In this chapter, the Panel considers Northern Gateway's evidence on its business structure, project financing plan, toll and tariff matters, pipeline capacity allocation, and open access conditions. Northern Gateway applied for approval of the toll principles applicable to service on each of the proposed pipelines, including the tank and the marine terminals at Kitimat. Northern Gateway's tariff, including tolls, would set the charges and conditions for transporting hydrocarbons on the pipelines and the conditions for shippers to get access to the pipelines. The tolls must be set at adequate levels to allow Northern Gateway to generate enough revenue to carry out its pipeline operator responsibilities in a safe and responsible manner. The Panel's decisions in this chapter determine the key commercial conditions for the pipelines, should they advance to the operating phase.
Northern Gateway said that, should the project be approved, the entities in the corporate structure of Northern Gateway Pipelines Limited Partnership (Northern Gateway, or the Transporter) would continue to evolve, as its partners and potential partners decide on their options to assume new roles such as shippers and/or equity investors. Figure 11.1 identifies these entities and their interrelationships over the different phases of the project.
Figure 11.1 Steps in Developing regulatory approval and Commercial Arrangements for the Enbridge Northern Gateway Project
Enbridge Inc. formed Northern Gateway Pipelines Limited Partnership under the Alberta Partnership Act to develop, design, build, own, and operate the project. The current limited partnership agreement between Enbridge Inc., as limited partner, and Northern Gateway Pipelines Inc., as general partner, was formed in 2004 and revised in 2008. The general partner would manage all project construction and operating activities. Northern Gateway expects that the agreement would be revised again before the pipelines start commercial operation because future equity investors and debt lenders to the project may request further changes. Northern Gateway chose the limited partnership structure because of the need to accommodate a broad range of interests, including potential shippers and Aboriginal groups, in a shared ownership arrangement.
Enbridge Inc., as a limited partner, is the only equity investor to date and its ownership interest would not be finalized until after regulatory approval is granted. As currently structured, the general partner would have a 0.19 per cent interest. There are two other potential types of equity investor in the project: Aboriginal Equity Partners, and Funding Participants. As described in Chapter 9, 26 out of 40 eligible Aboriginal groups have elected to subscribe to the Aboriginal ownership option and become Aboriginal Equity Partners. Northern Gateway set aside 10 per cent of the project's total equity for this option. Northern Gateway expects the full 10 per cent to be taken up by the Aboriginal groups before the project goes into service. The interest taken up by Aboriginal Equity Partners would be financed by the project and would be activated when the pipelines are ready to start commercial operations.
The Funding Participants are potential pipeline shippers and investors. Since potential shippers were unwilling to commit unconditionally to transportation service agreements during the 2005 open seasons, Enbridge devised Funding Support Agreements. These agreements enabled Enbridge and the Funding Participants to share project development costs and risks. By the third quarter of 2012, 10 Funding Participants had contributed about $140 million to the pre-development work. These contributions give each Funding Participant, among other things, the option to acquire transportation capacity on each pipeline (FP Option Volume) at discounted tolls and to become an equity investor-owner in the project. One Funding Participant (MEG Energy Corp.) has an option to purchase its equity in the form of direct ownership of a portion of the pipeline assets. The Direct Owner would have use of a pipeline's capacity up to the proportion of its direct ownership interest.
What is a limited partnership?
A limited partnership is a business structure made up of a general partner who is responsible for the operation and management of the partnership, and limited partners who may invest cash and other property in the partnership and have limited liability. The limited partners grant the general partner the authority to carry out its management responsibilities. Limited partners cannot provide services and are not involved in the day-to-day management and control of the business. Usually, they cannot lose more than their contribution to the capital of the limited partnership. Limited partners share the profits or other compensation from income on their contributions to the limited partnership. The general partner distributes cash to the limited partners in accordance with the partnership agreement and legislation such as the Alberta Partnership Act subsection 59(2).
After the Funding Participants joined the project, they entered into negotiations with Enbridge to develop a structure for commercial arrangements. These negotiations resulted in a precedent agreement and a pro forma transportation service agreement, which included toll principles. These documents were filed with the Panel in June and August 2011. If a Funding Participant enters into a firm transportation service agreement, it would become a Founding Shipper and also a term shipper. Under the pro forma transportation service agreement, a Founding Shipper's total toll for its Option Volume is estimated to be about 15 per cent less than for non-Funding Participant term shipper volumes transported under long-term, firm transportation service agreements. The term shippers, direct owners, and the Transporter would share in any revenue from non-term shippers that would exceed the toll revenue collected from term shippers under long-term transportation service agreements.
Northern Gateway said that a Funding Participant's option to acquire equity in the project is independent from the decision to become a shipper. Both the Aboriginal Equity Partners and the Funding Participants that exercise their equity option are expected to be limited partners in the Northern Gateway Pipelines Limited Partnership. Northern Gateway stated that, pursuant to applicable legislation, a limited partner's liability would be restricted to the funds contributed to the limited partnership.
The Alberta Federation of Labour (AFL)commented on the limited partnership business structure that Enbridge has set up for the project. In its view, limited partnerships are a special form of partnership that are used when business entities wish to limit liability for potential debts of the enterprise while accessing the preferential tax treatment that comes from this form of business structure. The Federation said that the business structure Northern Gateway proposed would provide limited access to cash resources in the event of damages, losses, or liability because of the limits on liability of the partnership. This would have consequences for liability limits for any compensation scheme for a catastrophic event such as an oil spill. In the Federation's view, once Northern Gateway would exhaust its insurance protection, its access to cash resources could be significantly restricted compared to a large corporation.
Haisla Nation said that, in Northern Gateway's corporate structure, only the initial investments of Enbridge Inc. and the Funding Participants would be at risk. Should the costs associated with an oil spill exceed these initial investments, Haisla Nation was concerned that it and the Canadian public may be responsible for some of the costs caused by the spill.
MEG Energy Corp. said that if it exercised its direct ownership option it would have to file an application pursuant to section 74 of the National Energy Board Act. It is MEG's view that this is the only approval needed if it exercises this option. MEG requested the Panel to confirm this position in its decision.
Although Northern Gateway provided its proposed approach to corporate structuring, this structure may change if the equity investors in the project change. The Panel finds the structure Northern Gateway proposed to be acceptable when combined with the conditions set out by the Panel to ensure financial accountability. When determining the financial assurances that Northern Gateway must arrange for the project, the Panel has considered the unique characteristics of the limited partnership.
The Panel understands that Northern Gateway expects the limited partnership agreement to be revised before the project starts commercial operation because future equity investors and debt lenders may request further changes to the agreement. Because these commercial arrangements may change, the Panel has decided that Northern Gateway must file the up-to-date limited partnership agreement and all related agreements at the time that it files its Part IV tolls application.
Northern Gateway said that the project would be in the Canadian national interest. Representatives of the Funding Participants testified that there is a critical need for the project to proceed so that access to new markets could be realized. The Panel finds that the Enbridge Northern Gateway Project has the potential to become a major, high capacity oil pipeline system dedicated to exporting crude oil from Canada to new, foreign markets. Because of its large capacity and potential importance in Canada's energy infrastructure for accessing new markets for oil, the Panel is of the view that additional regulatory oversight is appropriate to ensure that shippers are granted reasonable access to the oil pipeline and that the tolls do not impede access. In addition, the Panel finds that close monitoring of the project's market and financial performance would provide useful information about these emerging markets and related hydrocarbon transportation system needs. For these reasons, the Panel has decided that, if the project is approved, Northern Gateway would be designated as a Group 1 company and must comply with the National Energy Board's filing requirements for Group 1 companies as outlined in the Toll Information Regulations and Guide BB – Financial Surveillance Reports in the National Energy Board's Filing Manual.
The Panel has considered MEG Energy's request for a decision on the regulatory approvals required by MEG for its potential application requesting approval of direct ownership under section 74 of the National Energy Board Act. The Panel notes that MEG has not yet filed an application with the Board, and finds that it would be inappropriate to comment on a potential future application to the Board.
Northern Gateway's financial responsibility, financial structure, and financing methods are identified in subsection 52(2) of the National Energy Board Act as potentially relevant factors for consideration in the Panel's recommendation as to whether the project ought to be approved. These factors were raised during the proceeding, and the Panel's views on them are set out in this report.
Throughout the Panel's process, Northern Gateway said that its financing plan is preliminary and would remain so until the project is developed further. The development of a specific financing plan would follow regulatory approval, more definitive construction cost preparation, and shippers signing firm transportation service agreements.
Northern Gateway is of the view that the project would be financeable for the following reasons:
Northern Gateway plans to use a capital structure with 70 per cent debt and 30 per cent equity to finance the project. Enbridge would arrange debt financing from the project financing market for Northern Gateway. This debt would be non-recourse. Typically, project debt lenders require that a project have features such as long-term transportation service agreements signed by credit-worthy shippers to make a project feasible.
If non-recourse debt cannot be arranged, Enbridge and the other equity investors (which would include all limited partners except the qualified Aboriginal groups) would provide both the debt and equity for the project. The capital structure would be modified to include 60 per cent debt and 40 per cent equity. The strength of each investor's balance sheet would facilitate access to this debt.
If non-recourse debt is attainable, Northern Gateway calculated that the weighted average cost of capital after tax (WACCAT) would be 7.17 per cent and, if it is not attainable, the WACCAT would be 7.86 per cent. Northern Gateway assumes that the cost of debt would be 6.80 per cent in both financing scenarios. The higher WACCAT in the second scenario is attributable to the higher common equity ratio partially offset by a lower debt component in the capital structure.
What is non-recourse debt?
Non-recourse debt is typically secured by property and other assets pledged as collateral, and also in this case would be supported by the project's cash flow rather than being secured by the general assets or creditworthiness of the limited partners who would be equity investors. If the borrower were to default, the lender could seize the collateral. The lender's recovery would be limited to the pledged assets.
Enbridge intends to be the first equity investor in the project. Its level of investment would depend on the amount invested by Founding Shippers, who would have the option to invest equity in the project. If eligible Aboriginal Investor groups exercise their equity option, they would not inject funds into the project. Rather, their equity purchase would be financed by the project. If the Founding Shippers do not exercise their full equity options, Enbridge would increase its equity stake in the project to achieve the target debt to equity ratio at operations start-up.
The equity thickness and rate of return on equity were established through negotiations between Enbridge (on behalf of Northern Gateway) and Funding Participants (potential shippers) who had executed precedent agreements. These negotiations created two alternatives. In one alternative, Enbridge would take on no risk for capital cost variances and the return on common equity would be 11 per cent. In the other, Enbridge would take on the risk for some capital cost variances and the return on equity would be 12 per cent if the actual capital costs equaled the estimated costs. The return would vary as the spread between the actual and the Class III estimate of capital costs widened. This would create a sliding scale risk-reward mechanism for the return on equity. For example, if the actual costs were 135 per cent of the estimated costs, the return on equity is forecast to be 9.9 per cent. Conversely, if the actual costs were 75 per cent of estimated costs, the return on equity is forecast to be 15.4 per cent. Northern Gateway assured the Panel that it would not allow this risk-reward mechanism to detract from its commitment to the project's safety and reliability.
The Alberta Federation of Labour expressed the view that the Northern Gateway model, which would include shippers that are also equity holders, had the potential to reduce competitive market forces when these parties negotiated the toll principles. The Federation questioned whether these parties' investor interests may have taken precedence over their shipper interests.
The Panel accepts Northern Gateway's preliminary financing plan and its options for completing the financing arrangements, should the project receive Governor in Council approval and commercial support.
The Panel recognizes that Northern Gateway's financing plan would remain in a preliminary state until well after the Panel makes its recommendations to the Governor in Council. The Panel has set out a condition that would require Northern Gateway to file a subsequent Part IV application after commercial support for the project is finalized. Once it is filed, the National Energy Board would examine the tolls that would incorporate the annual costs of the financing plan.
The Panel notes that the investors' return on equity may be tied to variances in the project's capital cost. This could create the risk of reducing capital costs for future shareholder gain. The Panel accepts Northern Gateway's commitment to safety and reliability and its assurance that it would not reduce any capital spending that would diminish these strategic operating objectives.
Northern Gateway has applied for approval of the toll principles applicable to service on each of the proposed pipelines, including tank storage and terminal services at Kitimat. In this application it has not applied for Panel approval of the tolls that would be in effect at the start of project operations. Final tolls are not available yet because Northern Gateway has not completed several project steps that would provide the data required to calculate the tolls. These steps would culminate in shippers signing firm transportation service agreements and Northern Gateway finalizing its financing plan. After these steps are complete, Northern Gateway would have the necessary information to file a Part IV tolls application with the National Energy Board.
The tolls and tariffs, including conditions for shipper access to Northern Gateway's pipeline services, must conform to the requirements contained in Part IV of the National Energy Board Act. Section 62 of the National Energy Board Act requires that the tolls be just and reasonable. Section 67 states that a company shall not make any unjust discrimination in tolls, service, or facilities against any person or locality. These requirements are intended to result in all shippers that use the same route, for traffic with similar circumstances and conditions, paying the same tolls. Finally, subsection 60(1) of the National Energy Board Act requires Northern Gateway to have tolls specified in a tariff filed with the Board or approved by a National Energy Board order before it can charge the tolls to its shippers.
Northern Gateway's phasing of the project's pre-development work results in a two-step regulatory process, with the review of Northern Gateway's initial tolls occurring under subsection 60(1) of the National Energy Board Act subsequent to the Panel's issuance of this report.
In its 27 May 2010 application, Northern Gateway requested an order under Part IV of the National Energy Board Act approving the proposed toll principles applicable to service on each of the proposed pipelines, including tankage and terminalling at Kitimat. Northern Gateway's application included estimated tolls based on the toll principles. Northern Gateway did not request approval of the tolls that it would implement. Finalization of the tolls would depend on the completion of the following events:
Northern Gateway has consulted extensively with industry about its export pipeline concept since 2004 and held an open season for each pipeline in 2005. In 2007, it contacted all organizations involved in the 2005 open seasons, and other industry members in North America and Asia with an interest in the project, to solicit them to become Funding Participants. Northern Gateway spent 1.5 years signing up the Funding Participants and another 2.5 years negotiating the precedent agreement, pro forma transportation service agreement, and toll principles. Northern Gateway's efforts to attract Funding Participants continued into early 2012.
In June and August 2011, Northern Gateway filed an update to its application that included the pro forma precedent agreement, the pro forma transportation service agreement and the toll principles for each pipeline.
Northern Gateway said that it would establish the tolls for each pipeline on a stand-alone cost of service basis.
The negotiated toll principles identify the annual cost components that would be eligible for inclusion in the revenue requirements for each pipeline, and the definitions of oil and condensate throughput volumes that would be used to calculate the tolls. Northern Gateway split the revenue requirement into two parts: a capital revenue requirement, and operating expenses. The capital revenue requirement would include annual costs associated with the capital invested in pipeline facilities and a working capital allowance (together, the investment or rate base). Return on equity, cost of debt, income tax allowance, and depreciation expense are the major items in the capital revenue requirement. The operating expense components are identified below.
What is cost of service?
The cost of service for regulated utilities is the total annual costs (cost of service or annual revenue requirement) that shippers must pay through tolls to cover all costs for the transportation services on each pipeline. The tolls for each pipeline must recover the operating costs, the debt servicing costs, income and other taxes, depreciation, and a reasonable return on investors’ equity.
Tolls payable to Northern Gateway for transportation services would be calculated according to the toll principles that are part of the pro forma transportation service agreement. Key features of these principles and related matters are summarized below.
Forward (future) test year:
The tolls for the coming year would be based on the pipeline's cost of service estimates for the next year (forward test year). All differences between estimated and actual tolls would be recorded and recovered or refunded with carrying charges in the tolls 1 year beyond the test year.
Assuming that Northern Gateway can raise non-recourse debt, the project would have a capital structure of 70 per cent debt and 30 per cent equity. If this kind of debt is not available, the capital structure would be 60 per cent debt and 40 per cent equity.
Return on equity:
The target return on equity would be 12 per cent if the cost-risk sharing mechanism described below is implemented and 11 per cent if the cost-risk sharing is rejected by the Founding Shippers. Northern Gateway proposes to fix the return for 30 years.
The rate base components are made up of the capital expenditures for the facilities of each pipeline, plus an allowance for working capital to fund day-to-day operations, less accumulated depreciation. Northern Gateway's rate base would include expenditures for the development and design of each pipeline. The rate base would be adjusted for the First Nation Note Receivable, the mechanism by which the project would fund the Aboriginal equity.
Cost-risk sharing adjustment to rate base for variances between estimated and actual capital costs:
Table 11.1 summarizes the adjustments in the cost-risk sharing mechanism to recognize capital costs that exceed or fall below the Class III capital cost estimate. An increase in rate base above actual costs by this adjustment mechanism will enhance earnings and a decrease in rate base will reduce earnings.
Northern Gateway said that its management team's overriding priority is to construct and operate the project safely. It said that it would administer the cost risk sharing methodology within the bounds of a safe work environment and prudent engineering design and operational practices. Northern Gateway confirmed that its processes and policies would remain the same whether the cost risk sharing methodology is in place or not. Northern Gateway said that both the pipeline and Funding Participants are aligned on the need for a safe project and there would not be a reason to shortcut on capital spending.
The facilities installed for the initial start-up would be fully depreciated at the end of 30 years. During the initial 15 years, the annual depreciation rate would be changed annually so that the capital revenue requirement escalates by approximately 2 per cent per year, and achieves an accumulated depreciation of the initial investment in the pipeline facilities of 50 per cent at the end of year 15. For the final 15 years, the depreciation would be charged on a straight-line basis.
Operating expenses would include:
Reasonable costs for labour, supplies, utilities, overhead, rentals, insurance, and capital-related expenditures for maintenance items that are less than $2 million, individually. Costs relating to actions required for environmental issues would be an eligible operating expense if they are not associated with initial construction and completion or abandonment of the pipeline facilities.
Variable power costs:
Expenditures for electricity that are directly associated with pipeline throughput would be included on the shipper's bill as an item separate from the charge for operating expenses. These costs would be billed at a rate equal to the electricity costs Northern Gateway incurred.
Differentiated toll structure:
The tolls that Northern Gateway proposes to charge its shippers are separated into three tiers in which the tolls increase from one tier to the next. The toll differentials are based on the differing commitments of the shippers. The first tier would be made up of Funding Participants who would become Founding Shippers (and also Term Shippers) by signing long-term transportation service agreements. The second tier would be made up of non-Funding Participant Term Shippers. Both categories of Term Shippers would commit to service agreements with a term of 15 years or more. The third tier would be made up of spot or non-term shippers that make no volume and revenue commitments. The revenue from the tolls of the two categories of term shippers (Committed Toll Revenue) would match the total revenue requirement for each pipeline and the revenue from the non-term shippers would be designated excess and distributed to the Term Shippers and Northern Gateway Pipelines Limited Partnership. Table 11.2 summarizes Northern Gateway's differentiated toll structure.
Table 11.1 Cost-risk sharing adjustment to rate base
| Actual Capital Cost Variance
from Class III Estimate
|Possible Risk-Reward Adjustments to Transporter’s Rate Base|
|15 per cent or less below estimate||(i) Increase the rate base by an amount equal to 25 per cent of the difference between the estimated and actual costs|
|Less than 85 per cent of estimate||(ii) Increase the rate base by the sum of: 50 per cent of the difference between 85 per cent of the estimated costs and the actual costs plus the adjustment in (i)|
|Up to 25 per cent more than estimate||(iii) Reduce the rate base by 25 per cent of the difference between the actual costs and the estimated costs|
|More than 125 per cent of estimate||(iv) Reduce the rate base by the sum of: 50 per cent of the difference between 125 per cent of the estimated costs and the actual costs plus the adjustment in (iii)|
Northern Gateway proposes to provide reserve capacity for non-term shippers on the oil pipeline that equals 5 per cent of term shippers' committed volumes. For the condensate pipeline, this would be 10 per cent. The term shippers' tolls would recover the capital and operating costs associated with the provision of the reserve capacity to non-term shippers.
Excess revenue sharing:
Northern Gateway may collect revenue in excess of Committed Toll Revenue from non-term volumes shipped on reserve capacity or spot capacity, if the latter is available. This excess revenue net of variable electricity costs attributable to the non-term volumes would be distributed among term shippers (75 per cent) and Northern Gateway Pipelines Limited Partnership (25 per cent). If a Direct Owner holds capacity on a pipeline, the 75/25 split would be adjusted to recognize the Direct Owner's rights.
Northern Gateway's illustrative tolls showed that the differentiated toll structure in Table 11.2 created nearly a 1.8 to 1.0 ratio between an uncommitted spot shipper's total toll and the Funding Participant's total toll. This structure, which is part of the toll principles, resulted from negotiations between Northern Gateway and Funding Participants who had executed precedent agreements. Northern Gateway considered the potential shippers that negotiated the tolls to be representative of shippers in all three toll categories. Northern Gateway said that no parties have come forward to oppose the toll principles and three non-Funding Participants (third parties) executed precedent agreements after the original Funding Participants signed. Northern Gateway viewed this as support for the differentiated toll structure.
Northern Gateway said that, throughout its extensive consultations with industry members since 2004, all potential shippers have been provided with an equal opportunity to participate in the same service offerings and to obtain the benefits associated with these service offerings. The process, in Northern Gateway's view, was open and transparent and consistent with subsection 71(1) of the National Energy Board Act. Through Northern Gateway's continued solicitation from early 2007 to 2012, third parties had the opportunity and information to become Funding Participants. Seats at the negotiating table were not restricted to the original Funding Participants.
Northern Gateway said that potential shippers have not signed the transportation service agreements yet because they need more information. Specifically, they need to know: when regulatory approval will materialize; the Class III capital cost estimate and the resulting tolls; and the estimated in-service date of the project.
During the hearing, Northern Gateway said that it was opposed to holding a new open season and making the negotiated transportation service agreements open to comment from potential shippers who have not been involved in the Northern Gateway process to date. Northern Gateway was also opposed to increasing the reserve capacity on the oil pipeline to 20 per cent from the proposed 5 per cent. Further, it did not want to increase the reserve capacity on the condensate pipeline above the 10 per cent proposed.
The Alberta Federation of Labour expressed concern that shippers who are also equity holders may have a conflict of interest when negotiating tolls and may not strive to get the most competitive tolls possible. The Federation questioned whether such a result may have an undesirable effect on toll negotiations for other pipelines in the country.
The Shippers Group said that the negotiations subsequent to the open season were unique and different from the open season process because new foreign markets requiring tidewater access were involved. These shippers expressed no concern with the spot capacity toll being 77 per cent greater than for the Funding Participant Term Shippers' committed capacity. The Force Majeure provision in Section 15 of the transportation service agreement, that may obligate shippers to pay tolls for up to 12 months in the event of a service interruption, was acceptable to these companies.
Table 11.2 Differentiated toll structure
|Category||Service||Capital Portion of Toll (CT)||Operating Portion of Toll (OT)|
|Funding Participant (FP) Term Shipper (Founding Shipper)||Term (committed)||CT1||OT1|
|Non-FP Term Shipper||Term (committed)||CT2 = CT1*1.25||OT2 = OT1*1.0|
|Uncommitted Spot Shipper||Non-Term (spot)||CT3 = CT2*1.50||OT3 = OT2*1.50|
These shippers would oppose:
Increasing reserve capacity above the 5 per cent level incorporated in the tolling principles would, in the views of the Shippers Group representatives, negatively affect the economics for the committed shippers. They would have to support the costs for this unavailable capacity through tolls and would have access to less firm pipeline capacity. The Shippers Group was concerned that additional reserve capacity would affect the committed shippers' marine shipping logistics. They observed that no prospective shippers appeared in the hearing to demand more reserve capacity.
The Shippers Group said that it was too late to consider another open season or to make the transportation service agreement available for comment by potential shippers that had not been involved in the Northern Gateway process to date.
The Shippers Group representatives said that they would expect the Panel to require them to file executed transportation service agreements before construction starts. They would not commit to these transportation service agreements until they have a definitive Class III cost estimate with the resulting tolls, and know the projected in-service date of the pipelines.
Northern Gateway applied for approval of the toll structure and principles for the project under Part IV of the National Energy Board Act. The Panel's views apply to the both the oil and condensate pipelines.
The Panel observes that the toll structure and principles were developed through extensive negotiations between Northern Gateway and the Funding Participants over a lengthy period of time well after the open seasons for both pipelines were closed. In a typical open season all parties have the same opportunity and information at the same time to negotiate for pipeline capacity and the terms and conditions for access to that capacity. A successful open season would culminate with shippers executing firm or conditional transportation service agreements.
In contrast, the Funding Participants committed funds for project pre-development work and then negotiated terms and conditions of access, including tolling principles, with Northern Gateway. The Panel notes that Northern Gateway took reasonable steps to implement a process that was inclusive, open and fair and that no potential shipper objected to the negotiating process or its outcome. At the end of the process, all Funding Participants had access to the same information and agreed to a precedent agreement that included a pro forma transportation service agreement for each pipeline. The precedent agreement gives the Funding Participants the option of becoming Founding Shippers if they sign the transportation service agreement. At this time, the Funding Participants have not contracted for pipeline capacity.
The Panel accepts Northern Gateway's proposals for the following tolling principles:
The Panel's views on the remaining tolling principles follow.
Return on equity:
The Panel accepts Northern Gateway's proposed target return of 11 per cent per annum with no adjustments for cost-risk sharing and 12 per cent if the cost-risk sharing mechanism is accepted by the Supporting Term Shippers. The Panel does not approve of the return being fixed for 30 years regardless of future circumstances that may develop. This return should not be fixed beyond the initial terms of the transportation service agreements. In addition, a system expansion could potentially require a review of the return before the initial terms of the Agreements expire. Further, all shippers have the right to file a complaint with the Board about tolls and tariff matters.
Cost-risk sharing adjustment to rate base for variances between estimated and actual capital costs:
The Panel accepts this adjustment mechanism and its potential effect on return on equity. If this mechanism is applied, the Panel accepts Northern Gateway's commitment to give priority to the safety and reliability of the project during the design, construction, and operation of the project and to not shortcut spending funds that would enhance the project's safety and reliability.
Differentiated toll structure:
The Panel recognizes that this structure is the result of negotiations with Funding Participants who may enter into long-term transportation service agreements with Northern Gateway. Although these negotiating parties may have represented all three shipper categories, there is no evidence that potential shippers who might use the pipeline solely as non-term or spot shippers participated in the determination of the tolls that resulted in the Non-Term Shipper/Funding Participant Term Shipper toll ratio of approximately 1.80 to 1.0. It is unclear at this time whether the Non-Term Shipper toll premium of nearly 80 per cent might become a significant impediment to spot shippers using the system. Accordingly, the Panel directs Northern Gateway to use a monthly auction process to allocate this Uncommitted Non-Term Shipper capacity to spot shippers. Northern Gateway should conduct the auction within a toll range with the upper limit being the total Uncommitted Spot Shipper toll determined by the toll principles used in Table 11.2. The lower limit of the range would be determined in the Part IV proceeding.
Please see the Views of the Panel on reserve capacity in Section 11.4.
The Panel directs Northern Gateway to include in its regular surveillance reports a summary of how this reserve capacity is used, including level of usage by shippers that are solely in the Non-Term Shipper category, pricing with respect to the ceiling and floor, and bid volumes vs. capacity allocated in the auction. The Panel does not accept the view expressed by the Alberta Federation of Labour that the potential shippers who are also potential equity holders may have had a conflict of interest when negotiating the toll principles. The evidence indicated that 10 Funding Participants with diverse interests negotiated with Northern Gateway. The inclusion of the cost-risk sharing mechanism in the toll principles demonstrates the Funding Participants' attempt to put an upper bound on the return on equity and to obtain value for any increase in return above 11 per cent. Also, no potential shippers raised concerns that the negotiating process was unfair or that Enbridge took a dominant position.
Although the negotiating process did not have all the features of an open season, the Panel accepts the results of this process subject to its views and conditions. Using this process, Northern Gateway and potential shippers developed the commercial terms, including toll principles, and Northern Gateway continues to collaborate with these parties to finalize commercial support for the project.
The Panel has attached conditions, including additional monitoring by the Board, to its approval of the toll structure and principles because:
The Panel approves the toll principles subject to its comments and conditions. The Panel is not approving specific tolls that Northern Gateway would charge its shippers. The Panel finds that there is a need to maintain regulatory oversight over Part IV matters in this application because the required data are not available to determine the final tolls and because the potential shippers do not have enough information yet and are not ready to make shipping commitments. Accordingly, the Panel directs Northern Gateway to file an application under paragraph 60(1)(b) of the National Energy Board Act with the Board seeking approval for the tolls it will charge its shippers after it has finalized commercial support for the project.
Subsection 71(1) of the National Energy Board Act establishes that oil pipelines under National Energy Board jurisdiction are common carriage pipelines. It states:
Subject to such exemptions, conditions or regulations as the Board may prescribe, a company operating a pipeline for the transmission of oil shall, 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.
Oil pipelines are increasingly relying on long-term contracts to support new facility construction. Under this structure, capacity must be allocated in an appropriate manner among firm shippers and uncommitted shippers to ensure that the pipeline continues to comply with its common carrier obligations.
Northern Gateway said that the project's oil pipeline was announced in early 2004 and an open season seeking expressions of shipper interest was conducted from October through December 2005. Northern Gateway said that the notice of the open season was advertised during October 2005 in several local, regional, national, and international news publications. It said that the open-season package was distributed to 36 companies in North America and the Asia-Pacific region, and to all additional parties that contacted it in response to the public advertisements.
Northern Gateway said that, during 2004, it had become apparent that there could be sufficient support for the construction of a condensate import pipeline concurrently with the oil pipeline. Therefore, it conducted an open season from July through September 2005, seeking expressions of shipper interest in the condensate pipeline. Northern Gateway said that notice of the open season was advertised during June 2005 in several local, regional, national and international news publications and the open season package was distributed to 25 companies and to all additional parties that contacted it in response to the public advertisements.
Northern Gateway said that the oil pipeline open season resulted in 15 parties submitting non-binding requests totaling 183,600 cubic metres (1,155,000 barrels) per day of service, and the condensate pipeline open season resulted in 12 parties submitting non-binding requests totaling 42,000 cubic metres (264,000 barrels) per day of service.
Northern Gateway acknowledged that several of the key project parameters contained in the open season offerings including pipeline capacity, capital cost and toll estimates and in-service date, had changed in relation to the applied-for facilities. Northern Gateway maintained that the application reflects fundamentally the same concept of providing for high volume oil export capacity and condensate imports. Northern Gateway said that it did not consider holding a second open season based on the changed parameters, electing instead to develop funding support agreements with the open season participants and other third parties. Northern Gateway confirmed that none of the terms of the Funding Support Agreement and the preferential rights were included or described in the 2005 open season package materials provided to potential shippers.
Northern Gateway said that the open season processes held in 2005 yielded considerable expressions of interest for the oil pipeline and the condensate pipeline. Regulatory uncertainty was a significant concern for prospective shippers, and was a barrier to securing shipping commitments. The anticipated cost of resolving the regulatory uncertainty associated with a greenfield project to the west coast was a significant obstacle for Enbridge, as the sole project sponsor. Northern Gateway said that it ultimately concluded that obtaining regulatory approval for the project was necessary before prospective shippers would be willing to enter into long-term shipping commitments and that additional financial support for project development was required.
Northern Gateway said that, between early 2007 and 2008, it approached prospective shippers that had been identified through the open season processes and others to determine whether they would provide financial support to partially fund predevelopment activities. Northern Gateway said that, as a result, it successfully placed 10 $10 million units with a combination of Canadian oil producers and Asian market area interests (the Funding Participants).
Northern Gateway said that, for each $10 million unit of initial financial support to the project, a Funding Participant (under certain terms and conditions):
Northern Gateway said that a Funding Participant's option to acquire equity is independent from its decision to become a shipper. MEG Energy was identified as the only Funding Participant with a further option to purchase its equity in the form of direct ownership of portions of the asset. Northern Gateway said that this direct ownership option could be as high as 13.23 per cent with firm capacity on the pipelines equal to its ownership. According to the terms of the pro forma transportation service agreements, the direct owner capacity would not be operated as a common carrier. The Direct Owner would put up its share of the reserve capacity for uncommitted shippers. As of late 2012, neither the equity agreement nor the direct ownership agreement had been finalized.
Northern Gateway said that the structure of the commercial arrangements with the Funding Participants prevented it from issuing additional units to potentially interested third parties after the initial placement of the 10 units. It said that the option to become a Funding Participant was open until early 2012, by way of Funding Participants that were seeking to sell a portion of their interest. Northern Gateway said that two third parties came forward and became Funding Participants. Northern Gateway said that, in addition, two-third parties expressed interest in becoming Funding Participants but could not be accommodated because, as of mid-2012, the Funding Participants were no longer seeking to sell their units.
Northern Gateway said that, as of late 2012, there were 10 Funding Participants with various levels of units held. At that point in time, the Funding Participants continued to fund predevelopment activities beyond their initial commitment and had contributed about $140 million in aggregate.
In August 2011, Northern Gateway said that both the crude oil and condensate pipelines had been fully subscribed for long-term transportation service through shipper-executed precedent agreements. Northern Gateway filed copies of the pro forma precedent agreement and transportation service agreement for both the crude oil export pipeline and the condensate import pipeline. Northern Gateway said that it holds executed precedent agreements for 15,900 cubic metres (100,000 barrels) per day in excess of the proposed contractible capacity of the oil pipeline and 1,590 cubic metres (10,000 barrels) per day in excess of the proposed contractible capacity of the condensate pipeline.
Northern Gateway confirmed that the precedent agreements are non-binding in that they do not obligate any shipper to execute a transportation service agreement unless the shipper has received, at its sole discretion, the necessary internal approval of its senior management or board of directors, as the case may be. Northern Gateway said that, before potential shippers can execute the transportation services agreement, they will need to understand when regulatory approval will materialize, the Class III capital estimate and the resulting toll, and the potential in-service date. Northern Gateway said that it is possible, but not the intent, that the transportation service agreement be renegotiated at a later date.
Table 11.3 provides a summary of the capacity contracted under the precedent agreements for both the oil and condensate pipelines.
Northern Gateway said that the negotiating process for these agreements took place between 2009 and mid-2011, and, although discussions focused on the Funding Participants, seats at the negotiating table were not restricted to the original Funding Participants. It said that, through the application filed in May 2010 and continued solicitation for more Funding Participants through 2012, third parties had the knowledge and opportunity to participate.
Northern Gateway said that the option to enter into a precedent agreement remains open, and that it was encouraging parties to do so. Under the terms of both the oil and condensate pipeline precedent agreements, firm service on the pipelines could only be obtained to the extent that current Funding Participants did not provide letters of support to Northern Gateway to fund the technical studies (e.g. the Class III capital cost estimate). If a Funding Participant failed to deliver a letter of support, that capacity option would be first offered to the remaining Funding Participants. If all Funding Participants provided letters of support, and subsequently executed transportation service agreements for their full option volume, third party holders of precedent agreements would not have the opportunity to obtain firm service via the execution of a transportation services agreement.
Under the terms of the both the pro forma oil and condensate pipeline transportation service agreements, any party can request that capacity be made available by providing a backstopping agreement to fund the necessary technical studies and feasibility assessment. If a request were to be made, Northern Gateway would first seek to provide the capacity by way of Funding Participants holding firm capacity who may wish to release all or a portion of their term volume commitment, followed by other firm shippers. In the event that there were capacity requests from Funding Participant firm shippers, term shippers and non-term shippers exceeding turn back volumes, requests from Funding Participant firm shippers would be satisfied first, followed by other term shippers, and, finally, non-term shippers, each on a pro rata basis. If there were unallocated volumes remaining, Northern Gateway would then consider a capacity expansion, subject to the requesting parties providing satisfactory backstopping agreements. Northern Gateway said that, as of late 2012, the form of the backstopping agreement had not yet been developed.
Northern Gateway said that the two pipelines have been designed to provide the capacity necessary to efficiently transport term shippers' committed volumes. In addition, Northern Gateway said that the oil pipeline would provide 3,975 cubic metres (25,000 barrels) per day of reserve capacity, which is equal to 5 per cent of the term shippers' committed volume of 79,500 cubic metres (500,000 barrels) per day, and the condensate pipeline would provide 2,780 cubic metres (17,500 barrels) per day of reserve capacity, which is equal to 10 per cent of the term shippers' committed volume of 27,820 cubic metres (175,000 barrels) per day.
In determining the amount of reserve capacity for each pipeline, Northern Gateway said that it considered the incremental cost of providing reserve capacity and the associated financial risk to Northern Gateway and its term shippers, as well as the practical limitations of the marine terminal operations related to available tankage. Regarding the latter, it said that a monthly nomination for the reserve capacity on the oil pipeline would be sufficient to accommodate one cargo movement per month. Non-term shippers would also have the option to purchase additional oil supplies at Kitimat from other Northern Gateway shippers, if they wished to increase the size of their cargo. Northern Gateway said that, in addition, in any given month, the amount of pipeline capacity available to non-term volumes could exceed the reserve capacity if a term shipper did not nominate its full committed volume or if ambient factors were to result in more available capacity on the pipeline.
Northern Gateway said that, based on the anticipated pricing benefits in the Asian market and the fact that term shippers would be making binding take or pay commitments, spot capacity made available from unutilized term volumes would likely be relatively low and utilization of reserve capacity on the oil export pipeline would likely be high.
Potential Condition 10(e) would have required Northern Gateway to increase the level of reserve capacity for uncommitted shippers on the oil pipeline to 10 per cent of the average annual capacity as part of its future tolls application. Northern Gateway commented that the Canadian Association of Petroleum Producers and a number of sophisticated shippers active in the proceeding did not express concern with establishing reserve capacity of 5 per cent.
Table 11.3 Enbridge Northern Gateway Project contracted capacity
| Oil Pipeline
(cubic metres/day [barrels/day])
| Condensate Pipeline
(cubic metres/day [barrels/day])
|Capacity||83,500 [525,000]||30,600 [193,000]|
|Funding Participant PA volume||67,900 [427,000]||23,700 [149,000]|
|Direct Owner PA volume potential||10,500 [66,000]||3,660 [23,000]|
|Third party PA volume||15,900 [100,000]||1,590 [10,000]|
|Total PA Volume||94,300 [593,000]||28,900 [182,000]|
Note: PA – precedent agreement
Northern Gateway said that, through its total service offering, it has conducted itself in a fair, open, and transparent manner consistent with the requirements of subsection 71(1) of the National Energy Board Act.
Northern Gateway said that it conducted open seasons that enabled all interested parties to make informed decisions regarding whether they would participate in the service offerings. Northern Gateway said that it also engaged in extensive consultations with all interested parties since 2004 in a continued offering of service. It said that, throughout this time, all potential shippers were provided with an equal opportunity to participate in the service offering and to obtain the benefits associated with the offering. In addition, capacity would be made available for uncommitted shippers on the two pipelines.
Cenovus Energy Inc., INPEX Canada Ltd., Nexen Inc., Suncor Energy Marketing Inc., Total E&P Canada Ltd.
The Funding Participants said that, during the proceeding, no party expressed a concern with regard to the proposal to reserve 5 per cent of nominal capacity for non-term shippers on the oil export pipeline. It said that there is no basis upon which Northern Gateway should be required to reserve a minimum of 10 per cent of the oil pipeline's nominal capacity for non-term shippers. It said that a change to the amount of reserve capacity for non-term shippers may have an inadvertent impact on the toll principles, as shippers holding the contracted volumes are required to pay the oil and condensate pipelines' annual revenue requirement, with revenue from non-term shippers being shared by Northern Gateway and contract shippers.
MEG Energy Corp. (MEG)
MEG said that the proposed increase in reserve capacity from 5 per cent to a minimum of 10 per cent could have significant negative economic implications for Funding Participants' future involvement in the project. MEG said that, through the Funding Support Agreements, the Funding Participants made significant financial commitments based on an understanding of what they would be entitled to in return. It said that an increase in the reserve capacity necessarily decreases the volume available for each Funding Participant's option to reserve firm capacity on the pipelines pursuant to transportation service agreements. MEG said that no party intervened in the proceeding in respect of the level of reserve capacity.
Alberta Federation of Labour
The Alberta Federation of Labour suggested that the opposition by the Funding Participants to the Panel's potential condition proposing an increase in reserve capacity for non-term shippers from 5 per cent to 10 per cent makes the project sound like a private pipeline.
The Panel notes Northern Gateway's position that it has, through its total service offering, conducted itself in a fair, open, and transparent manner that is consistent with the requirements of subsection 71(1) of the National Energy Board Act. The Panel also notes that no shipper intervened in the proceeding and took the position that Northern Gateway would not be meeting its obligations as a common carrier.
In past decisions, the National Energy Board has found that an oil pipeline offering firm service acts in a manner consistent with its common carrier obligations when an open season is properly conducted and where sufficient capacity is left available for monthly nominations by non-term shippers. The Board has sometimes also considered whether the facilities are readily expandable.
The open seasons conducted by Northern Gateway in 2005 did not result in binding or conditional commitments for transportation service. Most of the project parameters included in the open seasons, such as pipeline capacities, capital cost estimates, estimated tolls, and in-service date changed in relation to those contained in the application, and further changes appear to be possible. Moreover, the concept of the Funding Support Agreements and the rights and obligations relating thereto were not part of the open season processes. The Panel is of the view, therefore, that there is no clear link between the open seasons and the development of the Funding Support Agreements, and the subsequent negotiations between the Funding Participants and Northern Gateway resulting in the precedent agreements and pro forma transportation service agreements.
The Panel notes that both the oil and condensate pipelines have been fully subscribed by the Funding Participants for long-term service under the precedent agreements. These agreements do not require the Funding Participants to execute firm transportation service agreements to ship oil or condensate, or pay the tolls for the capacity option that they hold. Accordingly, it is possible that Funding Participants, in whole or in part, would not enter into firm transportation service agreements with Northern Gateway. The Panel is of the view that this could affect the amount of capacity available for other shippers to access the facilities, either on a committed or uncommitted basis. It could also potentially affect the terms of access.
If all the Funding Participants execute transportation services agreements for their full option volumes, no other shipper would be able to gain firm access to capacity on either pipeline by way of executing a precedent agreement or transportation service agreement. The option volume rights were part of a package granted to the Funding Participants which were secured in exchange for sharing the costs of project predevelopment, which, as of late 2012, were about $14 million per unit. This differs from the typical exchange wherein the granting of firm access on common carrier oil pipelines has been justified because it was valuable to shippers whose financial support was required to underpin the substantial capital costs of commercially at-risk infrastructure. The Funding Participants have not, to date, committed to underpin the significant capital costs of the Enbridge Northern Gateway Project. The Funding Participants collectively hold the option to secure the entire contractible capacity on both the oil and condensate pipelines, and, therefore, the Funding Participants control access to the system. The Panel notes Northern Gateway's evidence that it holds executed precedent agreements for 15,900 cubic metres (100,000 barrels) per day in excess of the proposed contractible capacity of the oil pipeline and 1,590 cubic metres (10,000 barrels) per day in excess of the proposed contractible capacity of the condensate pipeline. Northern Gateway said that the option to enter into a precedent agreement remains open and it is encouraging parties to do so.
Under the terms of the pro forma transportation service agreements for both the oil and condensate pipelines, any party can request that capacity be made available by providing a backstopping agreement to fund the necessary technical studies and feasibility assessment. If there were competing requests for firm capacity which exceeded available existing capacity on either the oil or condensate pipelines, Funding Participants would be given priority in acquiring the available capacity. In such a case, Northern Gateway would consider a system expansion to accommodate the unallocated volumes, subject to satisfactory financial backstopping agreements being in place. The Panel notes that the backstopping agreement, which presumably would need to be in place to trigger such an application, has not yet been developed. The Panel is of the view that the form of the backstopping agreement could potentially have implications for pipeline access.
The Panel notes Northern Gateway's proposal that the oil pipeline would provide 3,975 cubic metres (25,000 barrels) per day of reserve capacity, which is equal to 5 per cent of the term shippers' committed volume of 79,490 cubic metres (500,000 barrels) per day, and that the condensate pipeline would provide 2,780 cubic metres (17,500 barrels) per day of reserve capacity, which is equal to 10 per cent of the term shippers' committed volume of 27,820 cubic metres (175,000 barrels) per day. The Panel is of the view that, if constructed, the oil export pipeline, in providing access to Pacific Basin markets, would be a significant and strategic addition to the western Canadian pipeline system overall. In the Panel's view, it would provide producers with valuable flexibility in their transportation options and allow for the development of a significantly broader range of customers. From a public interest perspective, these factors would, in the Panel's view, suggest that the uncommitted reserve capacity proposed by Northern Gateway be increased.
The Funding Support Agreements provide the right to the Funding Participants to acquire equity in the project commensurate with the option volume they hold, which is in turn determined by the number of units held. MEG holds a further option to purchase its equity in the form of direct ownership of portions of the asset. The direct ownership option could be as high as 13.23 per cent, with firm capacity on the pipelines equal to its ownership. The direct owner capacity, as contemplated by Northern Gateway, would not be operated as a common carrier. The equity agreement and the direct ownership agreement have not yet been negotiated. In the Panel's view, the form of these agreements, and the extent to which the Funding Participants elect to exercise their options, could potentially have implications for pipeline access.
The National Energy Board Act does not define or use the term common carrier, nor does it establish whether, and if so under what circumstances, priority access may be granted on an oil pipeline. Taken together with section 67, subsection 71(1) requires an oil pipeline to offer service under the same terms and conditions to any party wishing to ship on an oil pipeline. This obligation to provide open access to an oil pipeline is fundamental to the granting of a certificate to construct and operate an oil pipeline. Given the unique process undertaken by Northern Gateway to develop commercial support for the project, and the uncertainties identified in the foregoing discussion, the Panel finds that it would, at this time, be premature to determine whether Northern Gateway would operate in a manner consistent with its common carrier obligations. The Panel finds that it would be appropriate to consider Northern Gateway's common carrier status when it has finalized the commercial support for the project. In this connection, the Panel is of the view that this should occur when Northern Gateway seeks National Energy Board approval under Part IV of the National Energy Board Act for the tolls that it intends to charge on the pipelines. In this regard, in Conditions 22 and 23, the Panel has identified the information that Northern Gateway must include in its toll application.
The Panel has decided to remove the former part e) of Potential Condition 10, which would have required Northern Gateway to set aside a minimum of 10 per cent of the average annual capacity of each pipeline as reserve capacity for uncommitted shippers. As discussed, for oil pipelines operating as common carriers, capacity must be properly allocated between committed and uncommitted shippers, and this would be most appropriately considered when the commercial arrangements for the project have been finalized. Based on the evidentiary record of this proceeding, the Panel continues to be of the view that meaningful access for uncommitted shippers to a system of the scale and strategic importance of Northern Gateway would entail reserve capacity for both the condensate import and the oil export pipelines of not less than 10 per cent.
Section 58.5 of the National Energy Board Act describes a tariff as a schedule of tolls, terms and conditions, classifications, practices or rules and regulations applicable to the provision of a service by a company and includes rules respecting the calculation of tolls.
Northern Gateway's pro forma precedent agreement, pro forma transportation services agreement, and the pipeline toll principles cover tariff-related matters. Some of the tariff-related topics are: calculation and payment of tolls, pipeline and shipper obligations and liabilities, financial assurances from shippers, term of transportation services agreement and termination of the agreement, capacity apportionment, pipeline expansion capacity allocation, shipper audit rights, and Force Majeure conditions.
These terms and conditions would affect the basis on which both potential shippers that have signed precedent agreements and potential shippers without contractual arrangements would get access to pipeline services. For a common carrier pipeline these terms will determine if Northern Gateway's transportation capacity would be available on an open access basis.
In its application Northern Gateway said: The tariffs applicable to the operation of the pipelines will be described in Rules and Regulations published separately for the oil pipeline and the condensate pipeline. These Rules and Regulations will apply to Term Shippers and Non-Term Shippers. Provisions that are not operational in nature, such as financial assurances and invoicing, will be addressed in:
Northern Gateway's approach to tariff documentation would result in the tariff's terms and condition being distributed throughout multiple documents. One of Northern Gateway's obligations as a common carrier is to provide service with reasonable terms and conditions and to make these terms and conditions available to all categories of shippers and potential shippers in a clear and orderly way. The Panel must ensure that there is open access to these pipelines as required by the National Energy Board Act. To achieve this, the Panel directs Northern Gateway to prepare a single document that includes all tariff-related matters.
Fairness requires that prospective shippers know the terms of access to a pipeline in advance of contracting for capacity. This knowledge will allow market participants to make informed supply, market, and transportation decisions, which will contribute to the efficient functioning of the petroleum market.
The Panel notes that the precedent agreement and the pro forma transportation service agreement convey several benefits to the Founding Shippers. These benefits include significantly lower tolls than the other categories of shippers and priority rights to pipeline capacity. It is the Panel's view that the topics for the list of issues to be considered during the Part IV proceeding should include Northern Gateway's assessment of how the Founding Shippers' priority rights to the initial allocable capacity and future capacity releases and expansions result in no unjust discrimination in service or facilities as required by section 67 of the National Energy Board Act. The Panel is also of the view that the list of issues should require Northern Gateway to demonstrate that the terms of access to transportation capacity for potential shippers satisfy subsection 71(1) of the National Energy Board Act.
Pipeline operations, emergency preparedness and response, and the consequences of oil or condensate spills were dominant issues in this proceeding. Northern Gateway proposed several enhancements to reduce the risk of a hydrocarbon spill from its pipelines and the Kitimat Terminal. Even with these measures, some parties continued to have a concern that some risk of a large oil spill with catastrophic consequences would remain. This prompted parties to inquire about Northern Gateway's financial capability to manage the costs and liabilities associated with this risk that may cause damage to persons and the environment. Intervenors were looking for assurances from Northern Gateway that would demonstrate it has adequate financial resources to manage the consequences of a spill from the pipelines and the Kitimat Terminal. As a result, Northern Gateway was asked to prepare a financial assurances plan. Funds from this plan would be used to cover costs in the event of a spill from these facilities. It would not apply to spills from tankers offshore because these are covered under Canada's Marine Liability Act.
During the hearing most of the financial assurances submissions focused on the impacts and estimated cost of a large hydrocarbon spill, and Northern Gateway's financial capability to manage the resulting damages and costs.
What are financial assurances?
Financial assurances demonstrate that the pipeline operator has sufficient financial means or financial instruments in place to cover the costs of cleanup, damages, remediation, and liabilities that may arise from potential malfunctions, accidents, and failures during the operation of the pipeline. This comprises all large oil spills originating from the oil and condensate pipelines and tank and terminal facilities connected to the pipelines, including spills that have the potential of being catastrophic events.
Northern Gateway said in its application that the operator of a pipeline is responsible under statutory and common law for operating the pipeline in a safe and responsible way. Various federal and provincial statutes, including the National Energy Board Act, identify Northern Gateway's liability for prevention, cleanup, and remediation of an incident such as an oil spill. Northern Gateway said in the "unlikely event" of a spill it would implement measures to identify and remediate damage caused and address property loss and personal injury compensation claims fairly and efficiently. Northern Gateway acknowledged that it cannot give complete assurance that a large spill would not occur and that it would not be larger than average. Further, it expects that there could be a scenario where the spill costs may exceed the insurance coverage for a spill. Northern Gateway recognized that risk cannot be eliminated entirely. Regardless of whether or not insurance covers losses and liabilities of Northern Gateway and/or third parties, Northern Gateway said that it would cover the costs of the damages caused by a spill from the project's facilities.
Estimated cost of an oil spill
Northern Gateway said that the environmental and social consequences of a spill and related cleanup costs would depend on a combination of factors such as:
These factors result in each spill being unique and the costs being highly variable. Northern Gateway said that it would not be possible to predict the cost of any single spill accurately because of the interaction of these biophysical factors. In its reply evidence, Northern Gateway presented supplementary information that provided a basis for estimating the upper bound of average expected spill costs.
To simplify the complexities resulting from the interaction of these factors, Northern Gateway adopted the convention of estimating the costs of spills for a range of spill volumes and a range of unit costs ($ per barrel or $ per hectare). Northern Gateway separated the costs into:
Cleanup costs would be the direct, out-of-pocket costs for spill response and remediation. Environmental goods and services costs have less certainty than cleanup costs and may consist of damages arising from the losses of environmental goods and services such as waste treatment, erosion control, water regulation, pollination, biological control, subsistence food production services, and recreation.
The following equation summarizes Northern Gateway's approach to estimating spill costs:
To derive an expected annual cost from the estimated spill costs in the above equation, Northern Gateway multiplied these costs by the estimated probability of occurrence of a spill in 1 year. Combining total spill cost with the probability of occurrence resulted in an expected cost or an overall estimate of risk.
The cost expectations approach relies on estimated average values of spill volumes, damages caused by the spill, cleanup costs, and recovery periods. The expected cost represents the average value of a range of possible outcomes. Northern Gateway said that its use of average, rather than median, values in its calculations tended to increase the expected spill costs. Northern Gateway said that it has erred on the side of over-estimating environmental costs and that the average expected spill costs are upper-bound estimates. It said that both the spill volumes and the financial costs of spills in its supplementary information are treated as average expected values and fall on the high end of the values found in the survey of literature and industry experience.
Northern Gateway identified two categories of spills, based on spill quantity:
Northern Gateway said that large spills may have low probability of occurring and would have impacts with high total costs. It said that small spills may be more frequent and would have impacts with lower total costs. In the context of developing relevant financial assurance plans, this hearing focused on large volume spills.
Table 11.4 summarizes the range of estimated spill volumes from each pipeline for a full-bore rupture and a leak. One source for these volumes was Northern Gateway's semi-quantitative risk assessment. This assessment identified the risks of a full-bore oil pipeline rupture and the potential spill quantities along the entire length of the pipeline route.
Table 11.4 Estimated spill volumes (From Northern Gateway’s evidence)
|Source of Data||Spill Cause||Oil Pipeline||Condensate Pipeline|
|Northern Gateway analysis – expected average size||Full-bore rupture||2,238 cubic metres (14,100 barrels)||823 cubic metres (5,183 barrels)|
|Northern Gateway SQRA studies||Full-bore rupture||986 to 5,227 cubic metres (6,200 to 32,900 barrels) with median value of 2,104 cubic metres (13,200 barrels)||N/A|
|D.T. Etkin, US EPA-modelling of oil spill response and damage costs||Full-bore rupture||1,890 to 3,785 cubic metres (11,900 to 23,800 barrels)||382 to 1,890 cubic metres (2,400 to 11,900 barrels)|
|Northern Gateway analysis – expected average size||Leak||95 cubic metres (600 barrels)||95 cubic metres (600 barrels)|
|D.T. Etkin, US EPA-modelling of oil spill response and damage costs||Leak||38 to 380 cubic metres (238 to 2,380 barrels)||38 to 380 cubic metres (238 to 2,380 barrels)|
Northern Gateway said that its estimated spill volumes, costs, and probabilities of spill occurrence were based on consideration of relevant literature, Enbridge's experience with eight oil spill incidents between 2001 and 2011, four oil spill cases in Alberta and British Columbia between 2000 and 2011, and its pipeline semi-quantitative risk assessment. It said that the literature survey was broadly scoped and helped inform its analysis and selection of values for spill volumes, costs, and probability of occurrences. Northern Gateway said that Enbridge's experience with 8 oil spill incidents between 2001 and 2011 indicated that costs averaged about $62,900 per cubic metre ($10,000 per barrel) for all spills and about $15,700 per cubic metre ($2,500 per barrel) for 6 spills excluding the Marshall, Michigan spill and 1 other incident. Regarding the Marshall spill, the U.S. National Transportation Safety Board estimated that over 3,180 cubic metres (20,000 barrels) of oil spilled from Enbridge's Line 6B into a Michigan wetland in July 2010. As of the summer of 2012 the cleanup costs exceeded $767 million.
The key data for the four spills in Alberta and British Columbia between 2000 and 2011 are summarized in Table 11.5.
Northern Gateway's evidence showed that, although the cost information for some of these spill incidents is incomplete, the cleanup cost for the Plains Rainbow spill was about $15,725 per cubic metre ($2,500 per barrel). Its data showed that the cleanup and damage costs for the Lake Wabamun spill are estimated to be slightly over $189,000 per cubic metre ($30,000 per barrel). This high unit cost is attributed to the high values of the lake front property affected by the spill and the lake's important recreational role for the residents. Northern Gateway considered the high costs of the Marshall, Michigan spill, which were at least $252,000 per cubic metre ($40,000 per barrel), to be an outlier or a rare event because the spill occurred in a densely populated area, because the pipeline's response time was abnormally long, and because there was the prospect of potentially lengthy legal proceedings.
Northern Gateway's semi-quantitative risk assessment provided an estimate of the likelihood and consequences of various spill scenarios along the oil pipeline right-of-way. This risk assessment was based on several premises, including:
Northern Gateway said that the semi-quantitative risk assessment focused on pipeline ruptures because they would have the most extreme consequences. It said that the hazards and threats that could cause a full-bore rupture include:
Northern Gateway said that the semi-quantitative risk assessment provided estimates of spill volumes and likelihood of a major spill in high consequence areas within the 1-kilometre-wide Project Effects Assessment Area and other high consequence areas outside this 1-kilometre-wide area. High consequence areas outside the project area include: parks, urban areas, Indian Reserves, wildlife habitat, watercourses, and water intakes. The Fraser, Kitimat, and Skeena drainage areas are examples of high consequence areas. The failure frequency of the pipelines was estimated from reliability methods and expert judgement. The consequence of a spill includes consideration of the magnitude of the spill volume, the extent of the spread of a spill, and the sensitivity of the spill area to an oil spill event.
The model used in the semi-quantitative risk assessment divided the pipeline into 1-kilometre-long segments, which in turn were separated into 20 segments that were each 50 metres long. This resulted in 23,000 elements, and the modelling and analysis of 23,000 hypothetical spills. Within each one-kilometre segment the largest rupture volume of the 20 elements was taken as the expected rupture volume. With the selection of the largest of the 20 values in each 1-kilometre-long segment, Northern Gateway determined that the average size of spill on the oil line would be greater than the average of the 23,000 hypothetical spills evaluated along the 1,178-kilometre-long pipeline route. Figure 11.2 summarizes the oil spill volumes generated in the semi-quantitative risk assessment simulations. The estimated oil release volumes ranged from 986 to 5,227 cubic metres with a median volume of 2,104 cubic metres.
The semi-quantitative risk assessment did not generate an estimate of economic losses caused by a spill. Northern Gateway relied on its analysis of literature, and spill events experienced by Enbridge and other liquid hydrocarbon carriers in Alberta and British Columbia. After assessing all of this information, Northern Gateway proposed spill parameters, estimated oil spill costs, and the probabilities of a spill occurring. These are summarized in Table 11.6.
Northern Gateway said that the return period is the average interval between events, over an extended period of time. Annual probability is the inverse of the return period.
Northern Gateway regarded the costs in the summary Table 11.6 as conservative (i.e., high). In Northern Gateway's view the most costly pipeline spill incident would be a full-bore oil pipeline rupture, with an estimated cost of $200 million, and an extremely low probability of occurrence.
Table 11.5 Oil Spills in Alberta and British Columbia between 2000 and 2011
|Year||Spill Description||Volume of Spill||Spill Environment||Spill Costs|
|2000||Pine River crude oil spill in near Chetwynd, British Columbia||985.72 cubic metres, or 6,200 barrels||Land and fresh water||
|2005||Lake Wabamun bunker oil spill from freight train near Whitewood Sands, Alberta||695.57 cubic metres, or 931 barrels||Land and fresh water||
|2007||Trans Mountain spill of heavy synthetic crude oil into Burrard Inlet||238.48 cubic metres, or 1,500 barrels||Marine||
|2011||Plains Rainbow crude oil spill northeast of Peace River, Alberta||4,451.64 cubic metres, or 28,000 barrels||Remote, densely forested muskeg||
Northern Gateway identified the following potential financial resources that could play a role in in meeting its obligations in event of a spill:
Northern Gateway said that its asset base would generate $400 million of annual cash flow during normal operations and may facilitate borrowing arrangements. Its pro forma financial statements show that the annual cash flow of approximately $400 million is before dividend payments. These statements also show that the dividend payments are 100 per cent of the net income. Northern Gateway acknowledged that the dividend payments may be greater than the net income providing there is compliance with limited partnership and accounting obligations. The company said that if there were an incident involving a spill, the payouts to the equity investors would be reduced so that obligations arising from the spill would be met first.
Although Northern Gateway said that it would arrange for stand-alone, third party liability insurance of $250 million to cover damages in the event of an oil spill, it said that insurance details should be addressed later after detailed engineering is completed.
Northern Gateway said that losses and claims in excess of liability insurance payouts could be funded by:
Northern Gateway said that it would put a financial facility in place to pay bills while insurance claims are being processed. It said that it would have access to sufficient resources to cover cleanup and compensation costs. In the event that Northern Gateway cannot meet its financial obligations it would not have access to Enbridge's financial resources in excess of Enbridge's equity investment in the project. Enbridge is not prepared to consider an ownership structure that would result in Enbridge assuming more financial risk than its ownership share in the project.
Northern Gateway committed to investing $500 million in additional facilities and mitigation measures such as thicker wall pipe, more block valves, more in-line inspections, and complementary leak detection systems to enhance the reliability of the system and reduce the risk of a spill. In Northern Gateway's view these measures are a form of insurance that would reduce the need for liability insurance.
Figure 11.2 Map showing the pipeline route with hydrologic zones and corresponding graph of oil spill volumes from semi-quantitative risk assessment simulations for the oil pipeline
Northern Gateway said that it would be well capitalized, and would have very significant resources, so there would be no need to take any additional steps such as obtaining a guarantee from Enbridge. Because of these financial resources and the ownership structure, Enbridge reiterated its commitment to bear financial responsibility proportionate to its ownership share.
Northern Gateway accepted the need to develop a financial assurances plan providing it was based on facts and reasonable costs on the record in the proceeding and not costs of an outlier nature. Northern Gateway requested that the Panel treat it consistently with the rest of industry regarding the financial obligations in the plan. In the event that any regulatory changes are implemented to standardize financial assurance requirements for pipelines, Northern Gateway proposed that Potential Condition 147 should be superceded and the requirement to file a financial assurances plan should be modified or withdrawn.
Table 11.6 Northern Gateway’s Summary of Representative Parameters for Oil Spill Cost Calculations
|Spill Parameter||Marine Terminal Spill||Oil Pipeline, Full-Bore Rupture||Oil Pipeline, Other Spills|
|Mean Size||1,575 barrels||14,100 barrels||600 barrels|
|Return Period||61 years||240 years||4 years|
|Cleanup Costs||$11,000 per barrel||$4,000 per barrel||$9,000 per barrel|
|Damage Costs||$9,000 per barrel||$10,000 per barrel||$800 per barrel|
Note: The estimate for the marine terminal spill includes both oil and condensate handling.
The Alberta Federation of Labour recommended that Northern Gateway be required to carry a minimum of $1 billion mandatory insurance coverage annually on a stand-alone basis for the project as long as it operates. This floor of $1 billion was influenced by claims experience of other pipeline operators such as PG&E that experienced a gas pipeline explosion in San Bruno, California. The Federation said the Panel's potential financial assurances condition should be maintained as drafted.
Coastal First Nations, the Gitga'at First Nation, the Gitxaala Nation, and Haisla Nation filed evidence that described their concerns about the impact of oil spills on their territory, livelihood, and culture. Much of this evidence addressed the effects of oil spills in the marine environment. Haisla's evidence also included estimates of damages that terrestrial oil spills would cause.
Haisla Nation estimated the cost of damage to ecosystem services because of a terrestrial oil spill from Northern Gateway's pipeline would be in the range of $12,000 to $610 million for a 30-year period. The Haisla's cost estimates were based on values for environmental goods and services and probabilities of spills that were independent of Northern Gateway's parameters for estimating oil spill costs. In contrast to Northern Gateway's estimated spill frequency and costs, the Haisla predicted that spills would occur more often and placed a higher value on damages to environmental goods and services.
Haisla Nation argued that Northern Gateway overestimated its ability to detect and respond to a spill. In the Haisla's view this resulted in the cost of a spill and the requisite financial assurances being understated. Haisla cited several factors, including: remote location, limited access, challenging terrain, seasonal conditions, and river flow conditions that would cause the cost of cleaning up a spill in the Kitimat River valley to be significantly greater than the costs associated with Enbridge's Marshall, Michigan spill. For these reasons, Haisla proposed that Northern Gateway should be required to obtain a minimum of $1 billion of liability coverage through insurance and financial assurances. Haisla said that Northern Gateway should file annually the report from an independent third party assessing the financial assurances plan.
Gitxaala Nation filed evidence assessing Northern Gateway's expected value approach for evaluating the risks of this project. The expected value methodology combines the probability of the event with the severity or estimated cost of the event to yield a single monetary number. Gitxaala Nation said this methodology is not suitable for assessing the risks of this project because it tends to discount the consequences of catastrophic events. In Gitxaala Nation's view, the Enbridge Northern Gateway Project is at risk for low probability events that would be unexpected and would have highly adverse effects. These events would be catastrophic and should not be discounted out of the risk analysis as the expected value approach does.
Basing its analysis on Northern Gateway data, Douglas Channel Watch provided estimates of spill probabilities for six regions along the pipeline route, and for the six regions combined. The estimated probability of at least 1 medium spill of less than 1,000 cubic metres, or 1 large spill of more than 1,000 cubic metres, in a 50-year period, is 82.8 per cent for the 6 regions of the pipeline combined. When the results for medium and large spills from the Kitimat Terminal, the pipeline, and maritime transport are combined, the probability of at least 1 medium or large spill, over a 50-year period, is about 87 per cent.
MEG Energy said that it would be premature to determine the specific minimum amount of financial coverage at this time.
Nathan Cullen said that the proposed $950 million in financial assurances was unacceptably low.
Terry Vulcano said that Enbridge should have an insurance policy of $5 billion to cover its spill liability.
The United Fishermen and Allied Workers' Union said that, if the project proceeds, it should carry an insurance policy that would cover at least the costs of the most recent spills in the United States so that two payouts within a short time could be made, if required.
The Office of the Wet'suwet'en expressed concern that the damages that Northern Gateway would contemplate recognizing, following a pipeline spill, would not include, nor address, cultural losses. Because Northern Gateway said that there is no acceptable way of quantifying cultural effects in economic terms, the Wet'suwet'en interpret this as a tacit acknowledgement that these damages would be of an irreparable nature.
The Province of British Columbia opposed Northern Gateway's proposed amendments to Potential Condition 147.
The Coalition said that the Panel was correct in the amounts and form of financial security described in the financial assurances condition. It argued that the amount specified in Potential Condition 147 should be maintained regardless of any change to a pipeline regulatory regime.
In letters of comment many parties expressed concerns about the risk and unacceptable consequences of an oil spill. A few parties commented on insurance to cover the costs of spill. Regardless of whether the parties commenting on the insurance supported, opposed, or were undecided about the project, they were in agreement that Northern Gateway must have adequate third party liability insurance coverage to compensate for third party damages and liabilities.
Northern Gateway said that Haisla's findings were based on anumber of fundamental methodological flaws and a lack of probability analysis to support the high frequency of occurrence of oil spill events. Northern Gateway argued that Haisla's estimates of ecosystem service values were inflated because they were based on values from unrelated studies. In Northern Gateway's view, Haisla relied on high passive use values that were not justified.
Northern Gateway did not accept the Alberta Federation of Labour's rationale for the level of third party liability insurance that the Federation proposed. It felt that a lower amount was the appropriate threshold.
During the proceeding, several parties stated their expectation that Northern Gateway must operate this project to a high standard so that there is little risk of damaging the environment or the property of others. If there is a malfunction, accident, or failure that causes an oil spill during the operation of the pipelines and the Kitimat Terminal, the Panel finds that Northern Gateway must have the financial capability to pay for the damages and losses while also responding effectively with cleanup and remediation action.
Several times during the hearing Northern Gateway said that it would cover any loss or damage that is directly attributable to its operations. The Panel notes that Northern Gateway also said that, regardless of whether its insurance would cover losses and liabilities of third parties, Northern Gateway would compensate for the damages which it has caused. The Panel finds that this is confirmation that Northern Gateway has accepted the "polluter pays" principle.
The Panel is of the view that major industrial projects, such as the Enbridge Northern Gateway Project, must operate to minimize the risk of damages to the environment and the public. Should the project cause damage, the operator should be responsible for the costs of such damages. This requires the Panel to examine the potential costs of a large oil spill and Northern Gateway's financial capability to pay for the damages and losses caused by a spill. The responsibility for these losses and damages must be borne by Northern Gateway and not by third parties or the public.
Many factors influence the costs, including location, type of product spilled, the quantity of the spill, and the kind of cleanup and remediation required in each unique circumstance. Costs anywhere along the pipeline right-of-way and at the marine terminal must be covered. While the Panel heard evidence of costs associated with offshore spills in the marine environment, these matters are covered under Canada's Marine Liability Act. The Panel has not discussed compensation for marine spills in this chapter. Chapter 7 provides additional information on financial responsibility and compensation for marine shipping spills.
Northern Gateway provided estimated probabilities and return periods of oil spills occurring along the pipelines and at the marine terminal, over the life of the project. Haida Nation considered the probabilities presented by Northern Gateway to be much lower than would actually be the case.
During the hearing Northern Gateway and intervenors provided estimates of spill probabilities for the project and its components. The estimates covered a broad range of probabilities and generated controversy. There was no consensus on the return periods or probabilities of oil spills in similar circumstances. In the Panel's view, the return period of an event is an estimate of the frequency of that event stated in years. The return period or recurrence interval is the average time between events over an extended period of time. However, it is not a prediction of when the event will occur. When determining the financial assurances that Northern Gateway should provide, the Panel did not use probability data. The evidence indicates that there is some probability that a large oil spill may occur at some time over the life of the project. In these circumstances the Panel must take a careful and precautionary approach because of the high consequences of a large spill. The Panel has decided that Northern Gateway must arrange and maintain sufficient financial assurances to cover potential risks and liabilities related to large oil spills during the operating life of the project.
Northern Gateway committed to investing $500 million in additional facilities and mitigation measures such as thicker wall pipe, more block valves, more in-line inspections, and complementary leak detection systems. This initiative should enhance the safety and reliability of the system and help reduce and mitigate the effects of a spill, but it would not eliminate the risk or costs of spills. This initiative is not a direct substitute for third party liability insurance and does not eliminate the need for liability insurance or any other form of financial assurance to cover the cost of a spill.
The results of the semi-quantitative risk assessment assisted Northern Gateway in identifying the risks of full-bore ruptures along the pipeline route and prioritizing mitigation measures through route revisions and the addition and enhancement of facilities. The Panel found that the semi-quantitative risk assessment provided additional insight into risks that might cause pipeline spills, and also provided insight into mitigation measures to reduce the risk and consequences of a spill. This analysis also helped the Panel develop a better understanding of the range of spill consequences on people, property, and the environment along the pipeline route. The Panel supports Northern Gateway's continued use of this tool in the detailed design of the pipelines to identify and develop risk-mitigation measures. The Panel also believes it could be used beneficially by other pipeline proponents and operators of existing pipelines.
The Panel has decided that Northern Gateway must provide a total of $950 million in financial assurances to cover the costs of a large oil spill, including one that has the potential to be catastrophic. This amount is based on a large spill with costs for clean-up, remediation, and damages totaling $700 million. In addition to the financial instruments providing the primary coverage of $700 million, Northern Gateway must put backstopping arrangements of at least $250 million in place to cover any shortfalls in the primary coverage.
The Panel used the values of 2 variables to estimate the $700 million spill cost: i) the estimated quantity of a potentially large oil spill, and ii) the estimated total unit cost of an oil spill. The costs for cleanup, remediation, and damages would be captured in this total unit cost. The damages could include a range of items, including some allowance for damage to the ecosystem.
Based on the hearing record, the Panel finds that the estimated costs for damages to ecosystem goods and services are neither well developed nor currently broadly accepted. The evidence of Northern Gateway and the intervenors showed widely divergent cost estimates, sometimes orders of magnitude apart. In addition, the actual costs for historical spills did not identify all components making up total costs.
Regarding the Office of the Wet'suwet'en's concern about potential cultural losses, the Panel agrees that some aspects of cultural activity cannot be described in economic terms. To the extent that activities contribute to a culture, and monetary values can be attributed to these activities, the Panel should take these into account.
Considering these factors in combination with the unique circumstances of each spill, and the need to take a careful and precautionary approach, the Panel decided that the methodology does not currently exist to segregate the cost of components making up the total cost of a spill. It decided to use the total unit cost based on the available evidence, which was not complete enough to support disaggregation of the data. In addition, the weighting of the components may vary on a case-by-case basis.
Northern Gateway suggested that a large spill from the oil pipeline would have a volume of 2,242 cubic metres (14,100 barrels), and a large spill from the condensate pipeline would be 827 cubic metres (5,200 barrels). These estimates of a large spill volume were based on the expected average spill size from Northern Gateway's analysis. From the semi-quantitative risk assessment, the Panel notes the largest oil spill volume is approximately 5,000 cubic metres (31,500 barrels). Another source referenced by Northern Gateway proposed a volume, in the upper range of large spill volumes from the oil pipeline, of 3,800 cubic metres (23,800 barrels). The Panel has decided on a spill volume of 5,000 cubic metres (31,500 barrels). The Panel finds that the costs associated with an oil spill volume of 5,000 cubic metres would also cover the costs of a spill from the condensate pipeline.
The Panel accepts that the cleanup costs for the Marshall, Michigan spill were orders of magnitude higher because of the extended response time. In this application, the Panel accepts Northern Gateway's commitment to complete the shutdown in no more than 13 minutes after detection. For this reason the Panel did not use the Marshall spill costs in its calculations. The spill volume and the resulting costs are directly dependent on the Northern Gateway's control room staff and the pipeline control system fully closing the adjacent block valves no longer than 13 minutes from the detection of an alarm event, as well as the amount of oil which would drain out of the pipeline after valve closure due to elevation differences.
The Panel decided on a total unit cost of $138,376 per cubic metre ($22,000 per barrel). This is midway between the unit cost of $88,058 per cubic metre ($14,000) per barrel proposed by Northern Gateway and the unit cost of $188,694 per cubic metre ($30,000 per barrel) for the Lake Wabamun spill. It is about one-half of the Marshall spill's unit cost. Giving weight to the Lake Wabamun costs recognizes actual costs experienced in a Canadian spill and the greater costs of spills in high consequence areas. In these areas, individuals, populations, property, and the environment would have a high sensitivity to hydrocarbon spills. The deleterious effects of the spill would increase with the spill volume, the extent of the spill, and the difficulty in accessing the spill area for cleanup and remediation.
Using these spill volume and unit cost values in the calculation below, the Panel estimated the total cost of a large spill could be $700 million.
The Panel based the financial assurances requirements for Northern Gateway on a spill with a total estimated cost of $700 million and directs Northern Gateway to develop a financial assurances plan with a total coverage of $950 million that would include the following components:
The financial backstopping would be available to fill the gap if the spill volumes or unit costs were under-estimated or if the payout from the core coverage would be less than 100 per cent. It would also compensate for the limited partnership's defined liability limits.
The instruments in the financial assurances plan and the proceeds from these instruments must be dedicated to covering the cost of a large oil spill or other malfunctions, accidents, and failures during the project's operations. At all times, Northern Gateway must isolate, to the fullest extent possible, the payout proceeds of the instruments in its financial assurances plan from its operations and financial circumstances, including potential insolvency.