix of all other cases clearly demonstrates that there are no reasonable precedents to support a conversion to contract carriage in the absence of new facilities and in the face of widespread opposition from a broad range of stakeholders.263
227. Throughout the NEB’s history,264 when considering a departure from uncommitted to firm service, the NEB only did so in the context of new capacity or service offerings. Indeed, the NEB confirmed that the common carriage obligation may be met where an appropriate open season is held for new facilities or services and sufficient capacity is made available for uncommitted volumes:
While the Board has broad discretion in assessing compliance with subsection 71(1), the Board has indicated in previous decisions that an oil pipeline may meet its common carrier obligations when an appropriate open season is conducted for new facilities or services and sufficient capacity is made available for uncommitted volumes.265
228. Since 2005, the NEB has recognized the issue of insufficient egress on the Enbridge system, and consequent effects on prices for WCSB crude.266 The Application does not increase capacity which might ensure that sufficient uncommitted space would remain available to meet demand. The Application does not fit within the circumstances in which the NEB has found it appropriate to sanction firm service, and is counter to Enbridge’s common carriage obligation.
229. In the U.S., the FERC too has denied previous attempts to shift from common carriage to contract carriage precisely because no new capacity was offered. In the Colonial decision, FERC succinctly described Colonial’s proposal as creating two classes of shippers, committed and uncommitted, out of one class of shippers who were currently receiving the same service on existing capacity, as “unduly discriminatory”.267
230. The circumstances in Colonial are substantially the same as those at issue in this Application. Enbridge’s proposal to switch from common carriage to firm service is unjustly discriminatory because it will reclassify existing shippers on an existing facility. As the NEB has done, the FERC has previously approved contract rates
263 Written Evidence of Mr. Roland Priddle, PDF 42 and 55 - 57 (C10237-5).
264 An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts, SC 2019, c 28, s 33: Every decision or order made by the NEB is considered to have been made under the CER Act and may be enforced as such.
265 NEB Reasons for Decision RH-2-2011 – Trans Mountain Pipeline ULC on behalf of Trans Mountain Pipeline LP at 25 – 26 (Emphasis added).
266 See NEB Reasons for Decision RH-1-2005 – Enbridge Pipelines Inc. (June 2005).
267 Colonial Pipeline Co., 146 FERC 61, 206 (2014), at 12.
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but only where necessary to, “among other things, determine support for construction of the project, obtain financing, ensure the initial financial viability of the project, or to determine the support in new or growing markets.”268 Enbridge is not proposing any new services or facilities. The pipeline at issue in Colonial, like the Mainline, had a history of apportionment. The CSG submits that the FERC’s reasoning in Colonial is persuasive in this case and is directly applicable to the Mainline.
231. In its application, Enbridge attempts to justify its proposal to switch to 90% firm service by citing examples of where, in its view, oil pipelines have implemented firm capacity on existing facilities.269 However, in each of the cases cited by Enbridge, additional capacity or a new service, including a change in direction, was being offered. None of the cases cited by Enbridge allowed for a conversion to contract carriage in the absence of a new service offering, capacity expansion or new market access. Therefore, Enbridge’s proposal to switch from zero to 90% long-term firm service contracts is not consistent with its common carrier obligations under section 239(1) of the CER Act.
232. Previous applications for firm service have been made in direct connection with additional capacity on new pipeline facilities, as was the case for the Trans Mountain Expansion Project (RH-001-2012) and the Keystone XL Project (OH-1- 2009). Both of those applications were made in the context of proposed new facilities that required substantial financial commitments by shippers and the pipeline company in order for those projects to proceed. There is no new capacity or services, apart from the firm service itself, proposed in the current Application for the Canadian Mainline.
233. Enbridge argues that while it “is not applying for approval to construct ‘new facilities’, it is applying for approval to introduce a ‘new service’ on the Canadian Mainline, namely firm service.”270 It is circular for Enbridge to argue that its proposal for committed service is justified on the basis that the service it is offering is committed service. Requiring potential shippers to make long-term, significant and irrevocable financial commitments, when the pipeline company is not offering new capacity or facilities, does not constitute a new service.
IX. CONTRACTED SERVICE WOULD RESULT IN THE CREATION OF TWO CLASSES OF SHIPPERS AND UNDUE DISCRIMINATION
234. Implementing firm service contracts on 90% of the Canadian Mainline’s capacity will create two shipper classes and result in undue discrimination between those classes.
268 Colonial Pipeline Co., 146 FERC 61, 206 (2014), at para 35.
269 Application, PDF 22, para 38 and footnote 38 (C03823-2).
270 Letter to CER re Enbridge Response to CNRL Motion to Dismiss Application, PDF 7 (C08566-1).
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235. Dr Makholm describes the two classes of shippers that Mainline Contracting will create as follows:
(a) “those private downstream shippers, primarily those with refining assets located in PADD II willing to absorb the burden of contracting (because they perceive an associated private benefit)”, and
(b) “those WCSB producers, aggregators, and Canadian refiners who are opposed to having to do so (despite being offered contracts in an “open season”)”.271
236. Those in the first class of shippers will benefit from priority access to ship their volumes in a context of scarce egress capacity. At the same time, these shippers would collect the difference between the tolls that they pay for contracted Mainline capacity and the cost of the next transport alternative – be that the Mainline toll for uncommitted service, or the cost of rail transport – in the form of lower feedstock costs or reselling excess capacity at a premium. Those in the second group would pay more either in the form of spot toll premiums, or in what Enbridge calls a “secondary market” – a market that does not currently exist and that would be entirely unregulated - where those who have taken contracts will likely be able to re-sell capacity at a premium.
237. Uncommitted shippers will not only pay more but they will be subject to likely-high rates of apportionment with just 10% of the Mainline’s capacity reserved for uncommitted service. Uncommitted shippers that can only find capacity by sub- contracting from those that hold contracts on the Mainline will be exposed to potentially significant premiums to secure necessary market clearing capacity, in addition to other impactful terms dictated by such contract holders. As proposed by Enbridge, the Commission will have no means to regulate this anticipated “secondary market”.
238. Due to the unique configuration of the Mainline, downstream shippers have a structural advantage in obtaining capacity and participating in crude oil sales off the Mainline.272
(a) As described in the Caltex letter of comment,273 the mandatory supply verification and destination verification requirements for a firm shipper to access their firm capacity creates an unlevel playing field, providing shippers possessing DSV supply price negotiating power over those that do not possess DSV.
271 Written Evidence of Dr. Jeff Makholm, PDF 8 (C10237-4).
272 Written Evidence of the Canadian Shippers Group, PDF 36 – 40, paras 106 – 113 (C10237-2).
273 Letter of Comment from Caltex Resources (C04424-1).
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(b) Producers who sign for capacity in the Open Season will still have to find a buyer at a downstream delivery point within the contracted service haul. However, the number of counterparties are very limited.
(c) Downstream parties will be aware that producers need a market in order to ship, resulting in an uneven balance of negotiating power between capacity holders with significant DSV and those without.
(d) If a producer does not find a buyer, the space will revert to being uncommitted space. The producer will still be burdened with making payments on toll obligations associated with unutilized firm capacity.
239. The CSG is of the view that Enbridge’s proposal would create two classes of shippers, resulting in clear discrimination between shippers. Importantly, Enbridge has failed to justify this discrimination.
240. Enbridge has not advanced any plausible public interest reasons why the proposed discriminatory tariffs would render the discrimination ‘just’. On the contrary, the CSG and other parties, including EPAC and the Government of Saskatchewan, have adduced extensive evidence as to why the Application would result in negative outcomes with regard to the Canadian public interest.
X. THE PROPOSED OPEN SEASON PROCEDURES AND TSA TERMS ARE UNREASONABLE AND UNJUSTLY DISCRIMINATORY
241. The terms of the proposed TSAs are unreasonably one-sided in favour of a subset of shippers and Enbridge to the detriment of Canadian-based producers, aggregators and some Canadian refiners. In a competitive market, where shippers have multiple options to deliver their products to market, carriers must offer more balanced contractual arrangements to compete and attract volumes.274 However, given the scarcity value of the Mainline, Enbridge is not driven by market forces to offer TSAs that evenly balance risks and costs. This is evident from the terms of the TSAs, which do little to accommodate producer interests and shift risks to shippers (primarily producers) and away from Enbridge. In addition, the Open Season procedures will result in oversubscription and gaming.
242. As set out in detail in the CSG’s written evidence,275 there are two main areas in which the TSAs are unreasonable, unjustly discriminatory, constitute an exercise of market power, and/or are contrary to the Canadian public interest, namely:
274 For e.g. the NEB has approved competitive service offerings on TransCanada Pipelines Limited (“TCPL”) Mainline gas pipeline system, most notably in NEB Reasons for Decision RH-003-2011 (C13524-25) in which TCPL was first granted pricing discretion in the face of underutilization and declining volumes.
275 Written Evidence of the Canadian Shippers Group, Chapter VIII, PDF 43-61 (C10237-2).
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(a) the TSA terms unreasonably restrict producer flexibility while at the same time favouring the needs of US refiners and certain integrated companies; and
(b) the TSAs are unreasonably one-sided in favour of Enbridge, demonstrating Enbridge’s exercise of market power.
243. Rather than developing an offering that would provide value and be responsive to the needs of producers and other non-supporting stakeholders, the proposed TSAs would severely limit producer flexibility. At the same time, Enbridge would stand to profit from any steps taken by shippers to exercise the minimal remaining flexibility afforded to them. There are insufficient costs/risks to Enbridge to justify these gains, at the direct expense of the Canadian upstream industry, resources owners, and others.
Over-subscription and Gaming Expected in Open Season
244. Oversubscription in the proposed Open Season is very likely. This conclusion can easily be drawn based on the current high levels of apportionment on the Mainline,276 and for the reasons set out in detail in the CSG’s Evidence. During cross-examination, it was established that: Cenovus could contract for approximately 820,000 barrels/day of Mainline capacity based on its use of the Refinery Requirements Contracts, Producer Requirements Contracts and a Take or Pay Contract; BP, using these same contracts, could contract for approximately 570,000 barrels/day; and Imperial, again using these same contracts, could contract for approximately 869,000 barrels/day.277 These three companies alone could contract for significantly more than 2 million barrels a day of Mainline capacity based on the limits set by Enbridge in the Open Season Procedures.278
245. As a result of this expectation of over-subscription, the CSG expects that many shippers may be incented to request more committed capacity than they expect to be awarded, increasing overall pro-rationing in the primary market for capacity and reducing the likelihood that any one shipper will obtain the capacity it needs.
246. Some parties may have the incentive and ability to over-nominate in the Open Season with the goal of being awarded more capacity than they typically need for their operations to seek an advantage in marketing their excess capacity at a
276 See CER IR 1.11.a.2 Attachment – Enbridge Mainline Apportionment (C06801-19) showing heavy apportionment between 49% and 53% in January – March, 2020; Reply Evidence of Neil Earnest, PDF 27 (C12447-9) showing heavy apportionment on the Mainline above 30% in January 2021; Transcript Vol. 19, PDF 42, para 19126, CSG Transcript Corrections - Volumes 17 – 20, PDF 13 (C13806-1) (Currently, 52% apportionment for heavy).
277 Transcript Vol. 14, PDF 46 – 55, paras 13174, 13178, 13186, 13274, 13278, 13280, 13282, 13287 and 13294 (Cenovus); Transcript Vol. 15, PDF 14 – 17, paras 14388-14395, 14396-14401, 14411 and 14430-14431 (BP);Transcript Vol 16, PDF 23 and 27, paras 15630-15631 and 15674-15675 (Imperial).
278 See Appendix 17 – Open Season Procedures, PDF 15 (C03823-19).
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premium.279 Certain parties (such as those with multiple assets or both production and refining capabilities) are better suited than others to maximize their Open Season bids should they choose to do so.
247. On the other hand, likely over-subscription may effectively force shippers with downstream pipeline commitments to bid for more capacity than they require to achieve a pro rata award that fits their needs (e.g. matches their Flanagan South Pipeline commitment), and will be very unlikely to secure the “correct” amount of Mainline capacity.
248. In the Hearing, Ms. Day described the impossible position that Canadian shippers would be in when deciding whether or not to participate in the proposed Mainline open season, if approved.280 This evidence supports the unavoidable conclusion that it is unreasonable and contrary to the public interest to allow scarce Mainline capacity to be held by a small subset of shippers for up to 30 years under what essentially constitutes an unfair auction process.281
TSA Terms Favour Shippers Able to Make Large Volume Commitments
249. The proposed TSA terms and conditions are clearly designed to favour shippers with large downstream refinery assets. Generally, these shippers are US-based PADD II refiners that value long-term secure supply of discounted Canadian crude and certain integrated companies with significant DSV capabilities.282
250. For example, the proposed volume discounts available under Enbridge’s proposed TSAs are generally only available to large refiners and the large integrated companies. Conversely, only one pure producer is large enough to qualify for volume discounts and integrated companies.
251. Another example is the proposed procedure for allocation of capacity in the likely event of over-subscription, whereby allotment on each haul will occur on a pro-rata basis. The result is an unfair advantage for integrated companies that can subscribe for service under Refiner RC, Producer RC, and Take-or-Pay TSAs, providing the ability to request capacity far exceeding their requirements and thereby potentially being able to secure sufficient capacity notwithstanding oversubscription.
279 Transcript Vol. 18, PDF 35, paras 18149-18150.
280 Transcript Vol. 16, PDF 114, paras 16549 – 16554.
281 See Dr. Carpenter’s comments at Transcript Vol. 21, PDF 38, para 21179.
282 Written Evidence of the Canadian Shippers Group, PDF 44, para 128 (C10237-2).
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Parties’ Intentions to Subscribe for Firm Service Are Not Indicative of Fair and Balanced TSA Terms
252. As their support for the Application demonstrates, most PADD II refiners and integrated companies connected to the Mainline are uniquely positioned to contract for the maximum 20-year contract term length in order to secure long-term feedstock. Conversely, the uncertainty of future production rates and commodity markets make it difficult for upstream producers to lock themselves in to such large, long-term financial commitments.283
253. Despite the unfavourable terms, some parties would feel compelled to participate in Mainline contracting if it were to be approved.284 Enbridge would prefer to characterize this as an “economic decision” made through shippers’ exercise of “free will”.285 However, evidence in this proceeding clearly shows that shippers have no viable alternative. Choosing not to enter contracts presents often intolerable economic risks. As Mr. Varsanyi stated in the hearing, no one (supporters nor opponents of the application) has said they will solely use uncommitted capacity if contracting is approved.286 This demonstrates that shippers who will suffer under contracting relative to their current position nonetheless feel they have no option but to enter contracts, due to Enbridge’s dominant position and market power.
254. The fact that only 2 of the 66 producers that have signed confidentiality agreements regarding Mainline contracting support this application287 demonstrates that participation does not signal support. Many producers may participate in contracting against their preference. Other parties have indicated that if Mainline contracting were to be approved they may participate – this may be because they have no choice. Enbridge’s Mr. Varsanyi has stated that both CITGO Petroleum Corporation and Husky Energy have expressed support for the
283 Written Evidence of the Canadian Shippers Group, PDF 44, para 128 (C10237-2).
284 CSG Responses to Enbridge IR No. 1, PDF 51 (C11771-2); MEG Response to Commission IR No. 1, PDF 4 (C11753-2). See also Transcript Vol 19, PDF 21 – 22, para 18966.
285 Transcript Vol. 6, PDF 81 – 82, para 6250; Transcript Vol. 3, PDF 28, para 2751.
286 Transcript Vol. 6, PDF 14, para 5613.
287 Transcript Vol. 2, PDF 31, paras 1553 – 1554.
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Application. 288 However, this assertion is contrary to the evidence on the record of this proceeding.289
255. Mr. Varsanyi has since acknowledged that CITGO made submissions to the CER in September 2019 asking for the open season to be suspended.290 In that 13- page submission, CITGO wrote:
Enbridge is seeking to exercise its market power specifically to de-risk its position at the expense of its effectively captive shippers, while it is the only game in town and prior to the future emergence of competing 291 capacity.
256. CITGO’s letter included in Enbridge’s Updated Appendix 4, purportedly as a letter of support, in fact states nowhere that CITGO supports the Application. Rather, it states that should the Application be approved, “CITGO intends to participate for committed services under the open season procedures.”292 The evidence is that CITGO intends to participate in the open season if it is approved – despite its concerns that Enbridge is seeking to exercise its market power – because the Enbridge Mainline is “the only game in town”.
257. In Husky’s September 5, 2019 letter to the Commission it wrote “Husky is generally opposed to the conversion of Enbridge’s Mainline from uncontracted common carriage to contract carriage”. The letter goes on to say that “converting the Mainline to contract carriage would not be fair, just or reasonable to shippers” and “Enbridge’s attempt to convert the Mainline to contract carriage is an unfair exercise of market power.”293
258. Mr. Varsanyi undertook to provide a reference to where in the record Husky changed its position from opposition to support. His response to this undertaking simply states “Enbridge can confirm that Husky did not file a letter with the
288 Respecting CITGO, see Updated Appendix 4: Shipper Support Letters, PDF 14 (C03831-2); Transcript Vol. No. 2, PDF 32, para 1572 – PDF 33, para 1578. Respecting Husky, see Transcript Vol. No. 5, PDF 96 – 98, paras 5480 – 5502.
289 Respecting Husky, see Submissions of Husky Inc., PDF 2 (C04421-1); C01489-1 Husky Oil Operations Limited Letter to CER re Enbridge Mainline Open Season, PDF 2 and 4 (C13222-3).
290 Transcript Vol. 2, PDF 33, paras 1581 – 1582 (C13204-1).
291 Transcript Vol. 2, PDF 33, para 1583 – 1585 (C13204-1).
292 Updated Appendix 4: Shipper Support Letters, PDF 14 (C03831-2).
293 C01489-1 Husky Oil Operations Limited Letter to CER re Enbridge Mainline Open Season, PDF 2 (C13222-3).
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Commission advising that it had changed its position regarding Mainline Contracting.”294
TSAs Reflect Enbridge’s Abuse of Market Power
259. The TSA terms and conditions as a whole also reflect Enbridge’s abuse of market power. As discussed above, Enbridge’s discussions with a subset of shippers prior to the 2019 Open Season led to proposed TSA terms that tilt unreasonably in these supporting shippers’ favour. Enbridge’s dominant market position has enabled the company to garner support for Mainline contracting by devising an offering despite the unbalanced contractual terms on offer.
XI. THE PROPOSED TOLLS AND TOLL METHODOLOGIES SHOULD BE REFLECTIVE OF COST OF SERVICE AND TOLL PRINCIPLES
Tolls Should Be Cost-Based
260. The requirement that tolls should be cost-based is a principle295 that has been relied upon throughout the history of pipeline regulation in Canada, extending back to the regulation of IPL, Enbridge’s predecessor. In the Reasons for Decision in the Matter of Interprovincial Pipe Line Limited, Application, dated 5 September 1986, RH-4-86 the NEB stated that:
A principle which the Board has attempted to apply in the development of the appropriate toll design methodology for IPL is that the resultant tolls should be, to the greatest extent possible, cost based. In other words, generally speaking the concept of “user-pay” should be applied. The Board recognizes that due to such things as practical considerations and limitations on cost allocation procedures, no toll in practice will be absolutely cost-based, in the sense that it will precisely and completely reflect all expenditures related to a particular service over a precise distance. However, designing IPL’s tolls to be as cost-based as practicable should yield the result that the users of the system bear the financial responsibilities for the costs caused by the transportation of their particular hydrocarbon through the line.296 [Emphasis added.]
261. The approach adopted by the NEB to design tolls to be “as cost-based as practicable” is appropriate and reasonable as it results in the users of the system
294 Enbridge Response to Undertaking 3, PDF 1 (C13261-2).
295 In NEB Reasons for Decision RH-1-2007 – Trans Canada PipeLines Limited, Chapter 3 at PDF 33 – 35 and 37, the Board used the phrase “guiding principles and key considerations”. These included: the requirements of the Act, cost-based tolls, no acquired rights, economic efficiency, and the degree of integration and nature of service. Secondary considerations were: practicality, toll stability and administrative simplicity.
296 NEB Reasons for Decision RH-4-86 – Interprovincial Pipe Line Limited (June 1987) at 48. Note: Although correctly identified on the cover page as “RH-4-86” the decision is confusingly marked as “RH-2-88” at the bottom of each page. (Emphasis Added).
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bearing the just and reasonable costs caused by the transportation of their products and also respects the user-pay principle. While the Commission has discretion to determine what constitutes just and reasonable tolls in the specific circumstances of an application before it, cost of service remains the best method for evaluating the justness and reasonableness of proposed tolls in the context of a contested application by a pipeline with market power. It is the industry norm for regulated monopolies.297
262. Not only do cost-based tolls ensure that the user pays its fair share of the service, it also provides a necessary check and balance between the pipeline and the shipper when there is a non-functioning market or there is disproportionate market power, such as the current situation caused by the lack of egress from the WCSB.
263. In the above IPL decision the Board explained the importance of a toll setting principle as follows:
Considerable discussion took place during the hearing concerning the various factors which the Board should consider in its deliberation of toll methodologies designed to achieve just and reasonable tolls. Some parties characterized all of these considerations as principles, while others attempted to divide them into various categories, such as principles and objectives. The Board is cognizant of this latter distinction to the extent that a principle is something from which one should not easily be diverted, while an objective, although desirable, should not be accommodated at the expense of compromising overriding principles.298 [Emphasis added.]
264. The Board went on to confirm the importance of consistently applying established principles in order to achieve just and reasonable tolls.
The complexity of the issues and the conflicting positions advocated by the various parties confirm that, when dealing with toll design, the Board must be aware of and attempt to apply consistently the principles which it views as resulting in just and reasonable tolls. A toll design methodology should also be able to withstand the test of a range of cost and throughout (sic.) scenarios to ensure that it consistently yields reasonable results. The Board also recognizes nonetheless that a toll design decision cannot be static, when the environment is constantly changing. On the other band (sic.), the Board is of the view that it is not appropriate to develop a toll design on an ad hoc basis, which will not withstand an application of the criteria discussed above.299 [Emphasis added.]
297 See Written Evidence of Drazen Consulting, PDF 7 – 9 (C10237-3).
298 NEB Reasons for Decision RH-4-86 – Interprovincial Pipe Line Limited (June 1987) at 48 (Emphasis added).
299 NEB Reasons for Decision RH-4-86 – Inter Provincial Pipe Line Limited (June 1987) at 47 (Emphasis added).
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265. The principle of cost-based tolls has been followed in many NEB decisions300 and is as compelling and applicable today as it was in the initial days of regulation of the Enbridge Mainline. In a recent Letter Decision dated 7 April 2021301 regarding a toll application by Campus Energy Partners Suffield LP, the Canada Energy Regulator confirmed that for matters relating to the establishment of just and reasonable tolls it would be guided and informed by the previous direction of the Courts and prior NEB cases. It stated at page 7:
Other than a small change to modernize language, section 230 of the CER Act is the same as the previous section 62 of the NEB Act considered by the Courts. There continue to be no statutory rules which restrict the Commission’s authority to set just and reasonable tolls. For these reasons, the Commission is of the view that previous direction from the Courts regarding the toll and tariff provisions of the NEB Act continue to have direct application to the CER Act and to the Commission. Past NEB cases such as Alliance are also informative. The overarching requirement is that tolls must always be just and reasonable. The Commission has wide discretion regarding the factors to consider in assessing the justness and reasonableness of tolls. [Emphasis Added].
266. In contrast to objectively determined cost-based tolls grounded using fundamental rate-making principles, Enbridge proposes long-term tolls that are derived from an opaque and unsupported base toll amount of $5.70 USD that predominantly meets the needs of one class of stakeholder, the US based refiners. Tolls and tariffs must be equally just and reasonable for all stakeholders, and not developed to benefit one group of shippers who will be uniquely advantaged. In the absence of a broad- based settlement the Commission should not be diverted from the principle of cost- based tolls.
The Commission’s Requirement for Cost of Service Rate-Making
267. Cost of service is the default process for reflecting cost-based tolls, as indicated in the Commission’s current guidance. The CER Filing Manual provides:
A Group 1 pipeline company not regulated on a complaint basis (see footnote 16 in Guide R) that has not reached a negotiated settlement with its interested parties is regulated on a cost-of-service basis and
300 See NEB Reasons for Decision, RH-1-2007 – TransCanada Pipelines Limited (July 2007) at 21 in which the Board reaffirmed this principle: “A principle referred to in many Board decisions is that tolls should be, to the greatest extent possible, cost based and that the users of a pipeline system should bear the financial responsibility for the costs caused by the transportation of their product through the pipeline. This is often referred to as the cost-based/user-pay principle, which the Board views as a single toll- making principle.” See also NEB Letter Decision RH-001-2018 – TransCanada Pipelines Limited (13 December 2018) at 17.
301 CER Letter Decision RH-002-2020 – Campus Energy Partners Suffield LP (7 April 2021) at 7.
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is required to provide the information outlined in the filing requirements within sections P.1 to P.5 of Guide P.302
According to the Commission’s direction, in the absence of a negotiated settlement, it is mandated that tolls should be determined on a cost of service basis.
268. A cost of service review is guided by established rate making principles including cost-based tolls:
(a) Cost-based tolls are a rate making Principle (“A principle is something from which one should not easily be diverted”).303
(b) The Board has stated that tolls should be, to the greatest extent possible, cost-based.
(c) Toll stability is a “desirable objective” but not one of the principles used by the NEB to evaluate and set just and reasonable tolls.304.
(d) In determining just and reasonable tolls, although the Board is not bound to use a cost-of-service methodology, the NEB’s practice has been to establish a revenue requirement based upon the costs expected to be incurred in respect of regulated activities305.
(e) Under the cost of service methodology, the pipeline has no opportunity to recover more than the costs that it incurs to provide service. However, the corollary is that the pipeline is protected by cost of service as it has a reasonable opportunity to collect its prudently incurred costs.
269. In its Campus decision the CER discussed the regulatory framework to set tolls pursuant to the CER Act and determined that although it is not bound by any specific methodology to determine whether tolls are just and reasonable it could expressly consider cost of service information. The Commission stated:
Courts have previously emphasized the broad authority and discretion of the NEB to decide whether a proposed toll is just and reasonable…In
302 The CER Filing Manual, (Filing Manual) (Emphasis added).
303 NEB Reasons for Decision RH-4-86 – Interprovincial Pipe Line Limited (June 1987) at 48 (Emphasis added).
304 NEB Reasons for Decision RH-1-2007 – TransCanada PipeLines Limited (July 2007) at 23. The NEB stated: “Other toll methodology considerations raised by parties in past Board hearings are practicality, toll stability and administrative simplicity. While the Board found these to be useful considerations, it did not find them to be the primary ones in arriving at just and reasonable tolls.” See also, Transcript Vol. 10, PDF 105, paras 9983 – 9984 in which Enbridge’s witness, Mr. Reed, agreed that toll stability was not as critical a consideration as cost-based tolls.
305 NEB Letter Decision RH-001-2018 - TransCanada PipeLines Limited (13 December 2018).
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considering Part IV of the NEB Act, the Federal Court of Appeal stated that the NEB was given ‘authority in the broadest possible terms to make orders with respect to all matters relating to [tolls and tariffs].’…In other words, the NEB or the Commission as it is now, may consider cost of service information but there is no requirement to consider the just and 306 reasonableness of tolls using this methodology.
270. Although the Commission is not obligated to employ a cost of service evaluation, it is clear that a cost of service review remains an important tool available to the Commission to set just and reasonable tolls. In the absence of a negotiated settlement, having regard to Enbridge’s substantial market power, a cost of service review is appropriate to determine just and reasonable tolls on the Mainline.
A Cost of Service Review is Necessary
271. A foundational issue in the Application is whether cost of service is relevant to determining Mainline tolls. Enbridge’s answer is a simple and emphatic “no”.307 Enbridge did not consider nor refer to any cost-of-service information in setting the proposed tolls. Enbridge certainly had the information, but chose not to use it.
272. When the CER requested Enbridge to file cost of service information to respond to CER IR 1 Enbridge did so, but it used assumptions and methods that conflict with standard regulatory practice and conflict with existing agreements Enbridge itself had made with shippers. These assumptions are critiqued in the Drazen evidence.308 Although the lack of cost-of-service data precluded a rate-hearing- quality analysis, the Drazen work shows that the Concentric study commissioned by Enbridge significantly overstates the cost of providing service, and in particular overstates the Lakehead system costs by ignoring the FERC-approved tolls in favour of Concentric’s own postulated costs.309
273. The CSG is not asking the CER at this time to make a definitive finding as to the Canadian Mainline cost of service. Both Drazen and Concentric have indicated that the cost information available at this time is “not rate case quality”310. Rather,
306 CER Letter Decision RH-002-2020 – Campus Energy Partners Suffield LP (7 April 2021) at 6.
307 Revised Additional Written Evidence, PDF 17 (C07662-2): “Enbridge has not prepared such a cost-of- service model for the Mainline Contracting tolling methodology because the tolls were the product of negotiation rather than developed on a cost of service basis”; Additional Directed Information from Enbridge, Guide P – Tolls and Tariffs P.1 Cost of Service, PDF 3 (C08319-31): “No consultation was performed with interested parties regarding cost of service tolls because Enbridge has not applied for cost of service tolls”.
308 Blackline Revised Written Evidence of Drazen Consulting, Part 4, PDF 21 and Appendix D, PDF 39 (C12665-2).
309 See for e.g. Blackline Revised Written Evidence of Drazen Consulting, PDF 5, 18, 20, 25 and 55 (C12665-2).
310 Transcript Vol. 18, PDF 60, para 18415 (Mr. Drazen).
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the Drazen evidence shows that the cost study submitted by Enbridge is flawed and overstates costs. As a result, there is not sufficient supporting evidence to find that the proposed Mainline contracting tolls are just and reasonable and a more in- depth proceeding is warranted.
274. A cost of service review and determination is necessary because:
(a) In the absence of a settlement the Commission must determine whether the proposed tolls are just and reasonable having regard to the existing legislation and the established principles for rate-making. This is particularly true because the Enbridge proposal represents transformational change which would eliminate almost all uncommitted capacity out of the WCSB and depress pricing of crude oil.
(b) There is insufficient rate case quality information on the record for the Commission to definitively determine whether the proposed tolls are just and reasonable due to the opaque selection of the $5.70 base toll. However, the analysis undertaken by Drazen and Brattle using the available information shows that the proposed tolls are not just and reasonable.
(c) Enbridge’s reliance on the end of CTS tolls as being the justification for the base toll is inappropriate because the evidence regarding the current returns under the CTS demonstrates that Enbridge’s returns on the Canadian Mainline, at 25-30%, are excessive and out of step with regulated pipeline returns.311 Using the CTS base toll as the starting point locks in these excessive returns for the duration of the applicable TSAs.
(d) A cost of service review is consistent with the Commission long established principle that tolls should be, “…to the greatest extent possible, cost based”.312
(e) The Enbridge Canadian Mainline has operated for 26 years without a cost of service evaluation. During that time the tolls, services, terms, conditions, and relative risks respecting the Canadian Mainline have changed significantly and it is important to re-base the tolls having regard to current conditions.
(f) A cost of service review is needed having regard to the significant opposition to the Application raised by a diverse group of large and small Canadian producers, integrated companies and Canadian refiners. Canadian oil producers are stakeholders who will be directly affected by the
311 Written Evidence of Drazen Consulting Group, Part 4 – Cost of Service Analysis, PDF 21 and Summary at PDF 34 (C10237-3).
312 NEB Reasons for Decision RH-4-86 – Interprovincial Pipe Line (June 1987) at 48.
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proposed methodology and resulting tolls due to the nature of netback pricing. As the NEB determined in the Milk River case:
The Board considers that the net value received by producers for their production is the delivered price adjusted for quality and transportation and, to some extent, market conditions. Therefore, whether the payment of tolls is made by shippers, producers or refiners, the netback received by producers is impacted by the tolls on the Milk River Pipeline.313
275. Accordingly, for the reasons set forth above, and based on Drazen’s work, the CSG submits that the post-CTS tolls must be re-based using a cost-of-service evaluation.
A Cost of Service Review is Timely
276. The Enbridge Mainline has operated since 1995 without a cost of service evaluation. During those 26 years, the tolls, services, terms, conditions, and relative risks respecting the Mainline have changed significantly. It is important to re-base the tolls having regard to current conditions.314
277. If the use of long-term contracts were to be approved by the Commission, then it is likely that the Mainline would not be evaluated on a cost of service basis for up to an additional 30 years having regard to a maximum potential term of 20 years with a further permitted renewal of ten years. This would mean that Mainline tolls would not be objectively assessed on the basis of actual incurred costs for a period of 56 years.
278. Enbridge has acknowledged that from time to time the relationship between pipeline costs and revenues go out of balance.315 Under cross-examination Enbridge allowed that it is warranted to use cost of service adjudication to bring costs and tolls back into alignment316, effectively re-basing tolls. In fact, that is what Enbridge is currently undertaking in relation to the Lakehead system. In a filing made by Enbridge to the FERC dated May 21, 2021 (C13241-2) Enbridge is seeking to change its Index tolls to cost of service tolls317 for the Lakehead System
313 NEB Letter Decision TO-4-2020 — Murphy Oil Company Ltd., Concerning Tolls for the Milk River Pipeline (August 2001) at 3.
314 Written Evidence of the Canadian Shippers Group, PDF 110 and 122 – 123, paras 342, 343, 383 and 384 (C10237-2).
315 Transcript Vol. 10, PDF 64, paras 9521 – 9526.
316 Transcript Vol 10, PDF 64 –65, paras 9527 – 9530.
317 Enbridge Filing, May 21, 2021, FERC Tariff No. 43.40.0, PDF 2 – 3 (C13241-2) The Lakehead base transportation rate is a portion of the total transportation rate paid by shippers on the Enbridge Energy system. The total transportation rate equals the sum of the base rate and the Facilities Surcharge. The Facilities Surcharge is the product of a FERC-approved settlement agreement between the CAPP and Enbridge Energy that permits the recovery of negotiated costs associated with particular shipper-
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as Enbridge claims that there is a divergence between its actual costs and the revenue it is able to earn.318 As stated in Enbridge’s Application to the FERC:
The primary purpose of Enbridge Energy’s filing is to increase the Lakehead System base transportation rates in order to provide a better 319 opportunity for the Lakehead System to recover its base cost of service.
279. In the same manner as the current Enbridge cost of service application to FERC for the Lakehead base system, it is reasonable and appropriate for the Commission to evaluate and re-base tolls for the Mainline on a cost of service basis. Given the Drazen and Brattle evidence that shows how the proposed Mainline tolls significantly diverge from costs under CTS and having regard to the fact that it has been 26 years since the Enbridge Mainline was evaluated relative to cost, a contemporary cost of service review is necessary.
280. A present-day cost of service evaluation is a timely and needed step for the assessment and establishment of appropriate tolls. Without current, relevant and objective information, it is not possible to determine whether the proposed tolls are just and reasonable, and therefore it is not possible for the Commission to reasonably satisfy its statutory obligation.
XII. THE PROPOSED TOLLS ARE NOT JUST AND REASONABLE
There is Insufficient Information for the Commission to Conclude the Proposed Tolls Are Just and Reasonable
281. A key consideration regarding the validity of a settlement and any proposed toll is whether there is sufficient information on the public record for the Commission to understand the basis for any agreement, assess its reasonableness, and to be able to determine that the resulting tolls are just and reasonable and not unjustly discriminatory.320
282. The onus is on Enbridge to prove on a balance of probabilities that its proposed tolls are just and reasonable, and they have not done so.
283. The NEB has previously stated that the applicant must establish that its requested relief should be granted:
approved projects through an additional surcharge layered on top of Enbridge Energy’s base rates. Enbridge Energy’s base rates are subject to the Commission’s normal rules regarding establishing and changing rates, whereas the Facilities Surcharge is established through an annual rate filing effective April 1 of each year.
318 Enbridge Filing, May 21, 2021, FERC Tariff No. 43.40.0, PDF 3 (C13241-2).
319 Enbridge Filing, May 21, 2021, FERC Tariff No. 43.40.0, PDF 2 (C13241-2).
320 See e.g., CER Act ss 230 and 235; NEB Revised Guidelines for Negotiated Settlements of Traffic, Tolls and Tariffs, PDF 4, (C13339-2).
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Although the Board does not consider it appropriate to establish a burden of proof with respect to each issue in a public hearing, it nonetheless considers that an applicant has the burden of establishing on the balance of probability that the relief sought in its application should 321 be granted.
284. Enbridge established the Mainline base toll in a completely non-transparent manner without any explanation or foundation reflective of Enbridge’s assets in service and under construction. The base toll amount of US$5.70/bbl did not change over the course of the supposed negotiations leading to the “negotiated package.”322
285. The proposed tolls are not based upon an analogous toll, they are not derived as a result of an objective determination or broad stakeholder support, and they were not developed in response to a revenue requirement necessary for the operation of the pipeline.
There is no basis for the base toll
286. Enbridge contends that the tolls were the product of negotiation,323 however, it is clear from the Application that Enbridge did not negotiate the starting point for tolls. Enbridge simply commenced with a declaration of a base toll at $5.70/barrel and then states that any negotiated discounts were made from that predetermined benchmark toll:
The Hardisty to Chicago committed base toll is $5.70 (“bbl”) (“Base Toll”). From this toll, Enbridge and potential shippers negotiated discounts, an adjustment mechanism and surcharges, as described further below.324
287. There is no substantive quantitative information that explains the basis for the declared base toll itself. 325 Without a complete explanation and understanding for
321 NEB Reasons for Decision GH-2-87 TransCanada Pipelines Limited – Applications for Facilities and Approval of Toll Methodology and Related Tariff Matters (July 1988) at 80. (Emphasis Added).
322 See Appendix 18 – Summary of Changes to Mainline Contract Offering (C03823-20).
323 Revised Additional Written Evidence, PDF 17 (C07662-2): “Enbridge has not prepared such a cost-of- service model for the Mainline Contracting tolling methodology because the tolls were the product of negotiation rather than developed on a cost of service basis”.
324 Application, PDF 42 (C03823-2).
325 Enbridge Response to CER IR 1.6(a), PDF 23 – 28 (C06801-2): Enbridge stated that the amount of $5.70 was “similar” to the CTS toll: “A Base Toll of US$5.70/bbl was chosen as a starting point for negotiations because it was similar to the toll for Hardisty to Chicago Heavy movements that was then expected to be in effect on July 1, 2021 if the CTS was extended (“CTS Extension Toll”), and was therefore deemed by some shippers to be an acceptable starting point for negotiations, and because the financial results provided by such a Base Toll would be similar to those that might result from a CTS extension.”
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the actual derivation of the initial base toll value there is no effective independent opportunity for shippers or the Commission to assess its reasonableness.
The CTS toll is an inappropriate analogue
288. Enbridge indicates that the Base Toll amount is “similar” to the projected exit toll at the end of the CTS term.326 However, the exit toll from the CTS does not represent an appropriate base toll amount.
289. Although the CTS initial toll (in 2011) was based on cost,327 by 2019 its revenues were much higher and significantly out of step with costs,328 largely because of the change in the Canadian/US exchange rate and increased volumes due to shipper supported expansions.
290. Since the current IJT is denominated in US currency and was set at a time when the Canadian and US dollars were at par, the strengthening US dollar over the course of the last decade meant that the IJT toll over-recovers the Canadian Mainline costs, which are incurred in Canadian currency. By setting the initial proposed toll at the level of the CTS end-of-term toll, Enbridge would be locking-in this over-recovery for the 20 year term of the Mainline contracting.329
291. Under the CTS, on a cost of service comparison, Enbridge was earning extraordinarily high returns for a regulated monopoly. Enbridge, in its response to Total IR 1.031k indicated that after correcting for the distorting effects of Line 3 Replacement capital and foreign exchange hedging, the return on equity was 24% in 2018 and 31% in 2019.330 These returns are egregious and reflective of a toll that has ceased to correlate with the cost of service. The Drazen evidence concludes that Enbridge’s end-of-term tolls under the CTS greatly exceed cost-of- service and, as such, are not the appropriate basis for beginning a new incentive tolling regime.331
326 Enbridge Response to CER IR 1.6 (a), PDF 23- 28 (C06801-2).
327 Blackline Revised Written Evidence of Drazen Consulting, PDF 11, lines 14-16 and PDF 12, Figure 1 (C12665-2).
328 Enbridge Rely Evidence, PDF 59 (C12447-2). “There is no IJT service to the Canada/US border. Here is no Canadian portion of the IJT”.
329 See Transcript Vol. 21, PDF 18, paras 21021 – 21027.
330 Enbridge Response to Total IR 1.031(k), PDF 69 (C07658-2).
331 Written Evidence of Drazen Consulting Group, Part 4 – Cost of Service Analysis, PDF 21 and Summary, PDF 35 (C10237-3).
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The base toll is not a driver for supporting shippers
292. Enbridge has stated that the base toll of $5.70 USD/bbl was “… deemed by some shippers to be an acceptable starting point for negotiations.”332 In fact, some supporting shippers indicated under cross examination that they had not seriously evaluated the proposed base toll prior to determining it to be acceptable. In particular, supporting shippers such as Imperial Oil did not seriously evaluate the proposed toll versus an outcome of a cost of service regulatory process.333 Mr. Wetmore of Imperial Oil responded to a question about the base toll saying:
“We have always been under the understanding that it’s a market-based toll that has been provided within the Mainline Contracting proposal. We haven’t, to my knowledge, evaluated it versus an outcome of a regulatory process.”334
293. Where an evaluation was undertaken by the supporting shippers it was not to inform any discussion or negotiation but rather was undertaken after the fact when they had already had accepted the base toll amount. Cenovus, who is both a producer and a refiner, provided its letter of support to Enbridge335 six months before it had engaged Dr. Webb in June 2020 to assess whether the tolls were reasonable.336
294. The Commission should take note that none of the supporting shippers appeared to make any request for an independent assessment of whether the tolls are, in fact, reasonable before accepting the base toll. The CSG submits that the tolls proposed by Enbridge were not significant to the supporting shippers, as they knew their interests would best be addressed by firm service and that the tolls would generally be offset by lower netback pricing to producers.
295. In sum, the supporting shippers’ acceptance of the proposed US$5.70/bbl base toll cannot be taken as evidence of the reasonableness of the toll. Rather, the supporting shippers’ ambivalence towards the toll should be a red flag for the Commission. It indicates that the motivation for supporting the Application lies in securing premium, unapportioned service and, importantly, control over a scarce commodity with the monetization opportunities that entails.337
332 . Enbridge Response to CER IR 1.6 (a), PDF 23 (C06801-2) (Emphasis added).
333 Transcript Vol. 16, PDF 59, para 16000.
334 Transcript Vol 16, PDF 59, para 16000.
335 Application, Appendix 4 – Shipper Support Letters, PDF 10 (C03823-6).
336 Transcript Vol 14, PDF 71 – 72, paras 13466 – 13477.
337 See Section VII.A.i of this Argument.
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Insufficient cost information
296. A cost of service review would provide an objective basis for the establishment of just and reasonable tolls. However, Enbridge has argued that because it’s Application sought approval of negotiated338 or “market- based” tolls, it was not required to disclose standard cost of service information. Despite numerous requests to Enbridge for cost of service data by interested parties over the course of contracting discussions, and by the Commission as a part of this proceedings, Enbridge did not provide cost of service information in a complete or meaningful manner. Enbridge stated:
Enbridge has not prepared a cost-based study to allocate a revenue requirement to Canadian Mainline services.339
297. Similarly, Enbridge has not filed sufficient information to support a cost-of-service determination by the Commission. This fact is confirmed by Enbridge’s own expert witness, Concentric Energy Advisers, Inc., where it stated:
It is important to note that this is a simplified model and therefore not comparable to the type of cost of service model that would be used to file for cost of service tolls pursuant to the CER filing manual.340
298. The lack of sufficient cost information limits the Commission’s ability to determine whether the proposed tolls are just and reasonable. Although the Commission is not bound to use a cost-of-service methodology to determine whether tolls are just and reasonable, the NEB has used cost information in order to objectively assess the reasonableness of tolls. In RH-4-2001 the Board stated:
However, it has been the practice of the Board, in setting tolls, to establish a revenue requirement based upon the costs expected to be incurred in respect of regulated activities.341
299. In its Application Enbridge has not provided sufficient cost information, including a revenue requirement,342 to enable the Commission to conclude that the proposed tolls are just and reasonable.
338 Revised Additional Written Evidence, PDF 17 (C07662-2).
339 Enbridge Response to Suncor IR 1.22(a), PDF 75 (C07660-2).
340 Revised Additional Written Evidence, PDF 17 (C07662-2).
341 Reasons for Decision RH-4-2001 – TransCanada PipeLines Limited June 2002 at 10 - 11(Emphasis added).
342 Enbridge Response to Suncor IR 1.22(a), PDF 75 (C07660-2): “Enbridge has not prepared a cost-based study to allocate a revenue requirement to Canadian Mainline services.”
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300. Recently, the importance of cost information necessary to assess “market-based” tolls was recognized by the Commission in the Campus Decision:
Nonetheless, the Commission is of the view that Campus did not establish the appropriateness of a purely market-based toll. By its nature, a market- based toll involves limited inquiry into the cost drivers of the pipeline and the returns earned by the pipeline.343
301. Ultimately, some cost information was made available after Enbridge was compelled by the Commission.344 That information, although not rate hearing quality, informed the Drazen evidence (discussed below), which demonstrates that the proposed tolls are not reasonable as measured against an indicative cost of service evaluation.
302. The Commission cannot discharge its obligation to fix just and reasonable tolls in the absence of sufficient information on the public record regarding how the tolls, and in particular the base toll, were determined. This is particularly true where the evidence of Drazen and Brattle demonstrates on the basis of the available information that the proposed tolls are not just and reasonable.
303. Enbridge has failed to establish on a balance of probability that the tolls are just and reasonable and there is not sufficient information on the public record for the Commission itself to determine whether the tolls are just and reasonable.
The Evidence Demonstrates that the Proposed Tolls Exceed a Reasonable Cost of Service Toll
304. The evidence prepared by Drazen establishes that the cost of service toll in 2022 for Hardisty-Chicago should be US$4.23/bbl. This is US$1.17/bbl lower than Enbridge’s proposed average effective toll of US$5.40/bbl.345 These tolls would result in Enbridge over-earning at the expense of upstream producers (whose netbacks are based on the market price, minus the cost of transportation).
305. The evidence in the proceeding demonstrates that Enbridge’s proposed tolls would greatly exceed cost of service for the Mainline, result in excess payments to Enbridge and provide Enbridge with a rate of return ranging from 22 to 30%346 over
343 CER Letter Decision RH-002-2020 – Campus Energy Partners Suffield LP (7 April 2021) at 14 (Emphasis added).
344 See Letter to CER re Updates to CER IR 1.7 (b.c.d.) (C07713-1). Enbridge filed a response in June 12, 2020 purporting to respond to CER IR No. 1 (C06801-2). On July 23, 2020, the Commission directed Enbridge to file full and adequate responses to CER IR No. 1.7 (.b.c.d) (C07493). In response, on August 7, 2020 Enbridge filed supplemental information to respond to CER IR 1.7 (b,c,d) as directed.
345 The average effective toll of 5.40 USD/bbl is a 90:10 weighted average of the effective contract toll (after discounts) and spot toll in 2022 for a throughput of 3055 kbpd. For calculations see Blackline Revised Written Evidence of Drazen Consulting, PDF 30, A37 (C12665-2).
346 Written Evidence of the Canadian Shippers Group, PDF 111, para 346 (C10237-2).
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the coming decade. These excessive earnings, far above cost of service and a reasonable return, mean that the tolls proposed in this proceeding are unjust and unreasonable.
306. Specifically, the Application would result in an excess payment to Enbridge of over CDN$1.5 billion dollars per year.347 This would compound the erosion of revenues for producers, with a further reduction in royalties and tax payments to Canadian governments. Enbridge’s return on equity under the proposed new tolls would range from approximately 22 to 30%.348
The CER Cannot Rely Upon the Simplified Mainline Contracting Earnings Model Prepared by Concentric
307. Concentric’s Simplified Model cannot be relied upon as evidence that Enbridge proposed tolls under Mainline contracting would be just and reasonable. The Simplified Model was not undertaken to calculate a representative toll349 or to be used as a part of the discussions between Enbridge and the prospective shippers.350 Rather the model was prepared long after Enbridge had established a base toll amount of $5.70 per barrel from Hardisty to Chicago.351 The purpose of the model was to provide after-the-fact justification to respond to the CER’s Information Request 1.7 concerning whether the toll amount previously fixed by Enbridge was reflective of cost of service and toll principles.352 Contrary to normal practice, where the toll is calculated on the basis of representative input values, in this case the toll result was established before the model was developed. Such an approach is concerning as the methodology employed may be influenced by the known result.
308. Concentric’s Simplified Model makes a number of unreasonable and inconsistent assumptions for the purpose of demonstrating that if a COS model were applied, tolls would increase substantially from the proposed tolls. These include:
(a) Treatment of Lakehead Tolls - The Concentric Simplified Model assumes that the Commission’s intention is to evaluate a cost of service toll for the Lakehead System that ignores the authority of the FERC to adjudicate tolls for an American pipeline.
347 Written Evidence of the Canadian Shippers Group, PDF 112, para 345 (C10237-2).
348 Written Evidence of the Canadian Shippers Group, PDF 111, para 347 (C10237-2).
349 Transcript Vol. 9, PDF 75, para 8700 – 8701.
350 Transcript Vol. 9. PDF 76, para 8710 – 8711.
351 Transcript Vol. 9, PDF 74 and 75, paras 8691 – 8692 and 8696.
352 Revised Additional Written Evidence, PDF 6 (C07662-2).
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(b) Return on Equity for the Canadian Mainline - Under cross-examination Concentric confirmed that the tolls calculated by the Simplified Model are dependent upon the input values353 and that the value for return on equity (“ROE”) was an important component of the model in order to provide reliable information relating to the resulting calculated tolls.354 However, as demonstrated through cross-examination, Concentric did not use representative or current information to model its evidence.
(c) Currency Issues – Concentric built its model around an assumption that the toll for the entire Mainline route should be in USD. This gives rise to unnecessary uncertainty and risk premiums related to the management of USD revenue for the Canadian Mainline while all costs are in Canadian dollars.
309. The CSG maintains that tolls for the Mainline should reflect properly adjudicated cost-based tolls for Lakehead (as determined by FERC), and for the Canadian Mainline (as determined by the Commission). The CSG notes that the current International Joint Toll (IJT) denominated in USD is an administrative tool developed for the CTS as a result of an agreement between a broad base of affected parties. That is not the case in the current adjudicated Application and an IJT should not be imposed at the expense of ensuring tolls on the Canadian Mainline are just and reasonable.
353 Transcript Vol. 9, PDF 78, paras 8729 – 8731.
354 Transcript Vol. 9, PDF 78, paras 8732 – 8733.
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Figure 3
310. Drazen demonstrated the relative significance of the differences between their assumptions and Concentric’s assumptions in Figure 3 (replicated above) of their written evidence. In this figure, the main differences between the Drazen cost of service toll of US$4.23/bbl and the Concentric P50 toll, of US$5.66/bbl, are identified as the Lakehead Local Toll (discussed below), the Canadian Mainline cost of service and the effect of foreign exchange and hedging. As Figure 3 shows, taken together, these elements result in a toll difference of US$1.43/bbl compared to the Concentric CER P50 case.355
311. Below, we discuss two of the most significant contributors to the differences between these two analyses being the treatment of Lakehead Tolls adjudicated by the FERC and establishment of expected return on equity which significantly effects both the Lakehead and the Canadian Mainline calculations performed by Concentric. Obviously, the effect of foreign exchange and hedging can be removed by the simple expedient of charging Canadian Mainline Tolls in Canadian dollars as proposed by the CSG.
355 See Transcript Vol. 18, PDF 56, para 18377: Mr Mikkelsen confirmed that even if the starting toll had been higher (as in Concentric’s 100% uncommitted case) they Drazen Consulting would still have determined a toll of US$4.23/bbl as most reflective of a cost of service rate case in 2022.
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312. It is important to note that no party in this proceeding has presented rate case quality information necessary to support a cost of service determination by the Commission. Nonetheless, the modelling performed by Drazen reasonably demonstrates that the Concentric Simplified Model provides results that are more than 1 USD in excess of cost of service tolls based on the principles noted above.
Lakehead Tolls
313. The most significant difference between the Drazen analysis and the Concentric analysis is the calculation of Lakehead cost of service. The CSG contends that the Index tolls and Facilities Surcharge Mechanism agreements that comprise the FERC-approved Lakehead Local toll are based in cost and as they are the basis for the tolls charged by the Lakehead system, are the appropriate measure of the Lakehead costs of providing their service. This is in line with the CTS approach to allocation of IJT revenue to the Lakehead system. However, in its modelling Concentric chose to develop its own set of costs, which are not tested and which utilize an inflated, and as-of-yet unapproved, ROE of 13.5%.
314. Substituting the FERC-approved Lakehead Local toll for Concentric’s postulated Lakehead cost of service reduces the Benchmark toll by US$0.91/bbl. There are a number of issues that Drazen identified with the Concentric Model for Lakehead but the most important was the complete disregard for existing agreements related to the Facility Surcharge Mechanisms (FSM). These are existing agreements between CAPP (representing shippers) on one side, and Lakehead on the other pertaining to about three-quarters of the Lakehead assets, which fix important terms for cost recovery of those assets including depreciation rates and rates of return on equity.
315. Subsequent to preparation of the above Figure 3 in evidence, Enbridge filed two applications in respect of Lakehead tolls. The proposed applications only represent Enbridge’s aspirational requests. They are untested by the FERC. and will not materially change the conclusions of the Drazen analysis illustrated in Figure 3. The first application seeks to increase the ROE for FSM projects using an unreasonably high ROE of 14.63% that has not been agreed or adjudicated.356.
316. One important fact demonstrated by the applications filed by Enbridge with the FERC is that the Lakehead FSM agreements are cost of service based. As Ms. Martin confirmed under cross-examination:
And that’s standard language that we have used for the facility surcharge mechanism, which is a cost of service based mechanism. So that’s the only distinction I would make. But yes, it would be to the negotiated costs. It would be recovering and trued-up annually.357 [Emphasis added.]
356 Transcript Vol. 19, PDF 88 –89, para 19527.
357 Transcript Vol. 10, PDF 41, para 9306. See also Transcript Vol. 10, PDF 57, paras 9455 – 9464.
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317. The second was to reset the Index toll (for the Base system358) to cost of service also using an unreasonable ROE of 16%. The CSG notes that these filings by Enbridge have not been accepted by FERC and are yet to be adjudicated. As Mr. Mikkelsen indicated in testimony, even if these applications are approved as filed, updating the Drazen evidence to reflect the revised Lakehead Index (Base system) toll filing would have minimal impact359 on Drazen’s conclusions with respect to the cost of service benchmark toll.
318. It is important to note that the FSM agreements also provide a number of risk mitigation measures for Enbridge that are not addressed in the Application. In particular, the FSM agreements provide for pass through of changes to operating costs and throughput variations, significantly reducing the risk to Enbridge.
319. Another significant element of the FSM agreements are the Qualifying Volume credits. The qualifying volume credits pass on to shippers the incremental Index Toll revenue facilitated by the expansion projects shippers pay for through the FSM surcharges. These credits are very significant, totalling nearly $600 million in 2022.
320. In order to assess whether the proposed base toll of US$5.70/bbl is comparable to a cost of service toll it is essential that these existing FSM obligations be honoured as a part of the evaluation of just and reasonable tolls. However, they have been ignored in the Concentric evaluation resulting in inaccurate Lakehead toll treatment and therefore artificially high Mainline costs. Return on Equity
321. In its Simplified Model, the cost of both the Lakehead System and the Canadian Mainline were inflated by unreasonable values for return on equity. The CSG has already stated above that the determination of the appropriate cost-based toll for the Lakehead System should be appropriately determined by the FERC – and considers that this process is underway based on the recent filings by Enbridge to that regulator. However, the unreasonable values used by Concentric also carry weight in the Canadian Mainline calculations and so should be carefully scrutinized in this proceeding.
322. Concentric stated that it used two primary sources of data to develop its ROE value for use in its Simplified Model. The first source was a 14.67%360 ROE value taken from testimony prepared by Concentric and submitted to FERC on behalf of
358 The Lakehead Base system is described in Enbridge Filing, May 21, 2021, FERC Tariff No. 43.40.0, PDF 2 – 3 (C13241-2).
359 Transcript Vol. 19, PDF 88 – 89, paras 19526 – 19528.
360 Revised Additional Written Evidence, A70, PDF 49 (C07662-2). See also Transcript Vol. 9, PDF 82, paras 8779 – 8780.
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Panhandle Eastern Pipeline Company (“Panhandle”)361 and the second was a compilation of recent adjudicated ROE values in North America.362 Neither source justified the ROE value used by Concentric in its Simplified Model.
323. First, the proposed ROE of 14.67% calculated and advanced by Concentric in the Panhandle case was not accepted by the FERC. Instead the FERC calculated a significantly lower ROE value of 11.43%.363
324. Mr. Coyne in cross-examination by Mr. Miller,364 and Mr. Davies, in cross- examination of Mr. Mikkelsen,365 suggest that Enbridge represented a pipeline that bore greater risk than Panhandle. However, Mr. Mikkelsen refuted that suggestion, indicating the multiple reasons that there was no basis for such a determination. In addition, it should be noted that it was Enbridge and Concentric that presented Panhandle as a valid and representative precedent ROE value and that the FERC expressly considered the issue of Enbridge’s risk in relation to establishing the Panhandle ROE of 11.43%. In fact, in the sentence immediately following the one cited by Mr. Davies in his cross-examination of Mr. Mikkelsen, the administrative law judge holds that “Enbridge is risk comparable to Panhandle.”366
325. Second, with respect to the compilation of adjudicated ROE values represented in Table 11: “Authorized Returns for Oil & Gas Pipelines,”367 several values presented were not up to date or were not comparable to an established pipeline such as the Enbridge Canadian Mainline. The first authorized ROE presented in Table 11 is a value of 12.63% for SFPP, LP reported from a March 15, 2018 decision of the FERC. As indicated by Concentric’s witness, Mr. Coyne, the SFPP decision cited in Table 11 related to a case commenced in 2008.368 The initial March 15, 2020 SFPP decision was reassessed by the FERC in a decision dated September 4th, 2020.369 In that most recent FERC decision the SFPP ROE was
361 Revised Additional Written Evidence, A67, PDF 46 (C07662-2). See also Transcript Vol. 9, PDF 79, paras 8739 – 8743.
362 Revised Additional Written Evidence, A67, PDF 46 (C07662-2). See also Transcript Vol. 9, PDF 79 – 80, paras 8744 – 8751.
363 Transcript Vol. 9, PDF 86 – 87, paras 8822 – 8836. See also RP19-78-000, Panhandle Eastern Pipe Line Company, LP (C13168-2).
364 Transcript Vol. 10, PDF 23, para 9117.
365 Transcript Vol. 18, PDF 64 – 65, paras 18453 – 18458.
366 Panhandle Eastern Pipe Line Company, LP, PDF 100 (C13168-2).
367 Revised Additional Written Evidence, A69, PDF 49 (C07662-2).
368 Transcript Vol. 9, PDF 94, para 8910.
369 FERC Opinion and Order on Initial Decision and Establishing Paper Hearing Procedures (C13168-3).
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established at 10.54%.370 This most recent ROE value of 10.54% for SFPP was not included in the Table 11 list of adjudicated ROE values and was not added at any subsequent time by Concentric.
326. As its second ROE value Concentric included in the Table 11 list of adjudicated ROE values an ROE value of 14.00% for PennEast dated January 19, 2018. However, Enbridge had confirmed that PennEast was at the time of the toll adjudication a new entrant “greenfield” pipeline.371 In response to Total E&P Canada Information Request No. 2. (C08994-2) Enbridge agreed that:
327. As it relates to PennEast, this pipeline is a new pipeline and FERC’s policy has been to routinely award a 14% ROE to new pipelines. In the approval for PennEast (reference (c)), FERC stated:
The Commission’s policy of approving equity returns of up to 14 percent with an equity capitalization of no more than 50 percent for new pipeline companies reflects the fact that greenfield pipelines undertaken by a new entrant in the market face higher business risks than existing pipelines proposing incremental expansion projects. For example, in contrast to an existing pipeline company, a new pipeline entrant does not have historical cost data on which to base its cost-of-service estimates. In addition, a new pipeline entrant is likely to face higher risks in securing financing than an existing pipeline. Thus, approving PennEast’s requested 14 percent return on equity in this instance is not merely “reflexive;” it is in response to the risk PennEast faces as a new market entrant, constructing a new greenfield pipeline system.372 [Emphasis added.]
328. Mr. Coyne acknowledged that, in contrast to PennEast, the Enbridge pipeline was not a greenfield pipeline373 nor a new entrant.374 As a new pipeline the FERC allowed PennEast a higher return on equity compared to an established pipeline.375
329. The NEB has discussed the need for accurate and up to date evidence to assist the tribunal to discharge its duty. In its Reasons for Decision in RH-4-91, the Board stated:
Insofar as the main issue dividing IGUA and TCPL is concerned, the Board is of the view that in discharging its responsibilities to regulate pipeline tolls
370 FERC Opinion and Order on Initial Decision and Establishing Paper Hearing Procedures (C13168-3). Transcript Vol. 9, PDF 96, para 8945.
371 Enbridge Response to Total IR No. 2, PDF 58 and 59 (C08994-2).
372 .Enbridge Response to Total IR No. 2, PDF 58 and 59 (C08994-2).
373 Transcript Vol. 10, PDF 13, paras 9021 – 9022.
374 Transcript Vol. 10, PDF 13, para 9024.
375 Transcript Vol, 10, PDF 12, paras 9011 – 9012.
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in the public interest, it must ensure that its decisions are based on the most accurate and up-to-date evidence available, consistent with the requirements of procedural fairness. In this context, the Board not only expects but requires TCPL to amend its application so that it contains the most current information available at the time of the hearing. Failure by TCPL to do so could be viewed as an attempt to mislead the Board. The February 1992 update was therefore essential and contained information that was relevant to the Board’s decision-making process.376 [Emphasis added.]
330. Mr. Reed acknowledged that ROE was an important component of Concentric’s Simplistic Model,377 however, the ROE input data does not use reasonable comparable ROE determinations nor does it use the most up-to-date information to derive a representative ROE value. If the Concentric Table 11378 is updated by adding the recent September 2020 adjudicated SFPP, LP ROE of 10.54%, include the 2021 Panhandle ROE value of 11.43% and exclude the ROE value of 14% for the new greenfield PennEast Pipeline the range of ROE’s from 10.10% to 12.99%, compared to Concentric’s range of 10.10% to 14.00% and the average ROE declines to 11.32% from 11.74%.379
331. Concentric’s use of unsupported higher ROE values leads to unsubstantiated and artificially higher toll values and is not a helpful or reliable basis on which the Commission can assess the justness and reasonableness of tolls.
332. Instead, the Commission should prefer Drazen’s evidence, which provides the best possible modelling given the scant information made available by Enbridge in this Application. Although the Drazen evidence did not have the COS information that would be available in a full COS review, by using Concentrics’s own model and reasonable input values it demonstrates that the proposed tolls are not just and reasonable, or at a minimum, raises sufficient concern that the Commission cannot conclude that the tolls are just and reasonable.
Webb Toll Modelling
333. The Webb analysis is also deficient. It is not an independent review of the proposed toll and cannot be relied upon to determine the reasonableness of the proposed tolls. For the same reasons as stated above for the Concentric model, the Webb analysis is flawed and self-fulfilling. The analysis was created after the base toll
376 NEB Reasons for Decision RH-4-91 –TransCanada PipeLines Limited, PDF 54 (March 1992) (Emphasis added).
377 Transcript Vol. 9, PDF 78, paras 8731 – 8733.
378 Revised Additional Written Evidence, A69, PDF 49 (C07662-2).
379 Transcript Vol. 10, PDF 23, paras 9114 – 9121; Revised Table 11 Exhibit Authorized Returns for Oil – Gas Pipelines(C13168-6).
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had been chosen by Enbridge and sought to verify the toll solely on the basis of data provided by Enbridge. As stated in the report:
For my cost of service analysis, I relied on the data and assumptions presented by Enbridge in its response to CER IR1.7b Attachment #2, parts A, B , C, with five exceptions.380
334. Dr Webb confirmed the lack of independent data in his oral evidence and he also confirmed that outside of one FERC filing, he did not look at any information that was not filed on the hearing record at the time of his review.381 In the absence of any independent validation of the Enbridge data and assumptions the Webb review fails on the basis of any generally accepted criteria to provide objective evidential support for the proposed tolls.
Summary of Toll Model Credibility
335. The Concentric and Webb evidence was introduced well after discussions with the shippers had been concluded and only as a result of the Commission’s request for cost of service information in this proceeding. As a result, their work was not intended to calculate a reasonable cost of service toll but was undertaken to ratify the previously chosen toll amount of USD$5.70/bbl. In doing so Concentric and Webb relied only upon material provided solely by Enbridge or used inappropriate and inflated input values to reach a pre-determined toll level. They did not critically analyze historical costs; for example Drazen notes exceptional costs such as the Line 10 sale and Pipelink Project affiliate transfer, which one-off events should not impact future costs.382 Having regard to the after-the-fact defensive purpose of the work, the lack of independent data and the failure to use appropriate or the most current information the Commission should afford the Concentric and Webb evidence little to no weight.
336. In contrast, the analysis work by Drazen and Brattle was undertaken independently using identified objective inputs and both studies were consistent in reaching a determination that the proposed base toll was excessive relative to a reasonable cost of service toll.
380 Direct Evidence of Michael J. Webb, PDF 38 and 84 (C10219-3).
381 Transcript Vol. 14, PDF 79, paras 13552 – 13568.
382 Blackline Revised Written Evidence of Drazen Consulting, PDF 51, A58 (C12665-2).
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Enbridge’s Proposed Toll Methodology Improperly Makes the Revenue Requirement for the Canadian Mainline Dependent Upon Tolls Set in the United States and Establishes “ad hoc” Tolls
Background
337. Broadly speaking, an International Joint Toll (IJT) is an administrative tool used to capture tolling of crude oil movements between two countries. An IJT can be presented in one or more currencies and is sometimes useful in streamlining invoicing. What is important is that shippers agree on the underlying nature of the constituent tolls – whether they are just and reasonable in their respective jurisdictions and whether there is alignment on how external factors (such as foreign exchange) are addressed.
338. The CER should decide the Canadian toll and the FERC should decide the Lakehead toll. In this way, the individual components will be determined to be just and reasonable in their respective jurisdictions. The CSG’s position is that the Canadian Mainline toll should be set by the CER based on cost of service in Canadian currency. This can be invoiced on its own, or as part of an IJT, so long as the Canadian component’s relationship to cost is maintained.
339. In its Application, Enbridge proposes a tolling framework based on a benchmark IJT toll under a single US currency. Their tolling methodology sets the Canadian Mainline revenue as the difference between the IJT revenue and their costs to operate the Lakehead system. Enbridge also depends on this ‘residual’ approach to set a Canadian Local Toll (CLT) (which is not used by any shipper) at the International Border to meet the FERC ‘sum of the parts’ test.
Impact on Canadian Mainline Revenue
340. The NEB has stated “A determination of just and reasonable tolls in Canada must be viewed in the context of Canadian laws, precedents, and business conditions in Canada.”383
341. Enbridge’s requested tolling methodology is inconsistent with this requirement. Using the ‘residual’ approach creates an inter-dependence in which the Canadian Mainline revenue fluctuates based on US law, foreign exchange and business conditions in the U.S. as they impact the FERC-approved Lakehead local tolls.
342. Enbridge’s proposed “residual” methodology384 is also flawed in that it is tentative and changeable at Enbridge’s discretion. Mr Belyea confirmed that, unlike under the CTS (which based its allocation on the Lakehead local toll)385, Enbridge has
383 NEB Reasons for Decision RH-2-79 – Foothils Pipelines (Yukon) Ltd., Phase 1 at 6.
384 Enbridge International Joint Tariff Agreement, Attachment 4, PDF 74 (C13338-2) .
385 Enbridge Competitive Toll Settlement, PDF 6 (C13338-4).
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not yet determined how the revenue allocation will be done under its Mainline contracting proposal:
Counsel, this is Mr. Belyea. As explained in Concentric’s evidence, the current allocation of the IJT is based on the Lakehead local toll,…At this time, Enbridge hasn’t made a final decision about how that revenue allocation or attribution will be done under Mainline Contracting.386
343. In fact, Enbridge is of the view that it does not require any regulatory approvals from the CER or the FERC to set the revenue splitting mechanisms in Canada or the US.387
344. As this revenue allocation is not documented in the TSAs, Enbridge has reserved for itself sole discretion to optimize revenue allocation between the two jurisdictions. This will impact the Canadian Mainline revenue allocation used for the Commission’s Guide BB financial reporting, obscuring the true returns on the Canadian Mainline, among other performance metrics. The revenue allocation will, in turn, potentially impact Enbridge’s tax treatment in Canada and the US.
345. Enbridge acknowledges the expected Canadian Mainline revenue fluctuation in its written argument,388 but expresses no concern because Enbridge contends it has no bearing on the IJT tolls and with the proposed Canadian local toll in US currency, adjustments should be less frequent.389 In addition to using a residual methodology for revenue allocation and using US currency for Canadian local tolls,390 Enbridge proposes to benchmark the Canadian local tolls off of the US$5.70/bbl IJT base toll.391. All of this is apparently for Enbridge’s administrative convenience. This would not be a reasonable basis on which the Commission can approve these fundamental changes, given the cost to Canadian shippers and that the effect of residual methodology is to prevent the Commission and stakeholders from assessing the reasonableness of Canadian Mainline tolls, revenues and realized returns.
386 Transcript Vol. 12, PDF 82, paras 11559 – 1160.
387 Enbridge response to TOTAL IR 1.003 (e) (C07658-2).
388 Enbridge Written Final Argument, PDF 99, para 298 (C13899-2).
389 Enbridge Written Final Argument, PDF 99, para 297 (C13899-2).
390 In contrast, the CTS set Canadian local tolls in Canadian currency and was tied to Canadian costs. See Competitive Toll Settlement and Final Toll Application, PDF 9, para 23 (A1Y9R6): “The new CLT will establish a single toll for transportation, receipt and delivery terminalling services on the Canadian Mainline, adjusted in accordance with the CTS, that replaces the cumulative toll structure of the 2011 ITS base toll, plus the MET Toll and the Terrace Surcharge.” 391 Reply Evidence of Concentric Energy Advisors, PDF 63, A65 (C12447-6): “The only difference between the CTS and the proposed Mainline Contracting tolling methodology is that the Canadian Mainline local tolls are determined on a system-wide basis from the negotiated committed and uncommitted IJT tolls, and the CLT tolls are expressed in U.S. dollars.”
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Impact on Canadian Local Toll to International Border
346. The proposed methodology also gives rise to variable, ad hoc tolls provisional upon any variation in the Lakehead Toll as may be established by the FERC from time to time. In RH-4-86 the NEB indicated that tolls should not be established on an “ad hoc” basis.
The complexity of the issues and the conflicting positions advocated by the various parties confirm that, when dealing with toll design, the Board must be aware of and attempt to apply consistently the principles which it views as resulting in just and reasonable tolls. A toll design methodology should also be able to withstand the test of a range of cost and throughout scenarios to ensure that it consistently yields reasonable results. The Board also recognizes nonetheless that a toll design decision cannot be static, when the environment is constantly changing. On the other band (sic.), the Board is of the view that it is not appropriate to develop a toll design on an ad hoc basis, which will not withstand an application of the criteria discussed above.392
347. Like the Canadian Mainline revenue under Enbridge’s proposed methodology, the Canadian Local Toll at the international border will fluctuate based on external factors related to the Lakehead system such as foreign exchange393 and FERC regulations. As a residual amount, it is an ad hoc toll. It is also an artificial construct, formulated only to respond to the FERC ‘sum of the parts’ test, as confirmed by Enbridge.394
348. Enbridge also acknowledges that the rationale for the ‘sum of the parts’ test is predicated in the FERC presumption that each of the component tolls is just and reasonable in its own right, hence the sum of the two (or anything less than that sum) is acceptable. 395 This points directly to the CER’s ability to assess the Canadian Mainline tolls on a stand-alone basis. However, Enbridge insists that the CER should not assess the Canadian Mainline tolls independently from the IJT, and have only provided costs for the full flow system. Concentric asserts that the costs cannot be ring-fenced.396
I can’t imagine trying to essentially ring-fence a set of costs and define them as being the basis for a hypothetical service to the border which
392 NEB Reasons for Decision RH-4-86 – Interprovincial Pipe Line Limited (June 1987) at 47.
393 See Transcript Vol. 12, PDF 92 and 95 - 99, paras 11640 and 11665 - 11702.
394 See Transcript Vol. 12, PDF 73, para 11488: “Ms Martin: … So I think what we’re trying to say in our reply evidence, that there is no service to the border, but we do need that paragraph 144 in the application to be able to address the tolls in order to meet the FERC test.” 395 See Transcript Vol. 13, PDF 59, para 12217: “So it’s on the presumption that you have two local rates that are before a regulator that are considered to be just and reasonable, which gives you the ability to charge something less than that because they’re both considered to be reasonable, just and reasonable”.
396 See Transcript Vol. 13, PDF 61, para 12231.
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doesn’t exist. No portion of the system has ring-fenced costs to determine the cost of or the appropriate toll for transportation service on an individual segment of the Mainline.
349. Nevertheless, this is exactly how the Concentric model builds up the costs of the IJT – through adding the separate costs of each jurisdiction together – demonstrating that it is entirely possible to have an additive IJT. Concentric’s argument also contradicts Enbridge’s recent FERC application for a cost of service assessment of the Lakehead system which will necessarily be based upon ring- fenced costs on the U.S. portion of the Mainline. Further, it contradicts Enbridge’s acceptance of FERC’s reliance on the Lakehead local toll in its assessment of the ‘sum of the parts’ test.
350. Enbridge may raise the Keystone uncommitted IJT as an IJT comparator. However, that is an entirely different situation as TransCanada’s tariff was uncontested and TransCanada used actual posted (and used) tolls in an additive manner over a range of exchange rates to demonstrate that the resulting IJT is robust and not an ad hoc toll.397
351. In summary, the Enbridge IJT methodology results in uncertain, variable and ad hoc tolls and revenue for the Canadian Mainline, making any objective determination of the justness or reasonableness of the tolls and revenue impossible.
352. The use of Enbridge’s proposed residual methodology may have been accepted under the CTS, but the CTS was very different in that it was a cost-based, broadly supported, uncontested Negotiated Settlement which the NEB approved. 398
353. In the absence of a negotiated settlement, a more appropriate approach is to apply a straightforward methodology where, periodically and as required, the CER approves the Canadian Mainline toll and the FERC approves the Lakehead Toll, and the sum of the two is invoiced to shippers.
The Toll Structure is Discriminatory
354. The Enbridge’s proposal specifies an uncommitted toll of US$5.99/bbl as compared to the benchmark committed toll of US$5.70/bbl. The uncommitted toll
397 Commission Aid to Questioning, PDF 3 and 4 (C13649-2).
398 Blackline Revised Written Evidence of Drazen Consulting, A16, PDF 11 (C12665-2): “when Enbridge was negotiating the CTS in 2011, it said the starting point for tolls was ‘tied to cost of service’. This is demonstrated by the final point on this slide from Enbridge’s stakeholder consultation on the CTS agreement, wherein Enbridge states ‘Starting point for tolls tied to cost of service model’.” See Competitive Toll Settlement and Final Toll Application, PDF 9, para 23 (A1Y9R6): “The CTS provides a simplified toll structure. The new CLT will establish a single toll for transportation, receipt and delivery terminalling services on the Canadian Mainline, adjusted in accordance with the CTS, that replaces the cumulative toll structure of the 2011 ITS base toll, plus the MET Toll and the Terrace Surcharge.”
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is also subject to surcharges for the line 5 tunnel project and expansions on top of any change-in-law surcharges under the TSAs.399
355. In its Application, Enbridge notes that during spot toll “negotiations”, some shippers requested an uncommitted toll while others requested a lower uncommitted toll relative to the committed toll.400 In the developing TSAs, the uncommitted toll evolved from US$5.80/bbl to US$5.99/bbl.401
356. The two primary beneficiaries of a higher spot toll would be Enbridge, who receives incremental revenues, as well as the contracted capacity holders who can monetize a higher margin between the committed and uncommitted toll in a capacity constrained market.
357. This increase in toll arises despite an eroded quality of service as the uncommitted shipper will face increased apportionment for so long as the WCSB experiences an egress shortage. 402 As a result, contracted shippers enjoy discounted tariffs for premium (i.e. non-apportioned) service while uncommitted shippers (predominantly small and medium producers) will be paying inflated rates for a highly apportioned and therefore lesser quality service.403
358. Enbridge seeks to justify this discriminatory practice by pointing to select precedents (Keystone, Keystone Cushing extension, KXL and TMX)404 in which spot tolls were accepted by regulators at premium rates. However, these were all expansion pipelines which required capital to support new facilities and shipper support to develop new markets. As such, all producers in the WCSB benefitted from increased egress to a new market and the contracted shippers were sharing cost risk with the Carrier, hence discounts were appropriate. In contrast, Enbridge’s Mainline contracting proposal concerns existing facilities and no new market access, and thus a very different (i.e. lower) risk profile.405
399 Application, PDF 54, para 136 (C103823-2).
400 Application, PDF 54, para 134 (C103823-2).
401 See Appendix 18 – Summary of Changes to Mainline Contract Offering, line 6, PDF 1 (C03823-20).
402 Written Evidence of Canadian Shippers Group, Chapter VI, PDF 23 – 32 (C10237-2).
403 Transcript Vol. 20, PDF 40, para 19943 (Alson); Transcript Vol. 20, PDF 41, paras 19947 and 19949 (Hardy).
404 Application, PDF 54 – 55, paras 135 – 137 (C03823-2).
405 Transcript Vol. 20, PDF 41, para 19946 (Ms. Day, discussing the appropriateness of discounts for existing pipelines): “Well, as I indicated, I think, from my perspective, I see why those things could be aligned for a new pipe in the ground. But I don’t see where there’s any additional value creation for a pipe that’s already in the ground. The investment, the steel in the ground, has already been made, and
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359. Notably, Enbridge overlooks the most relevant comparator, the TMPL F50 case in which the Board recognized that firm service is a premium quality service and therefore accepted that it justified a premium toll.406
The Board notes that the Firm Service Fee will be an addition to the applicable uncommitted toll resulting in a Firm Service Toll that is higher than the comparable uncommitted toll. Further, Firm Service is distinct from and preferential to uncommitted service on the Pipeline due to its first priority unapportioned access to the Westridge dock. Based on the differing levels of commitment and service, the Board is satisfied that there is no unjust discrimination between Firm Service Shippers and Uncommitted Shippers.
360. The CSG submits that Enbridge has not provided sufficient justification for the discriminatory nature of the uncommitted tariff in its Application.
361. A related concern is that, as discussed above, without access to DSV in an egress constrained market, pure producers are not situated the same as supporting shippers who generally have means to verify and control the utilization of any contracted capacity they obtain. Enbridge’s acknowledgement that it prioritized negotiations with shippers of record and set the committed and uncommitted toll levels to their common interest is evidence of the discriminatory treatment of spot shippers.
Toll Stability is Not a Significant Consideration
362. Enbridge and supporting shippers claim that toll stability is an important factor in assessing and justifying the proposed toll package. As discussed above, toll stability is not one of the key toll making principles accepted by the NEB. More importantly the CSG submits that toll stability is not a serious consideration in this matter.
363. First, when viewed in a context relative to other normal commercial challenges, toll stability is not meaningful. The variability in transportation costs over the term of the CTS was insignificant relative to the variability in the price of the commodity itself. As shown in CSG Evidence Figure 9, the Western Canadian Select (WCS) oil price can move up or down 10 USD/bbl or more in a single month. The base toll under the CTS, on the other hand, increased by only about 0.80 USD/bbl over the term of the CTS, inclusive of expansion charges, with an average annual increase of about 8 cents per barrel. In terms of input costs for refiners, any increase in toll costs is orders of magnitude lower than changes in crude oil costs. Moreover, refiners’ transportation costs are generally recovered from producers through lower WCS prices.
that’s got huge value, as Mr. Monaco has pointed out. So I don’t see why there is any reason to give, necessarily, a volume discount when the pipe has already been built.”
406 Reasons for Decision RH-002-2011, PDF 49 (C13524-26).
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364. Second, Enbridge claims that, under cost of service, there is a future threat of toll instability and potential toll spiral as a result of significantly reduced throughput on the Mainline. However, as discussed above, Enbridge has failed to demonstrate any credible material future throughput risk and has consistently advised its investors to the contrary. Furthermore, Drazen’s evidence shows that under a cost of service model, the Mainline throughput would need to drop from the expected 2022 level of about 3055 kbpd (assuming Line 3 enters service in 2022) to below 2250 kbpd before a shipper would pay more under cost of service than under Enbridge’s proposed Mainline contracting proposal.407 It should be noted that in none of the supply forecasts presented in the Hearing does Mainline throughput drop below 2250 kbpd. This indicates that if the Application were to be approved, shippers would be paying a substantial premium for “stability”.
365. Third, shippers bear the volume risk on the Mainline regardless of whether service is provided under a cost of service regime or Enbridge’s proposed Mainline contracting regime. The main difference is that, under Mainline contracting, shippers bear the volume risk at the individual level (through the take-or-pay provisions) rather than at the group level found under cost of service. Given a choice between the two regimes, and recognizing producers’ desire for flexible market access, producers would prefer under current conditions to take the small risk of some toll variability and share the risk at a group level, than pay Enbridge’s stability premium.40808 Notably, the only circumstance where Enbridge bears the volume risk would be under a negotiated settlement similar to the CTS where Enbridge and shippers reached an agreement to share the risk.
366. Finally, Enbridge’s Mainline contracting proposal does not actually provide toll stability. There are a number of factors under the proposal that would in fact introduce variability. These include: the application of surcharges;409 the effects of Enbridge’s proposed Total Volume Delivered Discounts in which tolls move +/- US$0.05/bbl for each 50 kbpd change in Mainline throughput;410 and the effects of the expected oversubscription in an Open Season,411 from which shippers are
407 Written Evidence of Drazen Consulting, PDF 31 (C10237-3); Written Evidence of the Canadian Shippers Group, PDF 119, para 371 (C10237-2).
408 Transcript Vol. 22, PDF 53, para 22492 (Mr. Cross regarding cost of service): “We feel like there’s minimal risk of volume loss off the system. The system is currently highly apportioned today, and we don’t feel like the tolls are going to increase. We do understand that we bear the risk of tolls under cost of service. And we think if Enbridge filed a cost-of-service application, the tolls currently would go down.”
409 See Written Evidence of the Canadian Shippers Group, PDF 119, para 369 (C10237-2).
410 See Written Evidence of the Canadian Shippers Group, PDF 118, para 367 and PDF 115, Table 19 (C10237-2).
411 Written Evidence of the Canadian Shippers Group, PDF 27, 29 and 118, paras 77, 84 and 368 (C10237- 2).
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forced to acquire additional capacity in the premium-priced412 (and currently non- existent) secondary market, thus causing variability in that shipper’s overall transportation costs. Regarding Enbridge’s proposed surcharges (e.g. changes in law, GDPP escalator, abandonment costs), such charges are similar to the surcharges under CTS, meaning that the toll variability arising under Mainline contracting surcharges can be expected to be of the same order of magnitude as it was under CTS.
XIII. ENBRIDGE SHOULD NOT BE EXEMPT FROM KEEPING A SYSTEM OF ACCOUNTS UNDER THE OPUAR OR FROM FULL REPORTING UNDER GUIDE BB
367. As discussed previously in this Argument, the lack of transparency and access to cogent information, and particularly cost of service information, is a significant concern to stakeholders and is an impediment to fair and open toll discussions.
368. Enbridge does not keep its general ledger according to the system of accounts prescribed by the OPUAR. Enbridge has historically sought an exemption from these requirements, and as part of this Application seeks a further exemption under section 389(2) of the CER Act.413
369. The CSG opposes Enbridge’s request for an exemption from the requirements of the OPUAR. The Canadian Mainline is a regulated monopoly. Consequently, it is necessary the Commission and public have access to information which allows for assessment of the reasonableness of tolls, tariffs and conditions of service.
370. The exemption sought by Enbridge has historically been granted in the context of a negotiated settlement where otherwise confidential information sufficient to support accommodations and agreement has been exchanged between Enbridge and its Stakeholders. This is not the current case.414
371. Furthermore, the current proposal is silent in regards to communication of information to shippers. Consequently, shippers are not able to adequately calculate their transportation risks, apportionment and secondary market exposure.
372. As an adjudicated, as opposed to a negotiated settlement, the need for public disclosure is critical. In the absence of information sharing through true negotiation the only opportunity for the Commission, the public and Stakeholders to obtain
412 See Written Evidence of the Canadian Shippers Group, PDF 118 – 119, para 368, citing NERA’s written evidence (C10237-2).
413 Application, PDF 76, para 197(e) (C03823-2).
414 See Transcript Vol. 10, PDF 89, para 9803.
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relevant information is through Enbridge’s compliance with the existing regulatory reporting and disclosure requirements.
373. The CSG also takes the view that Enbridge must comply fully with the NEB’s Toll Information Regulations Guide “BB” requirements. Guide “BB” sets out information requirements which pipeline companies must provide to the Commission.
374. Guide “BB” provides two options for the level of detail a Group 1 company must provide – either a full amount consisting of the information set out in sections 1-7 of Guide “BB”, or a minimal amount consisting of the information set out in section 8.415 Under cross-examination Enbridge confirmed that should the Application be approved, it would only provide the minimal amount of information proscribed by section 8.
375. There is no compelling reason to exempt Enbridge from the Requisite Filing. Section 8 of Guide BB is mandatory. The Minimal Filing is limited to circumstances of negotiated settlement. Enbridge has readily acknowledged that the Application is not a negotiated settlement. Consequently, there is no basis upon which Enbridge can be exempted from making the Requisite Filing.
376. Enbridge’s testimony that it may select the modified approach as the Application is not a “cost of service” proceeding, is not persuasive.416 While section 8 allows negotiating parties to design requirements that “meet their needs” in the context of a negotiated settlement, the NEB was express in stating that it is “unreasonable to expect that a settlement negotiated by private parties would take precedence over a regulatory requirement… filing requirements are legal requirements”.417 Both the spirit and intent of Guide “BB” militate in favor of ensuring that appropriate and adequate information be provided regardless of the underlying toll calculation process employed (i.e., cost of service or negotiated settlement). Enbridge cannot unilaterally escape these requirements in the absence of either a negotiated settlement or cost of service hearing.
XIV. CSG COMMENTS REGARDING ENBRIDGE’S WRITTEN ARGUMENT
377. Given the Commission’s deadlines for filing written argument in this proceeding, much of this argument was prepared in advance of receiving Enbridge’s written argument. This section provides comments in response to specific aspects of Enbridge’s argument.
378. The CSG notes, first of all, that Enbridge does not once mention the Canadian public interest in its written argument. It goes without saying that given the
415 NEB Letter – All Pipeline Companies – Exemptions – Toll Information Regulations, PDF 2 (C13212-10).
416 See Transcript Vol. 10, PDF 91, para 9830.
417 NEB – Letter – All Pipeline Companies – Exemptions – Toll Information Regulations, PDF 2 (C13212- 10).
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jurisdiction and mandate of the CER, the relevant public interest for the purpose of its consideration of any matter before is the Canadian public interest.
Volume Risk
379. In its argument, Enbridge continues to insist that the Mainline is subject to material volume risk in the foreseeable future, despite the overwhelming evidence in this proceeding that Enbridge only advances this argument to its regulator, the CER, and no one else. As it pertains to volume risk, Enbridge advances one story to the Commission and a diametrically opposed story to its investors. This conduct is unbecoming and raises serious questions regarding the credibility of all of Enbridge’s evidence in this proceeding.
380. For instance, at paragraph 11 of its argument, Enbridge states that there is “no evidentiary basis” for statements made by others that “we’ve got a history of drill to fill” and that “provided there’s the price signals and egress available, we will quickly fill up that capacity”. This is categorically false. Cenovus’ CEO has said that egress from the WCSB is the key determinant of whether new projects will be sanctioned:
Emily Chieng -- Goldman Sachs -- Analyst
Great. And then just one follow-up, if I may, around project sanction. Can you remind us what we need to see in terms of market egress to sanction phase H of Foster Creek or Christina Lake given the rail above curtailment announcement this morning? Or is this still really a pipeline-dependent decision in conjunction with where the commodity price is tracking?
Alex Pourbaix -- President and Chief Executive Officer
Emily, it’s Alex. I think the way to look at it and similar to how we discussed it at the Investor Day is, right now, those H phases are in our base five- year plan. But at the same time, we are going to be very thoughtful about this, and it would be not a very sensible decision to sanction those projects if we’re not confident that we have market access. It’s hard to say what the bright line test for that would be, but I definitely know what it’s going to look like.
We will sanction those projects if and when we have high level of confidence that we will have long-term market access to get those barrels to market. So that’s the question that we’ll consider over the next year as 418 we bring those projects closer to an FID decision.
381. Mr. Pourbaix’s comments are entirely consistent with those of the CSG witnesses and others who have stated that production will grow to meet any increase in egress capacity from the WCSB.
418 See Cenovus – 2019 Earnings Call Transcript (October 31, 2019), PDF 7 (C13428-9).
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382. CNRL witness Ms. Day highlighted that provided the price signals and egress is available, CNRL alone has near term opportunities for 165 k bpd419 of production that can be brought on near term and 1.2 M bpd of capacity420 available to bring on longer term. In addition projects summing 4 M bpd have been filed with the AER.421
383. Enbridge’s witness, Mr. Varsanyi, confirmed that if more pipeline egress becomes available on a timely basis, this will help further grow North American supply, all else equal:
MR. IGNASIAK: All right, so Mr. Varsanyi, there’s a lot to unpack here. With respect to North American production, I understand the reference to “sufficient pipeline egress and prolonged approval processes for new pipelines” to mean that if more pipeline egress comes available on a timely basis, that will help further grow North American supply, all else equal, correct? You would agree with that?
MR. VARSANYI: Yes. I’ve heard a lot of companies making statements that any future growth in their production is conditioned on sufficient egress.422
384. Enbridge’s expert witness, Mr. Earnest, also supported this view when discussing forecasts Enbridge submitted to the MPUC regarding the recent Line 3 application:
MR. IGNASIAK: And if we go to the top of PDF 14, it says:
“Every forecast submitted by Enbridge showed the supply of heavy crude oil from Western Canada continuing to increase at least through the 16-year forecast period.”
Do you see that?
MR. EARNEST: I do.
MR. IGNASIAK: And so that would be up to 2035; is that right?
MR. EARNEST: Yes.423
385. In addition, Enbridge’s CEO has repeatedly asserted that Enbridge’s liquid business, including the Mainline, are robust assets that are not subject to any material volume risk:
419 Transcript Vol. 17, PDF 13, para 16602.
420 CSG Transcript Correction Volumes 17 - 20, para 19158 (C13806-1).
421 Transcript Vol. 20, PDF 47 – 48, paras 20007 - 20009.
422 Transcript Vol 1, PDF 53, paras 526 - 527.
423 Transcript Vol. 2, PDF 70, paras 2031 - 2035.
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“You’d think that makes pipe in the ground more valuable, and I think it will eventually, but the reason for that is it’s very difficult to replicate our asset base and the reality is that in any energy scenario we can think of, our systems are going 424 to be critical for a long time,” [Monaco] said.
“What this picture shows is that the three franchises and the low-risk model that underpins them drive out highly predictable cash flows even in the worst downturns. These businesses have great longevity in any energy scenario and are 425 well-positioned for the future.”
“In terms of the–maybe the implied capital allocation question there, that–we’re in a good position here because the liquids business, as you know, is world-class 426 franchise. That’s going to continue to grow.”
386. Incredibly, Enbridge, at paragraph 14 of its argument, tries to explain away its longstanding position to investors by pointing to the fact that one of the investor presentations referred to Mr. Varsanyi during cross-examination was from 2018. However, the statements by Mr. Monaco, quoted above, were made very recently in April and May of 2021.
387. The evidence clearly demonstrates that Enbridge’s senior management is of the view that its liquids business assets, including the Mainline, will remain critical to the industry for the foreseeable future in any energy scenario. Enbridge’s decision to advance an alternate view only to the CER in an attempt to justify its desire to monetize the scarcity value of pipeline egress from the WCSB is deeply troubling. The Commission should make it clear that this type of regulatory strategy, disassociated from reality, is unacceptable and will not be condoned.
388. At paragraph 15 of its argument, Enbridge attempts to rely on the temporary destruction of oil demand brought on by COVID-19 to demonstrate that the Mainline is subject to risk as the “swing” pipeline. First, the Mainline will not be the “swing” pipeline given that Enbridge and others expect a continued lack of egress from the WCSB. Second, the figure relied on in paragraph 15 is misleading. It does not reflect the temporary decline in volumes on the Mainline and Keystone relative to their overall capacities. If one takes into account the relative capacities of the pipelines, it cannot be said that the Mainline’s temporary decline in throughput is based on its common carriage status. The Mainline’s temporary decline was larger than all other pipelines on an absolute basis because it is responsible for 70% of all exports from the WCSB. Finally, to put the figure in perspective, it should be noted that despite the unprecedented temporary demand destruction brought on by COVID-19, Enbridge’s CEO remarked on the resiliency of Enbridge’s business as follows:
424 See Global News, PDF 4 (C13116-5)
425 See 2021 Q1 Earnings Call Transcript (May 7, 2021), PDF 4 (C13116-2).
426 See 2021 Q1 Earnings Call Transcript (May 7, 2021), PDF 10 (C13116-2).
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“In the face of the worst disruption to economic activity and energy markets, [Enbridge] delivered on our 2020 financial targets set prior to the pandemic.”427
389. In its Written Final Argument, Enbridge has indicated that one of the principal reasons for bringing the Application is it belief that Mainline contracting will mitigate potential future volume risk on the Mainline.428 While Enbridge acknowledges that the refining markets in the U.S. Midwest and Ontario create a “demand pull”, it goes on to suggest that the existence of this “pull” “offer[s] no guarantee of full or long-term Mainline utilization.”429
390. As addressed more extensively in section VI(A) of this Argument, Enbridge’s suggestion that it faces any meaningful volume risk is difficult to accept in light of: (a) the current and historical levels of apportionment on the Mainline; and (b) the future need for transportation on the Mainline that is projected under even the most pessimistic forecasts presented throughout this hearing. However, even if one accepts that volume risk justifies Mainline contracting, Enbridge’s position is difficult to reconcile with its later comments that the excused event provisions are indicative of its willingness to respond to the concerns of shippers and that it will continue to bear volume risk even if Mainline contracting proceeds.430
391. While Enbridge cites its own witness for the proposition that these excused event provisions are unique shipper protections “that are not offered in competitor TSAs”,431 the Commission’s cross-examination of EPAC suggests they are not as unique as Enbridge claims in the refining context.432 Moreover, it is noteworthy that the inclusion of these provisions in the TSAs serves to undermine any protection Mainline contracting provides Enbridge from the fundamental volume risk it has identified as the primary driver for the Application. This inconsistency was explained by Dr. Goodman under cross-examination by the Commission.433 Put simply, Enbridge’s proposed remedy does not cure the alleged problem.
392. Enbridge’s inconsistency on the issue of volume risk does not hold up to scrutiny when considered in conjunction with the excused event provisions in the proposed Refiner RC contracts. This strongly suggests that volume risk is not a risk Enbridge
427 Transcript Vol. 2, PDF 37, paras 1624 – 1626.
428 Enbridge Written Final Argument, PDF 17, para 43 (C13899-2).
429 Enbridge Written Final Argument, PDF 17, para 44 (C13899-2).
430 Enbridge Written Final Argument, PDF 61, paras 178-179 (C13899-2).
431 Enbridge Written Final Argument, PDF 61, para 178 (C13899-2).
432 Transcript Vol. 22, PDF 27, paras 22234 - 22235.
433 Transcript Vol. 22, PDF 27, paras 22234 - 22235.
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is particularly concerned about, nor is it illustrative of a unique or tailored approach to resolving issues that arose in negotiation. Enbridge is essentially asking the Commission to ignore the conflicting evidence on the record and conclude that one of the primary drivers of Mainline contracting is also a risk that Enbridge has willingly agreed to not protect itself against. The CSG submits that Enbridge’s argument is illogical and that the Commission should afford it little, if any, weight.
Over Subscription
393. In its argument, at paragraphs 17 to 25, Enbridge argues that the open season will not be oversubscribed and instead asserts that it will be undersubscribed. This position is novel. It is unprecedented for a pipeline company to develop an offering with the expectation that it will be undersubscribed. The question arises as to why Enbridge feels it is necessary to argue that the open season will be undersubscribed. It must be that Enbridge realizes that oversubscription will result in undesirable consequences. In this regard, the CSG agrees with Enbridge.
394. The CSG’s cross-examination of BP, Imperial and Cenovus demonstrated that these three companies alone could contract for significantly more than 2 million barrels a day of Mainline capacity based on the limits set by Enbridge in the Open Season Procedures.434 There is no credible evidence that the open season, if allowed, will be undersubscribed. Undersubscription is completely inconsistent with the fact that the Mainline has been subject to almost constant apportionment for several years. Enbridge’s argument appears to be that the CER should approve the MLC Application because it will be undersubscribed. Given the history of apportionment and the ability of just three companies to contract for over 60% of Mainline capacity, the Commission in our respectful view cannot approve the MLC Application with the hope that the open season will be undersubscribed.
395. Moreover, Enbridge’s arguments are illogical. If the open season will be undersubscribed, as Enbridge argues, how will this provide Enbridge with the certainty to proceed with any expansions? Undersubscription will not shield Enbridge from volume risk despite its claims that this is one of the key purposes of Mainline contracting. Enbridge’s position regarding undersubscription is simply not credible and should be given no weight whatsoever.
Negotiations and Cost Information
396. At paragraphs 167 and 168 of its argument, Enbridge attempts to argue that it never told CAPP or others that it was not prepared to provide cost information during its discussions with CAPP and others. Enbridge suggests that bilateral negotiations were undertaken because the representative shipper group (“RSG”) was not interested in negotiating with Enbridge. The CSG maintains that
434 See Section X.i of this Argument.
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Enbridge’s characterization of these events is wrong and notes that CAPP expressly clarified the sequence of events during the time in question:
In October 2017, Enbridge presented its perspective on key principles, benefits to shippers and considerations for a long term toll settlement to the RSG including very aggressive timelines for completion of post CTS commercial negotiations. Enbridge sought endorsement from the RSG to adopt the creation of the “2021 Negotiating Team” as an issue. In November 2017, the RSG, almost unanimously, did not support endorsing the issue, at that time, because it was deemed to be premature. The RSG members communicated to Enbridge that they were not prepared to discuss post CTS negotiations until industry has had some time to develop a tolls model and a consensus amongst shippers about what they would like to achieve in a post CTS agreement. Prior to undertaking negotiations for the CTS, Enbridge and shippers spent months to establish a starting point e.g. rebasing of the tolls on the Enbridge Mainline. This critical step was necessary in order to provide transparency and a level playing field for negotiations of a new long term settlement.
In early 2018, CAPP created a working group to identify key objectives, principles and strategic considerations for post CTS discussions with Enbridge. In May 2018, the working group identified and requested specific information from Enbridge which was necessary for transparency and inclusion in the tolls model. The working group indicated to Enbridge that the timing of post CTS discussions was based on Enbridge’s willingness to provide information requested. Enbridge did provide some general information to shippers and later indicated that it was pursuing contract carriage discussions with individual shippers therefore, would not provide any further detailed information.
In September 2018, Enbridge triggered the creation of the “2021 Negotiation Team” under Clause 25.1 of the CTS. In order to participate, RSG members were required to enter into another confidential agreement to receive the Terms of Reference. CAPP signed a confidential agreement but elected not to participate in the “2021 Negotiating Team”.
In October 2018, CAPP communicated to Enbridge that the producer community would like Enbridge to consider alternatives to contract carriage in the nature of a new competitive toll settlement. Enbridge responded that it would only pursue contract carriage discussions at this 435 time. As a result, the CAPP working group was disbanded.
DSV Requirement Renders the Mainline Unsuitable for Contracting
397. Enbridge’s argument does not substantively address the fact that the Mainline is unsuitable for contracting because of its DSV requirement, which does not exist for pipelines that ship to liquid destinations. The importance of DSV, and how it potentially impacts pricing for crude oil, was explained by one of the supporters of the MLC Application, Cenovus’ Mr. Pourbaix:
435 See CAPP letter of December 7, 2020 (C10212-1).
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Alex Pourbaix – President and Chief Executive Officer
I have to say I’m somewhat surprised by the industry pushback. I think we tend to look at it in a very simple way. Just the way that Enbridge’s Mainline system has developed over the decades and with their requirement for downstream verification, for pretty much its entire history, that pipeline has largely been controlled by downstream refiners because of this downstream verification requirement. In order to ship on that pipeline, you have to be able to demonstrate that you have a home for the oil at the other end of it, either a refinery storage or a downstream pipeline.
So just the effect of that is it has been controlled in large measure by refiners. And certainly, from my perspective, I think we have all seen that, that situation has very greatly benefited the refining industry and has very significantly impacted the upstream sector. My own personal view and very simply is that one of the biggest issues affecting our industry right now is people’s concern over market access. And I saw Enbridge’s proposal to convert to a contract carrier as an opportunity where a producer like Cenovus could actually, for the first time, be the master of its own future with respect to getting oil to market.436
436 See Cenovus – 2019 Earnings Call Transcript (October 31, 2019), PDF 11 (C13428-9).
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398. The importance of DSV is also demonstrated by Cenovus’ Mr. Murray. He was referred to the following slide in a combined Husky/Cenovus presentation which showed the pipeline capacity held by both Husky and Cenovus:437
399. Mr. Murray confirmed that despite the Mainline being a common carriage pipeline, it viewed its DSV as equivalent to contracted capacity:
MR. IGNASIAK: Right. So okay. So I think we’re on the same page, that those numbers, the 135,000 barrels for Cenovus, 130,000 for Husky, that is contracted capacity on some pipelines, for instance, Trans Mountain, and then as it pertains to the Mainline, you have used your downstream verification capacity to come up with those numbers, correct?
438 MR. MURRAY: I believe that’s correct.
437 See Husky/Cenovus Presentation, PDF 7 (C13428-8).
438 Transcript Vol. 14, PDF 62, paras 13365 and 13366.
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400. The DSV confers a distinct advantage to a certain class of shippers and introduces unjust discrimination into the Application. This demonstrates why the Enbridge Mainline is not appropriate for contracting and why the commission must deny the MLC Application. In addition, because Enbridge won’t acknowledge this, despite the rest of the industry agreeing on this point, this again brings into question Enbridge’s credibility in this proceeding.
401. Enbridge, at paragraph 135 of its argument, states as follows [footnotes omitted]:
No party has provided a credible explanation for how Mainline Contracting would act to decrease the price of Western Canadian crude oil. On the contrary, the evidence shows that Mainline Contracting would not change:
• the physical supply of WCSB crude oil,
• the demand for WCSB crude oil at all of the refineries directly or indirectly connected to the Mainline,
• the number and composition of the buyers,
• the number and composition of the sellers,
• the capacity and capabilities of the various pipeline, rail, and storage facilities in the WCSB, or
• the price-setting mechanism for WCSB crude oil.
As a result, there is no potential for Mainline Contracting to lower Western Canadian crude oil prices.
402. Enbridge’s argument that there is “no potential” for contracting to lower WCSB prices based on the above factors is absurd. The fact is that none of the factors listed above changed when Enbridge imposed the SPV in June of 2018. Nevertheless, there were, as admitted by Enbridge at the time, significant impacts on the market.
403. Enbridge’s refusal to acknowledge the importance of DSV, and the impacts that resulted from the SPV in June of 2018, demonstrate that Enbridge is not acting in good faith as it pertains to addressing the legitimate concerns expressed by numerous stakeholders in this proceeding. While no one can predict with certainty what the impacts will be, contracting the Mainline clearly has the potential to impact WCSB prices, and to lock those impacts in for 20 years or more.
CSG Proposal for Rebasing Is Not Regressive
404. Enbridge claims that the CSG’s proposal for a cost of service assessment for the Canadian Mainline is regressive, while Enbridge’s proposal is among the possible innovative approaches to regulation. The Commission should reject this characterization. First, Enbridge seeks a cost of service framework on the U.S.
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side of the Mainline (see recent FERC application), which raises the question of why cost of service should be appropriate in the U.S. but regressive in Canada. Second, there is nothing progressive about allowing a regulated monopoly to escape cost accountability for roughly 50 years,439 or about reallocating a scarce public resource for the benefit of a select few who are best positioned to monetize its scarcity value.
405. Being different does not make something innovative; innovation implies solutions, and Enbridge’s proposal falls short, particularly in solving the principal problems plaguing the Canadian petroleum industry, being a lack of egress from the WCSB and access to liquid markets.
406. In his evidence Dr. Makholm provided the example of the Trans Alaska Pipeline System (“TAPS”) to demonstrate the use of rebasing of tolls after a long period of settled tolls. This involved the litigation of a new set of tolls in 2006-2008 after having used settlement tolls since 1985. Adopting a new cost of service study the FERC acted to re-base the tolls.440
407. The CSG submits that its own proposal is progressive: the CSG proposes a one- time re-basing of tolls to put all stakeholders on an equal footing, and that this may be followed by either a negotiated settlement or, in the absence thereof, a periodic (e.g. every 5 years) cost of service review. This approach is both efficient and flexible, in contrast to the rigidity that would be imposed by Mainline contracting for 20+ years.
Tolling Methodology Should Result in Cost-Based Tolls
408. In its argument, at paragraph 249, Enbridge maintains “that a negotiated tolling methodology has no need to be cost-based”. This is a narrow and incomplete statement of the NEB’s past deliberations. This is thoroughly discussed in section XII.
409. The Enbridge Application is not a negotiated settlement. The Commission’s current filing manual makes it clear that a Group 1 pipeline company, such as Enbridge, that has not reached a negotiated settlement with its interested parties is regulated on a cost-of-service basis. It has been a long-standing principle of the Board and 441 Commission that tolls should be designed to be “as cost-based as practicable.” The NEB’s practice has been to establish a revenue requirement based upon the costs expected to be incurred in respect of regulated activities.442 As recently as
439 Consisting of the past 26 years plus a proposed 20 years of Mainline contracting (or plus 30 years including extensions).
440 Written Evidence of Dr. Jeff Makholm, PDF 25 (C10237-4).
441 NEB Reasons for Decision RH-4-86 - Interprovincial Pipe Line Limited (June 1987) at 48.
442 NEB Letter Decision RH-001-2018 – TransCanada Pipelines Limited (13 December 2018).
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this past April 2021 the Commission reaffirmed the importance of costs in setting tolls where, in the Campus decision,443 it implemented a cost-informed toll for a Group 2 pipeline.
444 410. Enbridge also relies significantly on the RH-001-2012 decision to support its view regarding the importance of cost to tolls. However, as indicated by Mr. 445 Houston that case is very different. In contrast to the Enbridge Application, the Trans Mountain decision involved new facilities to alleviate capacity limitations, had much greater shipper support and any impact was modulated by anticipated new capacity. That is not the case in this Application where there are no new incremental facilities, there is strong opposition to the Application and where Northern Gateway and Keystone XL are not alternatives and Trans Mountain capacity is subscribed.
411. All of this is discussed in section XII. Contrary to Enbridge’s argument, the proposed toll should be cost-based.
Market-based Solutions
412. Enbridge has attempted to characterize its Application as a market-based solution that has been devised to meet the needs of the market. In its final argument, Enbridge cited two decisions by the NEB that stated that the NEB supports market- based solutions: RH-3-2004 and OH-001-2009.
413. The CSG notes that the citation from RH-3-2004 states that:
When and where conditions exist which allow for the functioning of a workably competitive market, the Board is inclined to allow the market to operate and to evolve naturally according to its own choices. At the same time, the Board will not hesitate to provide a regulatory solution when a market solution is not available or comes with unacceptable costs.446
414. It is clear from this quote that the NEB qualified its support for market-based solutions on the existence of the appropriate conditions for the functioning of a workably competitive market. The CSG submits that, as recognized by the CER in its hearing order, Enbridge has extensive market power. Further, as detailed in the CSG’s evidence, the Application was not the result of a broad-based market negotiation, but rather it was the result of negotiations between Enbridge and a subset of shippers. In short, the CSG submits that the conditions that allow for a
443 CER Letter Decision RH-002-2020 - Campus Energy Partners Suffield LP (7 April 2021) at 6.
444 Reasons for Decision RH-001-2012, PDF 13 and 40 (C13524-23).
445 Transcript Vol. 17, PDF 95, para 17437.
446 NEB Reasons for Decision RH-3-2004 – TransCanada North Bay Junction (December 2004) at 8.
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workably competitive market for pipeline transportation services do not exist in the context of this proceeding.
415. Rather, approval of the Application would effectively force non-supporting shippers to enter into long-term financial commitments for transportation service, which would unreasonably and unnecessarily expose them to significant financial costs and risks beyond their control, create a barrier to participation for many producers, dis-incentivize expansion, and deter investment in the Canadian petroleum industry. It is a particular concern that the length of the contracts means that there would be no real opportunity for any party, including the Commission, to react in a timely manner to correct any adverse or unexpected consequences.
Enbridge Fails To Apply Appropriate Principles
416. In its Argument (section 9.3.1) Enbridge maintains that the proposed toll is consistent with the Commission’s tolling “principles”. However, Enbridge omits the singular most important principle that tolls should be designed to be “as cost-based as practicable.”447 As discussed in section XII B, the fact that the value of US$5.70/bbl was not determined or justified having regard to actual cost (or determined on any demonstrable basis whatsoever) indicates that this “guiding principle”448 was not observed. In contrast, Enbridge points to toll stability to support its position despite knowing that toll stability is not a tolling principle.449
Enbridge Justification for a Higher ROE Is Not Supported
417. In its argument at paragraph 279 Enbridge attempts to justify the use of unreasonably high ROE values on the basis that the Enbridge Mainline “…has been recognized as an above-average risk regulated pipeline business”. In support of this contention they cite the recent FERC Panhandle decision. 450 It is noted that in that decision Concentric itself actually argued that Panhandle and Enbridge were risk comparable:
Although witness Buckley provides an explanation as to how the different types of risks facing Enbridge are comparable to the types of risks facing Panhandle, it would appear from the significant segment of the liquids pipelines that Enbridge may have higher risk than Panhandle which consists purely of gas transportation and storage segments.
447 NEB Reasons for Decision RH-4-86 - Interprovincial Pipe Line Limited (June 1987) at 48.
448 Reasons for Decision RH-1-2007 - TransCanada PipeLines Limited (July 2007) at 21 -23.
449 See Transcript Vol. 10, PDF 105, paras 9983 – 9984: Enbridge’s witness, Mr. Reed, agreed that toll stability was not as critical a consideration as cost-based tolls.
450 RP19-78-000 Panhandle Eastern Pipe Line Company, LP, PDF 85 - 90 (C13168-2).
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418. In the end result, however, notwithstanding the potential elevated risk of an oil pipeline like Enbridge compared to a gas pipeline like Panhandle, the FERC determined that “Enbridge is risk comparable to Panhandle”.451
Enbridge Advocates An Inappropriate Resolution
419. In paragraph 290, Enbridge makes the transparent suggestion that:
Mainline Contracting would also eliminate the time, expense and risk to all parties of continual lengthy adversarial proceedings going forward regarding cost recovery, the appropriate allowed cost of capital, cost allocation and toll design issues that would be present under a traditional cost-of-service tolling approach for the Canadian Mainline. (para 291).
420. This is tantamount to saying ‘give us what we are asking for and we will save you some time and effort’. This is not a principled approach for establishing tolls. Further, the CSG is not recommending “continual lengthy adversarial proceedings”, but only a one-time rebasing.
Drazen Modelling
421. In section 9.3.2.1 its Final Written Argument, Enbridge alleges certain errors in the CSG (meaning Drazen) and Suncor analyses of tolls. In the case of the work done by Drazen, none of the allegations of error or fault have merit as properly discussed in the Drazen Evidence and further discussed below.
Modelling Methodology
422. In paragraph 301 of its Argument, Enbridge states:
Due to the highly uncertain levels of costs, capital requirements, taxes, interest rates and foreign exchange rates, as well as substantial long-term uncertainty over throughput on the Mainline, the best measure for judging the reasonableness of the proposed tolling methodology is to assess the range of outcomes in terms of potential earned returns on equity, and to do so on a probabilistic basis, reflecting a wide range of throughput, for the entire 20-year period over which these tolls will be offered. The only analyses on the record which meet these criteria are those offered by 452 Enbridge and by Cenovus.
423. The CSG considers that to project tolls over a 20 year period is not a realistic approach and that a more robust methodology is to set tolls for a shorter period and to plan to re-base tolls periodically through contractual or regulatory triggers. As Enbridge indicates in the above quote, many factors are highly uncertain taken over a 20 year term and even a probabilistic modelling approach does not provide
451 RP19-78-000 Panhandle Eastern Pipe Line Company, LP, PDF 87 (C13168-2).
452 Enbridge Written Final Argument, PDF 101, para 301 (C13899-2).
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an assurance that the toll methodology will be robust under all conditions. In effect, Enbridge and Concentric are advocating a “roll of the dice” with the most important infrastructure for the Canadian oil industry. Therefore, the CSG considers that the Drazen modelling approach is appropriate and correct for setting tolls for the near term. Drazen’s modelling has demonstrated the key consideration - to ensure the correct initial starting toll.
Treatment of Lakehead Tolls
424. Enbridge states that it is not correct to use the Lakehead Local tolls as a cost of service:
The first basis on which the CSG and Suncor analyses are misinformed is that the last FERC-approved Lakehead rate is not a proxy for the cost of service on the Lakehead System. (para 265)
425. The CSG notes that the FERC regulates on a cost-of-service basis, and since Enbridge itself has repeatedly described the FSM arrangements as cost-of- service it is entirely reasonable to treat the Lakehead tolls as being based on cost- of-service. This is more fully addressed in paragraph 305 of Chapter XII(C) of the CSG argument.453
426. Enbridge goes on to say in its Argument that,
… the Lakehead toll has no impact on the amount charged to IJT shippers. (Para 266)
And
… the CSG and Suncor analyses seek to ignore the existence of the IJT tolls, which define what shippers actually pay, and instead treat Lakehead’s filed rate as a Transportation by Others (“TBO”) cost of the Canadian Mainline to determine a cost-of-service toll for the Mainline.
427. Enbridge proposes to treat the IJT toll as something that exists outside of any cost analysis, whereas the CSG considers the IJT toll to be based on the actual costs of the Canadian Mainline and Lakehead. There is no dispute that Lakehead charges its actual toll for the U.S. portion of delivering oil. Unless and until the FERC finds otherwise there is no reason to assume the FSM and indexed toll charges are not based on cost of service.
428. As Mr. Mikkelsen noted, the Lakehead Local Toll, specifically the FSM arrangements, reflect cost of service parameters that have been agreed between 454 Enbridge and shippers.
453 See Transcript Vol. 10, PDF 41, para 9306. See also Transcript Vol. 10, PDF 57 – 58, paras 9455 - 9465.
454 Transcript Vol. 19, PDF 95, para 19584.
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Treatment of MARA
429. Enbridge further comments that
... the CSG and Suncor positions assume that Enbridge would be denied recovery of the Market Access Revenue Adjustments (“MARAs”) (Para 268)
430. This is not correct in the case of the analysis done by Drazen. Specifically, Drazen indicates that “In other words, when the tolls reflect cost of service, there is no longer a need to subsidize downstream commitments entered into by Enbridge.”455
431. The CSG notes that these ‘discounts’ were not negotiated or ever brought to the RSG for approval during the CTS. Transferring this as a cost in a new contract without informed consent from shippers certainly merits discussion at a regulatory review.
Prudently Incurred Costs
432. Enbridge claims in paragraph 269 that the Drazen analysis is based on the presumed denial of prudently incurred costs such as foreign exchange hedging and others. The CSG does not categorically insist that hedging costs are imprudent. Nevertheless, it also does not agree that they are prudent simply because Enbridge says they are. For example, given that Enbridge entered into hedges (worth some CDN $835 million456) that extend past the expiry of the CTS and that Enbridge has incurred significant losses on hedges is surely a topic that merits regulatory scrutiny.
433. Regarding other costs, Drazen questions for example the inclusion of a write-off related to the sale of Line 10 which was included in the annual capital costs.457 Whether these costs should be included in a cost-of-service analysis should be the subject of a full cost-of-service rate review before the Commission. These and many other matters can be effectively addressed based on full disclosure of information in such a forum. Without this review of costs, it is not possible to make a final assessment of whether they should be included or excluded from the analysis. What is important is that shippers have not had the opportunity to make an informed decision regarding these toll impacts.
Effect of Throughput Variations
434. Enbridge states that, “An important part of Enbridge’s evidence that is almost entirely disregarded by the opposing intervenors is that one cannot limit the
455 Written Evidence of Drazen Consulting, PDF 40, A46 (C10237-3).
456 Enbridge Response to Cenovus IR 1.3(a), PDF 4 (C07657-2).
457 Written Evidence of Drazen Consulting, PDF 25 - 27, A32 (C10237-3).
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analysis of the Mainline Contracting proposal to an assumption that the Enbridge Mainline will always operate “full” at 3,055 kbpd.” This statement is incorrect.
435. The Drazen analysis specifically addresses the effect of various throughputs in Part 5 – Sensitivity Analysis. In particular, Drazen states in A38 that “The throughput would have to drop to 2,250 kbpd (75% of capacity) for the cost-of- service toll to increase to the level of the proposed contract tolls.” 458
436. Regarding the upside potential for the Mainline, Enbridge’s own evidence is that the once Line 3R is fully operational—expected to be later this year, the capacity will be 3,165 kbpd.459 Further Mr. Varsanyi said that drag-reducing agents and additional horsepower “could be brought to the marketplace very quickly.”460 An additional 100 kbpd would produce $200 million in extra income for Enbridge.
Cost of Capital
437. With respect to Return on Equity, Enbridge stated as follows:
Rather, Drazen referred to actual earned returns for Canadian Group 1 pipelines, and allowed ROEs used in settlement agreements for various pipeline projects. This is inappropriate. Only a market-based analysis of comparable risk companies provides a reliable estimate of the required return for the Enbridge Mainline, such as those provided by Concentric. (Para. 279)
438. Enbridge states “A 13.5% cost of equity on 50% equity ratio for the Canadian mainline and a 55% equity ratio for the Lakehead System are the minimum reasonable levels for use in benchmarking Mainline Contracting tolls.”461 Neither Enbridge, Concentric nor Dr. Webb reconcile why the ROE for the Mainline should exceed every pipeline ROE awarded in the last decade by either FERC or the NEB/CER.462
439. The CSG contends that the work done by Concentric with respect to ROE is highly deficient. This is explained in detail in Section XII C, of this document. Given the inappropriate and optimistic estimations performed by Concentric, the use of existing data from Canadian Group 1 pipelines by Drazen is the best alternative. The CSG considers that the appropriate return on equity for Enbridge could be properly adjudicated at a cost-of-service review by the Commission.
458 Written Evidence of Drazen Consulting, PDF 30, A38 (C10237-3).
459 CER IR 3.9.a.1 Attachment – Annual Capacity Information (C08084-3)
460 Transcript Vol. 7, PDF 20, para 6471.
461 Enbridge Written Final Argument, PDF 92 - 93, para 275 (C13899-2).
462 See Revised Table 11 Authorized Returns for Oil & Gas Pipelines (C13168-6).
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Depreciation and EPH
440. Enbridge comments on the Drazen treatment of depreciation with the following:
By contrast, the Drazen evidence used a 30-EPH in its cost-of-service modelling, suggesting that a 30-year EPH is appropriate because approximately 46% of Enbridge’s 2019 gross plant in service had contractual underpinnings to a 30-year EPH, and therefore the remaining 463 54% of the gross plant should carry the 30-year EPH as well.
441. The CSG notes that Enbridge has not committed to the depreciation parameters it would apply under MLC. If Enbridge adopts a 30-year EPH for MLC, Enbridge would be suggesting that MLC tolls with a 30-year EPH be compared to uncommitted cost-of-service tolls calculated with a 20-year EPH.
442. As Mr. Mikkelsen noted in testimony, comparing tolls with different EPHs is incomplete; it ignores the large difference at the end of 20 years.464 Under a 30- year EPH (MLC) tolling scenario, a rate base of over $10 billion remains after 20 years; with a 20 year EPH that rate base will be zero. With zero rate base the uncommitted toll would be under $1/bbl. Enbridge has not explained how this should be recognized in the toll comparison.
Exemption for OPUAR
443. Enbridge asserts the fact its application is not a negotiated settlement has no bearing on the OPUAR exemption it seeks. Enbridge offers no compelling rationale for this position. Rather, Enbridge claims its Chart of Accounts is superior to that mandated by the OPUAR. With respect, it is not for Enbridge to dictate which information and accounting procedures are appropriate. As set out above, the absence of a negotiated settlement removes any justification for the exemption sought.465 It does so by creating a situation in which the Commission, the public and Stakeholders are denied information necessary to fully assess the Mainline. Enbridge even acknowledges that its Chart of Accounts does not distinguish between such important costs as maintenance, transportation and general categories of operating costs.
Divide and conquer
444. Throughout its Written Final Argument and Reply Evidence, Enbridge has employed a rhetorical technique that is tantamount to a “divide and conquer” strategy whereby it highlights that only one or two specific intervenors have raised
463 Enbridge Written Final Argument, PDF 95, para 285 (C13899-2).
464 Transcript Vol. 18, PDF 54, paras 18367 - 18368.
465 See Section XIII of this Argument.
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a particular argument while others have not.466 It appears that in using this strategy, Enbridge is attempting to draw an inference that these points of concern are not widely shared and therefore not persuasive arguments against Mainline contracting.
445. Enbridge’s suggestion is without merit and is misleading. In accordance with the Commission’s direction, many of the intervenors opposed to Mainline contracting sought to enhance regulatory efficiency by not repeating arguments or lines of questioning, including by forming groups such as the CSG. It does not necessarily follow that, simply because only one or two parties raised a specific issue, others do not share the underlying concern. This is a principle that Enbridge clearly agrees with, as explained at paragraph 93 of its Written Final Argument:
It is in any event an overstatement to suggest that virtually all pure producers are opposed to Mainline Contracting. The 14 shipper support letters were obtained from companies, including some pure producers, that were willing to publicly disclose an intention to subscribe for firm service on the Canadian Mainline in the open season. It should not be taken from this that these are the only companies (including pure producers) that support Mainline Contracting, and it certainly should not be taken from this that companies (including pure producers) that did not 467 provide letters are opposed to Mainline Contracting.
446. To cite one particularly egregious example, at paragraph 150 of its Written Final Argument Enbridge states: “Other than Suncor, no intervenors have taken a position on a particular level of uncommitted capacity to be reserved or otherwise challenged Enbridge’s proposed 10% reservation of spot capacity.” While it may be true that other opposed intervenors did not advance any specific proposal regarding the appropriate level of spot capacity reservation in their evidence, this cannot be reasonably interpreted to mean that no other intervenors have taken a position regarding the appropriate level of spot capacity reservation. To be clear, in the event that Mainline Contracting is approved, it is the CSG’s position that the proposed 10% spot capacity reservation is woefully inadequate, and that a significantly larger proportion of capacity should be reserved for continued spot service.
Prematurity
447. One of the premises underlying many of the arguments outlined in Enbridge’s Written Final Argument is that there is “significant uncertainty” about whether WCSB takeaway capacity will be scarce in the future.468 Enbridge argues that it is necessary to implement Mainline contracting now in order to deal with future
466 See: Enbridge Written Final Argument, PDF 51, 63, 66, 67-70, paras 150, 186, 200, 201, 203, 206, 208 (C13899-2); Enbridge Reply Evidence, PDF 44, para 113 (C12447-2).
467 Enbridge Written Final Argument, PDF 33-34, para 93 (C13899-2).
468 Enbridge Written Final Argument, PDF 5, para 6 (C13899-2).
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uncertainty and the impacts that potential future falling demand may have on the continued operation of the Canadian Mainline.469 If Enbridge’s concern is that, in an unapportioned world there might be enough volume risk to necessitate Mainline contracting, the CSG submits that it would perhaps be more appropriate for Enbridge to wait until the market reflects that dynamic before seeking to implement Mainline contracting, since that is clearly not the market dynamic faced presently and Mainline contracting does not address the issues that exist in the market today.
448. Seeking to implement contracting in the face of significant and sustained apportionment is economically inefficient because: (a) it is likely to result in participants being driven by different motivations and calculations than those that Enbridge relies on to justify Mainline contracting; and (b) Enbridge will be able to take advantage of high demand and “panic buying” to the detriment of most shippers and the Canadian public interest. As succinctly stated by Mr. Van Heyst on behalf of Suncor: “Unfortunately contracting isn’t a remedy for apportionment”.470
XV. CONCLUSION AND REQUESTED RELIEF
449. The Application is not in the Canadian public interest. It reduces the value and return that can be recovered for Canadian oil production. It does nothing to provide Canadian oil producers with additional egress to new or existing markets. It proposes tolls that are not just and reasonable and that generate egregious returns for a regulated monopoly. It is discriminatory to shippers without DSV and results in a discriminatory toll for uncommitted shippers. It has no mechanism for Enbridge or the Commission to change the course or mitigate a structural decrease in oil prices for 20 years (or up to 30 years when possible extensions are accounted for).
450. The CSG remains open to negotiating a risk-balanced and cost-based common carriage tolling settlement for the Enbridge Mainline (i.e. CTS 2.0). However, the CSG submits that continued uncertainty regarding tolls and access to the Mainline is not efficient and contrary to the public interest. Therefore, Enbridge should be required to submit to the CER a cost-of-service application for common carriage on the Canadian Mainline, denominated in Canadian Dollars, with the CER no later than January 31, 2022. This re-basing will ensure a fair return to Enbridge and can facilitate future negotiations that will be fair and transparent with all impacted parties working from a common understanding of the underlying cost-of-service.
451. The CSG submits that the Commission is obliged to deny Enbridge’s Application, direct that the Canadian Mainline remain dedicated to 100% common carriage service at this time, and direct that Enbridge file an application for final tolls
469 Enbridge Written Final Argument, PDF 5, 21 - 22, 53 and 101, paras 6, 53 - 54, 154 and 301 (C13899- 2).
470 Transcript Vol. 21, PDF 37, para 21174.
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calculated on a cost-of-service basis. The Commission has jurisdiction to make these orders in the public interest, pursuant to section 32(c) of the CER Act.
452. In the interests of regulatory efficiency, the Commission should also take steps and issue the necessary orders to prevent a repeat of the current situation in which an application is advanced that has only been negotiated with a narrow subset of stakeholders. The CSG and others have had to incur significant expenses and dedicate limited resources to oppose Enbridge’s Application.
453. As the 2011 CTS expired on June 30, 2021, the CTS tolls in effect as of that date became interim. As a result, future Mainline cost-of-service tolls should become effective July 1, 2021, following either approval by the Commission of a new CTS or a Commission decision setting Mainline cost-of-service tolls.
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