IN THE MATTER OF
Pacific Northern Gas Ltd.
Application for a Certificate of Public Convenience
and Necessity
to Construct and Operate and Interconnecting Pipeline between
Kitimat and Douglas Channel
Decision
October 9, 2015
Before:
D. A. Cote, Commissioner / Panel Chair
K. A. Keilty, Commissioner
B. A. Magnan, Commissioner
Table of Contents
Page No.
2.0 Project description and justification
2.1 Project description, construction, infrastructure and approvals
2.1.4 Construction and infrastructure
2.1.5 Environmental and social impacts
2.1.6 Government approvals, authorizations, licenses and permits
3.1 Approval of the 10-inch and 30-inch interconnecting pipeline options
3.2 Waiver of CPCN requirements for a Class 3 estimate
3.3 Development, capital and operating costs
3.3.1 Recovery of development costs
3.3.2 Recovery of capital costs
3.3.3 Recovery of operating costs
3.4 Consideration of
Clean Energy Act and alignment with Provincial Government energy
objectives
4.1 Public and stakeholder consultation and support
4.1.2 First Nations engagement
4.1.3 Other stakeholder engagement
4.2 Terms and conditions of Transportation Agreements
4.2.1 Modernization and harmonization of terms
4.2.2 Practical issues of gas balancing with multiple shippers and multiple pipe segments
4.3 Potential conflict of interest
5.0 CPCN determination and approval of the agreements
5.1 CPCN Commission determination
5.2 Approval of the agreements
6.1 Summary of reporting requirement submissions
Order C-10-15
Appendix A List of Exhibits
1.0 Introduction
1.1 Background
Pacific Northern Gas Ltd. (PNG) filed its Application for a Certificate of Public Convenience and Necessity (CPCN) to construct and operate an interconnecting transportation pipeline (Interconnecting Pipeline) of approximately 8 kilometres (km) between Kitimat and Douglas Channel. PNG proposes to construct either a 10-inch diameter or a 30-inch diameter pipeline for the transportation of natural gas from the terminus of PNG’s existing pipeline in Kitimat to proposed liquefied natural gas (LNG) project sites on the Douglas Channel. The pipeline is being constructed to allow service related to Transportation Reservation Agreements (TRAs) executed by PNG to be provided by this Interconnecting Pipeline. One TRA is with EDF Trading Limited (EDFT) and relates to the proposed Douglas Channel LNG project (DC LNG) while the second TRA is with Triton LNG Limited Partnership (Triton) and relates to the proposed Triton LNG project. The decision of whether to build a 10-inch or a 30-inch diameter pipeline will be based on the certainty of projects which will be determined subsequent to granting the CPCN.0F[1]
This Application filing follows the Commission’s recent acceptance and approval of a Firm and Interruptible Gas Transportation Service Agreement (GTSA) between PNG and EDFT which was granted under Order G-5-15 on January 15, 2015. The EDFT GTSA stipulates that PNG’s existing 10-inch diameter gas pipeline to its terminus in Kitimat is to supply transportation services for the DC LNG project.1F[2]
1.2 Approach to the decision
This decision is unique in that due to circumstances related to the timing of Final Investment Decisions (FID) being made on either the DC LNG or Triton LNG projects, PNG is presenting both a 10-inch and 30-inch option and has requested the review be expedited. Further, rather than filing for approval of what it considers to be an optimum solution to the need, PNG has requested approval to make a final construction decision to build one of two sized pipelines based on circumstances which will evolve subsequent to approval of this Application.
This Decision is separated into six sections:
Section 1.0 provides background, an outline of the regulatory process and the requested approvals to be addressed in the sections that follow.
Section 2.0 provides a description of the Interconnecting Pipeline project and evaluates the need and benefits of completing the project and the risks associated with it.
Section 3.0 provides an examination of the key issues that have been raised within the proceeding that require Panel review and determinations. Included among these are discussions on approval of both the 10-inch and 30-inch pipeline options, the inclusion of costs in tolls paid by shippers, escalations in operating costs and alignment with Provincial Government Energy Objectives.
Section 4.0 includes other issues including public, stakeholder and First Nations consultation, terms and conditions of transportation agreements and the proposed construction and operating schedule.
Section 5.0 includes the Panel’s determination on the CPCN and approval of agreements related to this Application.
Section 6.0 outlines the reporting requirements set out for the execution of the Interconnecting Pipeline Project.
1.3 The applicant
PNG is a company formed under the laws of British Columbia (BC) that is wholly-owned by AltaGas Utility Holdings (Pacific) Inc. (AltaGas) and has an office location in Terrace, BC with its head office located in Vancouver, BC.
PNG serves approximately 20,400 residential, commercial and industrial customers located in northwestern BC through its PNG West division and provides natural gas transmission, distribution and sales services. PNG West’s transmission pipeline is connected to Spectra Energy’s pipeline system near Summit Lake, BC extending westward to the BC west coast at both Prince Rupert and Kitimat. PNG West owns and operates in excess of 1,022 km of transmission pipeline including 592 km of mainline transmission pipeline and lateral transmission lines that extend into the various communities served by the Company. PNG states that in conjunction with the closure of the Methanex methanol/ammonia facility in Kitimat in 2005 it deactivated its compressor stations in Vanderhoof and Telkwa as well as sections of 6- and 10-inch pipeline. These facilities have been maintained for future use and as PNG prepares its system to provide service under the EDFT GTSA, they will be refurbished and reactivated.
PNG owns and operates distribution facilities for natural gas which includes approximately 950 km of distribution mains and 690 km of service lines. These deliver natural gas from PNG’s transmission pipeline system to homes and businesses in the BC communities of Prince Rupert, Port Edward, Kitimat, Terrace, Smithers, Telkwa, Houston, Burns Lake, Fraser Lake, Fort St. James and Vanderhoof. PNG West also operates a propane vapour system in the town of Granisle serving 150 customers. PNG is also the parent company of Pacific Northern Gas (N.E.) Ltd., a provider of sales and transportation services to approximately 20,000 residential, commercial and industrial customers in the northeastern BC communities of Fort St. John, Dawson Creek and Tumbler Ridge.
PNG states it can finance the Interconnecting Pipeline either directly or indirectly through its association with the AltaGas group of companies. It states that AltaGas has stable cash flow, investment grade credit ratings (DBRS and S&P [BBB]) and balance sheet strength that provides good access to capital markets for business and investment needs. PNG reports that AltaGas shares have an over $5 billion market capitalization and the company has an approximate $9 billion enterprise value.2F[3]
1.4 Approvals sought
PNG seeks Commission approval of the following:
1. Approval, pursuant to sections 45 and 46 of the Utilities Commission Act (UCA), for a CPCN for the construction and operation of an 8.8 kilometer interconnecting pipeline between Kitimat, British Columbia, and the Douglas Channel area, consisting of either:
(i) A 10-inch diameter transportation pipeline and related compression and metering facilities, or
(ii) A 30-inch diameter transportation pipeline and related compression and metering facilities.
3. Approval, pursuant to section 58 of the UCA, for the Interconnecting Transportation Reservation Agreement (TRA) between PNG and EDFT dated January 23, 2015 including the form of TSA attached thereto; and
4. Approval, pursuant to section 58 of the UCA, for the Interconnecting TRA between PNG and Triton dated July 22, 2015 including the form of TSA attached thereto.3F[4]
PNG submits that the approvals it seeks are in the public interest and will allow it to put in place the infrastructure and rate structure necessary to support the advancement of the DC LNG and the Triton projects. In addition, these projects greatly improve the likelihood that all PNG customers will realize future rate benefits under the EDFT GTSA.4F[5]
1.5 Regulatory process
PNG states that regulatory approval of the Application is required by September 30, 2015 to meet the decision making timelines imposed by DC LNG, its customer. DC LNG anticipates making its FID in the fourth quarter of this year and as a requirement, regulatory approvals for the Interconnecting Pipeline need to be in place. Accordingly, the Company has requested an expedited review of the Application. Subsequent to this PNG, in response to BCUC IR 1.8.3.1 indicated that it did not believe a Commission decision on or before October 9, 2015 would materially impact this FID.5F[6]
On July 22, 2015, the Commission by Order G-122-15 issued the Regulatory Timetable outlining the initial dates for intervener registration and one round of information requests (IRs). In addition, the Commission requested interveners provide comment in writing by August 11, 2015 on whether a written process or a combination of written and streamlined review process (SRP) was preferred to review the Application. On August 14, 2015 by Order G-137-15, the Commission amended the Regulatory Timetable for an expedited review process. This provided for a tight timeline with a second round of IRs responded to by September 10 and final and reply arguments completed by September 23, 2015.
Three interveners registered to take part in the review of the Application:
• BC Public Interest Advocacy Centre, on behalf of the British Colombia Old Age and Pensioners Organization (known as BCOAPO);
• LNG Canada Development Inc. (LNG Canada); and
- British Columbia Hydro & Power Authority (BC Hydro).
2.0 Project description and justification
2.1 Project description, construction, infrastructure and approvals
2.1.1 Overview
As noted, PNG proposes to finance, construct and operate a natural gas pipeline and related infrastructure to transport natural gas from the end of its existing mainline located southwest of the Kitimat town site to sites along the rugged west side of the Douglas Channel. The project is being undertaken at the request of DC LNG and Triton LNG whose proposed floating natural gas liquefaction facilities would be supplied by the Interconnecting Pipeline The start of construction is, among other conditions precedent, contingent on the foundation shipper, EDFT, approving the project and making financial commitments to PNG through the execution of a Service Agreement.6F[7] The target completion date of the Interconnecting Pipeline is July 1, 2017.
2.1.2 Pipeline options
PNG is proposing to construct either a 10-inch or a 30-inch diameter pipeline. The proposed 10 inch diameter pipeline would have a capacity of 36 cubic meters per second [110 million cubic feet per day or 110 mmcfd], sufficient to meet the requirements of EDFT contract. The upper range of the capacity of the proposed 30-inch diameter pipeline is approximately 460 cubic meters per second [1,400 mmcfd], sufficient capacity for both EDFT and Triton LNG’s proposed LNG export facilities located at the same proposed termination point of the Interconnecting Pipeline. In addition, the 30-inch option could also provide capacity for Cedar LNG which is proposing LNG facilities further south on Douglas Channel.7F[8]
The 10-inch option would be supplied with natural gas from the excess capacity on PNG’s existing pipeline under the terms of the GTSA between PNG and EDFT approved by Commission Order G-5-15 on January 20, 2015. As PNG’s existing system does not have the capacity to supply the 30-inch option, a new pipeline will be required to provide the additional supply. One option for additional natural gas supply is PNG’s proposed Looping Project. This would loop or twin the existing natural gas transmission pipeline between Summit Lake and Kitimat8F[9] for which PNG has filed a Project Description with the BC Environmental Assessment Office.
The issues related to whether the Panel should grant a CPCN allowing PNG to make a decision at a later date as to whether to move forward with a 10-inch or a 30-inch option will be discussed further in Section 3.1.
2.1.3 Pipeline routing
The proposed pipeline route traverses Haisla Nation, Crown and privately held lands.9F[10] The route starts at the terminus of PNG’s existing mainline near the former Methanex site and heads west for approximately two km. It then turns south for approximately seven km initially paralleling the west side of the Rio Tinto Alcan facility and then continuing along the west bank of Douglas Channel. The initial two km section of the proposed route is located in an industrial area with existing and proposed infrastructure.
The proposed corridor is geologically constrained and several other pipeline proponents have an interest in it. Therefore, a corridor study has been initiated by the Ministry of Transport (MOT) to provide recommendations on a common corridor taking into account critical utility and road infrastructure required to serve south Douglas Channel as well as the needs of the proponents. In addition, PNG has initiated a Joint Corridor study along with Chevron Canada and Cedar LNG (a subsidiary of the Haisla Nation) to find a common corridor that can meet the needs of other pipeline proponents. The completion of the study is expected in September of 2015 at which point it will be shared with the MOT. It is expected to form critical input into the MOT study to be will be released later in the fall.10F[11]
The issues related to pipeline routing are discussed further in Section 4.1.3.
2.1.4 Construction and infrastructure
The project infrastructure consists of a pipeline, a compression station and metering facilities. The pipeline is either a 10-inch or a 30-inch buried steel pipe with a maximum operating pressure of approximately 6,100 kilopascals (kPa) [900 pounds per square inch].11F[12]
The compression station is a building housing a compressor unit which consists of an electric or gas motor driving a compressor. For the 10-inch option, the proposed compressor is estimated to be a 1.1 megawatt [1,500 horsepower] reciprocating or piston type compressor. The compressor power rating for the 30-inch option would be approximately 17.3 megawatts [23,200 horsepower] and would likely be a centrifugal or turbine type compressor. 12F[13] PNG states the most likely location of the compressor station is at the old Methanex gate station at the start of the pipeline route.13F[14]
The proposed metering facility is a skid mounted unit consisting of one or more meters and valves located at the customer delivery point at the south end of the pipeline.
PNG is proposing the project be built over two summer-to-fall construction seasons with the major clearing and grade work occurring in 2016 and the pipeline and facilities construction following in 2017.14F[15] The TRA between PNG and EDFT contemplates PNG making a commitment to use commercially reasonable efforts to complete the Interconnecting Pipeline by July 1, 201715F[16]
2.1.5 Environmental and social impacts
PNG estimates the construction of the Interconnecting Pipeline is expected to require a workforce ranging from 200 to 300 positions for both the 10-inch and 30-inch options. Once operational, PNG does not anticipate the need for any additional staff to operate and maintain the Interconnecting Pipeline.16F[17]
PNG proposes to use horizontal directional drilling to bore under stream crossings to minimize disturbance of sensitive stream habitat.17F[18]
At the time of the Application, PNG had not determined whether an electric or gas drive would be used to power the compressor. A gas drive compressor would produce significantly more greenhouse and other air emissions than an electric-drive compressor.18F[19]
This issue is further discussed in section 3.3.
2.1.6 Government approvals, authorizations, licenses and permits
PNG states that the Interconnecting Pipeline project does not fall within the definition of a project required to file a separate British Columbia Environmental Assessment application.19F[20] When an environmental assessment is not required, the lead permitting agency for natural gas pipelines is the BC Oil and Gas Commission (OGC) operating under the mandate of the Oil and Gas Activities Act. Prior to the start of construction, PNG is required to obtain a new facility permit from the OGC which will consider PNG’s submitted environmental studies, community consultations and technical documentation. A Master Licence to Cut is required to start the clearing of the right-of-way.20F[21]
2.2 Rate design
2.2.1 Rate design principles
PNG adopted the following rate design principles in establishing a proposed rate structure for service on the Interconnecting Pipeline:
• Rates will be paid only by those parties reserving service on the new facilities;
• Rates will be set to recover the increase in the cost of service resulting from the construction and operating of the Interconnecting Pipeline such that there will be negligible rate impacts on PNG-West customers which do not utilize service on the Interconnecting Pipeline; and
• Rates will be set to recover the capital cost of the facilities over the term of the TSAs, so that there is no stranded asset risk for PNG or its customers when the TSAs expire.21F[22]
PNG proposes establishment of a new rate schedule based on these principles to apply to any customer executing a TSA for service on the Interconnecting Pipeline.22F[23]
Issues related to rate design are addressed in Section 3.0.
2.2.2 Toll calculations
The calculation method for toll charges on the Interconnecting Pipeline is contained in Schedule D to the form of TSA with EDFT and Triton (Toll Calculation).23F[24] The Toll Calculation is based on the incremental costs of the Interconnecting Pipeline and is designed to encompass several scenarios, including the construction of a 10-inch pipeline or a 30-inch pipeline. The Toll Calculation as outlined by PNG in its Application24F[25] covers three distinct time periods:
1. Period A: From completion of construction until the shipper’s service request date, where no toll is applied.
2. Period B: From the EDFT service request date until the service request date of a second shipper. Key features are as follows:
• Based on the costs and fees required to construct and operate a pipeline for EDFT only, with a capacity of 3,115 10³m³ per day. This is identified as the Base Toll. The Base Toll is calculated using the Base Capital Costs, which is defined as: “… either (i) the actual capital cost of the Interconnecting Pipeline if the Interconnecting Pipeline is constructed with a capacity of 3,115 10³m³ per day (the “Base Capacity”); or (ii) the estimated capital cost of an Interconnecting Pipeline sized for the Base Capacity if the Interconnecting Pipeline is constructed with a capacity exceeding the Base Capacity.”
• An annual straight-line depreciation rate based on the primary term of EDFT’s TSA, or 20 years.
• A fixed OMG&A charge of $60,000 in 2013 dollars that will be inflated annually thereafter by the Consumer Price Index.
• No Interruptible Charge is payable by the shipper.
3. Period C: From the service request date of a second shipper until the end of the individual shippers’ respective TSA. Key features are as follows:
• Based on the costs and fees required to construct and operate a pipeline for more than one shipper, with a capacity of greater than 3,115 10³m³ per day and divided proportionately according to each shipper’s contracted capacity.
• A fixed OMG&A charge of $60,000 in 2013 dollars that will be inflated annually thereafter by the Consumer Price Index.
• An annual straight-line depreciation rate based on the commencement date of shipper’s respective TSA until the end of the primary term of the shipper with the latest end date of its primary term.
• Shippers will pay an Interruptible Charge equal to 70 percent of the unit demand charge.
Issues related to the toll calculations for capital and operating costs are included in Section 3.3. Approval of Agreements is included in Section 5.0.
2.3 Project need
In the Application, PNG outlines the justification for the Interconnecting Pipeline as being necessary to:
• Meet a request for firm service from a customer as established in PNG’s application for approval of the EDFT GTSA which was approved by the Commission in January 2015;25F[26] and
• Realize the rate benefits for existing customers from providing service under the EDFT GTSA. Completion of the Interconnecting Pipeline is an integral infrastructure component necessary for PNG to provide service to the DC LNG project;26F[27]
Subsequent to the approval of the EDFT GTSA, PNG has identified additional customers who may potentially be served by the Interconnecting Pipeline, including the Triton LNG project.27F[28]
2.4 Project benefits
PNG identifies that the primary benefits to be realized from the construction of the Interconnecting Pipeline arise from the DNG LNG project securing demand for existing capacity on the PNG-West pipeline system that has remained available from many years. PNG states that “PNG customers have the potential to benefit from the positive delivery rate impacts of increased volume throughput on the PNG-West system resulting from additional annual demand charge revenues of up to $16.665 million per year.”28F[29]
PNG outlines that revenue received from customers contracting for service on the Interconnecting Pipeline (Shippers) will be sufficient to cover all additional revenue requirements that result from construction and operation of the new pipeline with negligible impact to existing customers. To demonstrate the impact to existing customer, PNG provided a confidential example of PNG’s cost of service and revenues for 2019, indicating no rate impact as a result of the tolls and fees on the Interconnecting pipeline offsetting the costs of service impact.29F[30]
Issues related to project benefits included in Section 3.0.
2.5 Project risks
In the Application and responses to IRs, PNG outlined the following key project risks:
1. Construction and operations schedule
PNG indicates that the project schedule is predicated on receipt of Commission approval of the CPCN on or before September 30, 2015 in order to meet the DC LNG project proponents’ requirements for regulatory authorizations prior to the making a FID on the project.30F[31] PNG states that the key project risk is that receiving Commission approval after this date may result in the DC LNG proponents choosing not to make a positive FID on their project or to delay their decision which could result in higher project construction costs. This could compromise the economics of the proponent’s LNG project and jeopardize a positive FID.31F[32] PNG understands that securing a positive Commission decision is a critical milestone for DC LNG to achieve FID.32F[33]
2. Specific project risks
PNG presents the specific risks associated with construction of the Interconnecting Pipeline in Exhibit 4-4 of the Application and the high risk items are identified in Table 1:33F[34]
Table 1 Preliminary Construction Risk Register
PNG states it is comfortable the risks identified can be mitigated in order to achieve timely and successful completion of the project.34F[35]
3. Financial risks
PNG submits that there are no identifiable financial risks to PNG and its existing customers from the Interconnecting Pipeline. This is a result of PNG designing the toll calculation so that all capital and operating costs are recovered from the shippers, thereby eliminating the risk of asset stranding and ensuring that there are negligible rate impacts on PNG’s other customers.35F[36] In response to IRs, PNG states that shippers executing TSAs must be rated BBB or better and therefore, only a very remote risk of a shipper going bankrupt exists. In addition, PNG considers it reasonable to expect that it would be able to contract for firm service with a new party in such an event.36F[37]
PNG states that the underlying principle of full cost recovery from the Shippers contracting for service on the Interconnecting Pipeline remains the same under both the 10-inch and 30-inch diameter pipeline options.37F[38] In response to BCUC IRs 2.1.2 and 2.1.3, PNG states that given there is no immediate guaranteed benefits to existing customers, the financial risks associated with upsizing the Interconnecting Pipeline to the 30-inch option will not fall to its existing ratepayers.
The subject of risk will be addressed in Section 3.1.
3.0 Key issues
3.1 Approval of the 10-inch and 30-inch interconnecting pipeline options
PNG states that its proponents and potential customers have requested that it be ready from a technical and regulatory perspective to construct either a 10-inch or 30-inch interconnecting pipeline based on DC LNG’s FID and on the basis of financial commitments of other project proponents. Once FIDs have been made and there is certainty on which of the LNG projects will go forward, the Company will be able to determine the appropriate size of pipeline to be constructed.38F[39] PNG submits that it will only begin construction of the Interconnecting Pipeline after it has one or more executed TSAs in place. It further submits that there are no identifiable financial risks for the Interconnecting Pipeline as the risk of stranded assets has been eliminated and there are only negligible rate impacts on its other customers due to tolls being calculated to recover all capital and operating costs from the Shippers.39F[40]
The issue that needs to be considered is whether PNG has covered all risks as it has claimed and PNG’s ratepayers will bear only negligible risk in the event the Panel approves PNG’s request to make the final construction decision on either a 10-inch or the 30-inch pipeline options.
Noting that EDFT will have a TSA in place before initiation of pipeline construction, the Company states that payment of transportation service charges starting once the pipeline is completed, will be assured during the pipeline construction period. Further, termination of the TSA prior to the end of its term will require EDFT to pay an Early Termination Fee in accordance with its contract. This early termination fee is “the net present value of all future demand charges payable for service on the Interconnecting Pipeline.” PNG is confident these would be equal or greater than the capital costs of constructing the pipeline.40F[41]
PNG states that the TRA with Triton has no requirement for it to have a TSA in place prior to commencement of the construction of the 30-inch Interconnecting Pipeline. In response to what type of financial commitments would be required from either Triton or another proponent for the project to proceed with the construction of the 30-inch pipeline, PNG states:
At the time of commencement of construction of a 30 inch pipeline PNG will have confirmed the obligation of Triton LNG and/or another project to either pay the Reservation Fee under the Interconnecting Transportation Reservation Agreement between PNG and that party or to pay the demand charges under an executed Service Agreement between PNG and that party for firm transportation service on the Interconnecting Pipeline.
PNG’s counterparty to a Service Agreement for firm transportation service on the Interconnecting Pipeline must comply with the credit requirement provisions of section 17 of the General Terms and Conditions. It is PNG’s intention to also require that the obligations to pay the Reservation Fee under any Interconnecting TRA be secured in the same manner as payments under the Service Agreement, prior to undertaking construction of the 30-inch pipeline option.41F[42]
With respect to credit support required from EDFT and Triton prior to the commencement of construction on the Interconnecting Pipeline and the commencement date of the transportation service agreement PNG makes the following explanations.
EDF Trading Limited
PNG submits that it will not commence construction on the Interconnecting Pipeline until it has an executed TSA with EDFT. Therefore, EDFT’s tolls on the Interconnecting Pipeline commencing following completion of the project are assured throughout the period of construction of the Interconnecting Pipeline. In addition, if EDFT terminates the TSA prior to the end of its term, EDFT will be required to pay an Early Termination Fee in accordance with the Interconnecting Pipeline General Terms and Conditions regardless of the stage of completion of the project.42F[43]
The General Terms and Conditions (GT&Cs) attached to the form of TSA with EDFT include the credit requirements that would be applicable to EDFT as a shipper on the Interconnecting Pipeline.43F[44] As at the effective date of the TSA, EDFT must maintain the “Minimum Acceptable Rating,” which is defined in the GT&Cs as follows:
…at least two of the following: (i) “BBB” or better by Standard & Poor’s Financial Services LLC; (ii) “Baa2” or better by Moody’s Investors Service, Inc.; (iii) “BBB” or better by DBRS Limited; or (iv) other equivalent rating(s) from a recognized rating agency or agencies acceptable to Transporter [PNG]. In cases where ratings of the aforementioned rating agencies are different, the lowest credit rating shall be used to establish the applicable rating in respect of any entity. In the event none of the aforementioned rating agencies publish relevant ratings, Transporter, acting in its sole discretion, may determine whether the applicable entity would meet the relevant ratings if such rating agencies were to publish such ratings.44F[45]
Credit support in the form of an approved letter of credit may be required subsequent to completion of construction, depending on EDFT’s credit rating, in the amount of 12 or 24 months of monthly toll charges. In the event that EDFT does not meet the credit requirements of the GT&Cs, a guarantee may be provided by a creditworthy guarantor. 45F[46]
Triton
There is no requirement for Triton to execute a TSA prior to commencement of construction. However, the TRA with Triton requires it to pay the Reservation Fee if it does not terminate its TRA 10 days prior to construction of the project. PNG states that prior to commencement of construction of the 30-inch pipeline it intends to require that Reservation Fee and Post Construction Termination Fee obligations be secured in a manner identical to how those payments under the TSAs are secured. 46F[47]
In spite of the assurances offered by PNG, the Panel notes that there are two risks which must be considered in making a determination as to whether PNG is to be given the final construction decision as to the size of pipe;
• the allocation of risk of insolvency, bankruptcy or liquidation of interconnecting pipeline shippers; and
• PNG’s obligation to meet its construction schedule.
Risk of insolvency, bankruptcy or liquidation of pipeline shippers
PNG reports that EDFT is rated A3 by Moody’s and the likelihood is extremely remote that EDFT will become insolvent, bankrupt or liquidate over the construction or 20-year period of firm transportation services. Further, PNG notes that Shippers executing the TSAs on the 30-inch pipeline option are required to be rated BBB or better and likewise, the risk of these types of events are very remote.47F[48] Subsequent to these assertions and in response to BCUC IR 2.3.1, PNG noted that EDFT had been downgraded to Baa1.48F[49]
In the event of EDFT experiencing an event of insolvency, liquidation or bankruptcy, PNG stated it would attempt to mitigate any loss or damage related to non-payment for contracted services by seeking another partner interested in utilizing natural gas on or around the DC LNG project. With respect to the 30-inch Interconnecting Pipeline, PNG states: “Given the very capital nature of the LNG projects utilizing the Interconnecting Pipeline, it is reasonable to expect, though not fully certain, that the related project would want to continue operations…” Therefore, PNG believes it will be able to contract for transportation to the LNG project with a new party.49F[50]
In response to Commission IR 1.5.3.1 requesting PNG’s opinion as to whether the shareholder or the ratepayer on the existing system should bear responsibility for any stranded asset costs in the event of insolvency, liquidation or bankruptcy of shippers PNG stated:
PNG is of the opinion that, to date, its awarded rate of return on common equity has not included a premium to compensate PNG’s shareholder for assuming the full risk of customer bankruptcies or other terminations of service which result in the stranding of assets. To the extent that PNG’s allowed rate of return on common equity is set with a premium that appropriately compensates shareholders for stranded asset risk, the risk should be appropriately borne by its shareholder.
Acknowledging that there are no immediate guaranteed rate benefits for existing customers by increasing the size of the pipeline from 10-inch to 30-inch PNG considers it appropriate for it to accept the credit risk underlying the Interconnecting TRA and service agreements executed with Triton.50F[51]
Intervener submissions
BCOAPO submits that it is unusual for a utility to apply for approval of two different options in a single CPCN application. It is unclear as to the reason PNG was unable to obtain binding financial agreements with Shippers that were conditional on regulatory approval of the CPCN and allowed for variations to be made by the Commission.
With reference to PNG’s assertion that the risk of stranded assets is small, BCOAPO submits “it is completely unclear as to why PNG’s shareholder doesn’t assume this risk.”51F[52] Further, BCOAPO notes that there is a possibility that the cost of stranded assets could be borne by existing ratepayers in the event of default or insolvency of one or more Shippers. It submits that there is no assurance provided by PNG that these existing ratepayers will receive any financial benefit as compensation.
BCOAPO also expresses concern about the possibility that PNG is needlessly exposing the ratepayer to the risk of shipper insolvency or bankruptcy. It points out that EDFT may have received a credit downgrade and Triton has not been rated by a ratings agency. BCOAPO does not believe it makes sense for ratepayers to have to bear the risk based on what it terms to be “speculative future benefits.”52F[53]
PNG reply
In PNG’s submission, it was unable to obtain binding commitments from Shippers at this time. Further, it made good sense in terms of both reduced costs and environmental impacts to try to provide parties considering the need for transportation capacity the most time possible to make their decisions. PNG maintains that project proponents will have the necessary support to make a final FID on projects if the Commission approves both the 10-inch and the 30-inch options at the outset.
PNG asserts that BCOAPO is incorrect in characterizing ratepayers as getting nothing where a 10-inch pipeline is constructed for EDFT’s use only. The record is clear that existing customers will have substantial financial benefits. PNG acknowledges that upsizing the Interconnecting Pipeline to 30-inch from 10-inch has no immediate, obvious benefits to existing customers and states that it is not appropriate for these customers to take on any risk in this instance unless it is able to “demonstrate material benefits are accruing to its existing customers.”53F[54]
Concerning stranded asset risks, PNG again submits “that by setting PNG’s common equity risk premium at an appropriate compensatory level, the stranded asset risk would be borne by the shareholder.”54F[55]
PNG’s obligation to meet its construction schedule
PNG has stated that the outside completion date for the construction of the Interconnecting Pipeline is January 1, 2018. When asked in BCUC 1.9.12 whether there were any penalties or costs to the Company in the event the in-service date slips due to construction issues, PNG provided the following:
There are no specific provisions for penalties or liquidated damages in the agreements between PNG and the prospective shippers on the Interconnecting Pipeline. If PNG is unable to complete the Interconnecting Pipeline by the Outside Date of January 1, 2018 (subject to extension due to Force Majeure events), the agreements terminate unless an extension is mutually agreed.
PNG continued by stating that it could also be subject to payment of damages if it fails to comply with its obligation to use commercially reasonable efforts to construct and ready the pipeline for use by Shippers on or before July 1, 2017. PNG submits that the risks related to PNG’s obligation to meet its construction schedule will not be borne by existing ratepayers.55F[56]
Commission determination
The Panel approves PNG’s request for approval for construction and operation of either a 10-inch or 30-inch interconnecting pipeline between Kitimat, BC and the Douglas Channel area. The Panel also approves PNG’s request to make the final construction decision on either the 10-inch or the 30-inch option based on DC LNG’s final investment decision and on the basis of financial commitments of other project proponents. Once FID decisions have been made and there is certainty concerning the proposed LNG projects or other projects, PNG is directed to submit a compliance filing confirming the decision(s) by the earlier of within 30 days of this decision or by the end of 2015.
The Panel recognizes the significant benefits to existing PNG ratepayers under the EDFT GTSA will only be realizable with the construction and operation of a 10-inch Interconnecting Pipeline. The Panel support for this project is based on the steps PNG has taken to shield the existing ratepayer from many of the financial risks. An example of this is the TRAs that PNG has put in place with proponents. These protect the existing ratepayer from cost overruns related to the construction of both the 10-inch and 30-inch Interconnecting Pipeline options. In addition, PNG’s shareholder has accepted risks related to any failure on the part of PNG to meet its obligations relative to the construction schedule as well as committing to ensure that Reservation Fee and Post Construction Termination Fee obligations are secured in a manner identical to how payments under the TSAs are secured. Collectively, provisions such as these serve to demonstrate that the public interest has been served.
Providing PNG with the option of making its own decision as to whether to pursue the 10-inch or 30-inch Interconnecting Pipeline provides it with the certainty necessary to conduct the necessary negotiations. Moreover, the existing ratepayer is protected due to the requirements of TRAs including the form of TSAs and the fact that PNG has stated its shareholders will bear any risk for stranded assets related to the incremental costs associated with the 30-inch pipeline.
The one remaining issue is the handling of the risk of stranded asset costs on the 10-inch Interconnecting Pipeline (or a commensurate portion of the 30-inch Interconnecting Pipeline) in the event of insolvency, bankruptcy or liquidation by EDFT.
PNG agrees to have its shareholders take on the risk of insolvency, bankruptcy or liquidation in relation to the incremental costs associated with the 30-inch Interconnecting Pipeline. However, this does not apply to EDFT’s 10-inch Interconnecting Pipeline or the EDFT portion of the 30-inch Interconnecting Pipeline. With reference to EDFT, PNG has taken the position that the risks of EDFT becoming insolvent are remote and should be balanced against the benefit of reduced rates for existing ratepayers who should bear such risks.
PNG has indicated that it would be prepared to have the shareholder bear the risk of EDFT’s insolvency, bankruptcy or liquidation. However, in return, PNG submits it’s allowed return on common equity needs to be set with a premium that compensates shareholders for stranded asset risk appropriately.
The Panel has considered PNG’s proposal but is not persuaded there is justification for PNG’s shareholders to take the risk in the event of insolvency, bankruptcy or liquidation of EDFT. The Panel notes that EDFT in spite of a recent downgrade retains a solid, investment grade credit rating. Given the current credit rating and the required credit support to be provided by EDFT in the event of a downgrade below investment grade as set out in the TSA, the Panel accepts that the risk of default is remote. In addition, as noted in Section 2.4, there are significant ratepayer benefits totalling $16.665 million per year in additional demand charges resulting from increased volume throughput on the PNG West system. This will have a significant positive impact on rates in favour of the existing PNG ratepayer. In consideration of these factors, the Panel finds that it is appropriate for ratepayers to bear the risk of failure due to insolvency, bankruptcy or liquidation as argued by PNG.
However, in reaching this determination, the Panel considers there to be value in investigating optional strategies to further mitigate the risk of EDFT failure. Such strategies could include financial vehicles, third party guarantees or other options PNG might undertake to mitigate this risk. Accordingly, the Panel directs PNG to investigate potential options and provide a cost benefit analysis of those options as part of the next revenue requirements filing.
3.2 Waiver of CPCN requirements for a Class 3 estimate
PNG states that the capital and operating cost estimates it expected to file in late July in support of the Application “are considered to have a class 4 level of accuracy as defined by the [Association for the Advancement of Cost Engineering (AACE)] International Recommended practices.”56F[57] These were filed on July 31, 2015 and included a Class 4 level of accuracy for the pipeline and Class 5 level of accuracy for identified owner and equipment costs. This does not meet the requirement for an AACE Class 3 Estimate as outlined in the Commission’s 2015 Certificate of Public Convenience and Necessity Application Guidelines (CPCN Guidelines). PNG states that in order to facilitate the expeditious review process it has requested for this Application, a Class 3 estimate cannot be obtained in a timely manner. However, PNG asserts that the tolls on the Interconnecting Pipeline have been designed to recover all capital and operating costs from the Shippers and there is no risk of stranding assets with only negligible rate impacts on customers. PNG submits that given these circumstances the Class 4 and Class 5 levels of accuracy are sufficient for the Commission to review and approve the Application and requests the requirement for a Class 3 Estimate be waived.57F[58]
Intervener submissions
BCOAPO submits that it does not support the waiver request unless there is a guarantee there are no costs to ratepayers resulting from the less reliable cost estimates.58F[59]
Reply submission
PNG stands by the position it has taken in the Application stating that the reliability of cost estimates will not impact existing ratepayers as the Interconnecting Pipeline tolls have been designed to recover from Shippers the full actual costs.59F[60]
Commission determination
The Panel finds that in these circumstances it is appropriate to waive the requirement for an AACE Class 3 estimate. In making this determination the Panel has relied on the assurances provided by PNG that the tolls on the Interconnecting Pipeline have been designed to recover all capital and operating costs. As more detailed cost estimates become available they need to be filed with the Commission in accordance with the reporting set out in Section 6.0.
3.3 Development, capital and operating costs
To ensure that PNG’s existing customers will not be adversely impacted by construction of the project, the issues to be addressed in Section 3.3 include determining the appropriateness of the mechanisms for recovery of development, capital and operating costs related to the Interconnecting Pipeline, in addition to protection of PNG’s existing ratepayers in the event of termination.
3.3.1 Recovery of development costs
Table 2 sets out the details of the estimated Interconnecting Pipeline development costs outlined by PNG:60F[61]
Table 2
PNG’s forecast project development costs are $2.5 million and include costs associated with engineering, design and bid packages, environmental studies and Stantec FEED studies up to Class 3, amongst other things. PNG states the forecast costs include $50,000 for regulatory costs.61F[62]
The TRA with EDFT includes the provision that EDFT will pay 100 percent of the estimated project development costs upfront, with a subsequent true up to actual project development costs. PNG notes that instead of upfront payment as originally contemplated, the parties have agreed that EDFT will pay for project development costs in “material tranches as they are incurred.”62F[63] PNG states that they will not proceed with construction of the Interconnecting Pipeline until the project development costs have been fully recovered.63F[64] The TRA includes another provision that any other Shippers on the Interconnecting Pipeline will pay a portion of the actual project development costs based on contracted capacity upon execution of a TSA.64F[65]
Section 3.4 of the EDFT TRA deals with recovery of development costs in the event that the project does not proceed. A shortfall between the actual development costs incurred and payments received by PNG will become payable (or refundable if payments exceed costs) with 10 days’ notice of the amount.65F[66]
In response to BCUC IR 1.14.1.1, PNG stated that should the project not proceed, its existing customers will not be at financial risk for the proposed facility and if this occurs, PNG will look to recover all project development costs incurred from EDFT in accordance with the Interconnecting TRA. However, “as a matter of principle, PNG does not agree that its shareholder should be at risk of recovering regulatory costs as the benefits of the regulatory process are generally intended to accrue to its ratepayers.”66F[67]
While PNG does not expect the costs will be materially different under either the 10-inch or the 30-inch Interconnecting Pipeline option, it notes that its shareholder has agreed to cover the incremental costs of the additional minor project development costs that have arisen from performing work for both a 10-inch and a 30-inch Interconnecting Pipeline to support the regulatory process and other contractual requirements.67F[68] In its Final Submission, PNG confirms that it will not be seeking recovery of any such additional costs from either EDFT or its existing ratepayers.
Intervener submission
With respect to development costs, BCOAPO submits “PNG has not guaranteed recovery of regulatory costs from EDFT if PNG does not proceed with the Interconnecting Pipeline. In our view the regulatory costs risk should be borne by PNG’s shareholder.”68F[69]
PNG Reply
PNG disagrees with BCOAPO’s characterization and submits that 100 percent of project development costs, including the regulatory costs, are recoverable from EDFT. PNG further submits that it has incurred these costs while attempting to realize very significant benefits for existing ratepayers and, as a result, PNG is opposed to the shareholder taking on this risk.69F[70]
Commission determination
The Panel approves the recovery of actual project development costs from EDFT in material tranches, as incurred, until the development costs have been fully recovered. The Panel directs PNG is to ensure payment for all development costs are received prior to the commencement of construction of the Interconnecting Pipeline. The Panel acknowledges the following:
• PNG’s estimate for development costs is reasonable and for cost categories included in the estimate, the agreement provides for a subsequent true up to actual project development costs in the event that actual costs differ from the estimate;
• The provision in the TRA with EDFT that any other Shippers on the Interconnecting Pipeline will pay a portion of the actual project development costs based on contracted capacity upon execution of a TSA;
• PNG’s confirmation that it will not be seeking recovery from either EDFT or its existing ratepayers of any incremental costs of the additional minor project development costs that have arisen from performing work for both a 10-inch and a 30-inch Interconnecting Pipeline to support the regulatory process and other contractual requirements; and,
• With the exception of regulatory costs, PNG’s existing customers will not be at financial risk for the proposed facility should the project not proceed.
With respect to regulatory costs, the Commission Panel agrees with PNG’s argument that the regulatory costs have been incurred in the public interest in an attempt to realize significant benefits for existing ratepayers. The Panel finds that in the unlikely event that regulatory costs are not recovered from EDFT the $50,000 in regulatory costs will be recoverable from ratepayers.
3.3.2 Recovery of capital costs
To preserve the commercial sensitively of the information, PNG has requested confidential treatment of the capital cost estimates and the associated revenue requirement impacts of the Interconnecting Pipeline.70F[71] PNG submits disclosure of this information on the public record may be considered harmful to the commercial interests of the shippers as they continue to advance their LNG export projects in a globally competitive environment. PNG states that the Interconnecting Pipeline will be used exclusively by shippers who have signed a TSA with PNG for service and as outlined in Section 2.2.2, PNG has designed the tolls to recover the capital cost of the facilities over the term of the TSAs, so that there is no stranded asset risk for PNG or its customers when the TSAs expire. The Toll Calculation is designed to also recover the incremental revenue requirements associated with the capital costs, including PNG’s weighted average cost of capital.
To ensure that PNG’s existing customers will not be adversely impacted by construction of the project, the issues to be addressed in Section 3.3.1 include determining if the capital costs of the Interconnecting Pipeline are recovered through tolls paid by shippers and the responsibility for cost overruns.
Base capital costs and responsibility for capital cost overruns
The Toll Calculation for the Interconnecting Pipeline as outlined by PNG in its Application is outlined in detail in Section 2.2.2 of this decision and is designed to recover the incremental costs of the Interconnecting Pipeline.71F[72] PNG submits that the Toll Calculation generally uses the actual costs of construction and therefore the shippers on the Interconnecting Pipeline “…bear the risk of increased costs related to delays, routing changes, weather, rock conditions, etc.”72F[73] PNG further submits that:
PNG understands that, as a project subject to the jurisdiction of the Commission, disputes in final costs would be determined by the Commission. To the extent capital costs of the Interconnecting Pipeline are prudently incurred, notwithstanding delays, changes, etc., costs will be borne by shippers. There will be no construction cost overrun risk that will fall to PNG’s existing ratepayers.73F[74]
The Toll Calculation is designed so that EDFT will never be required to pay a toll greater than the Base Toll, which is derived from the Base Capital Costs. Base Capital Costs are defined in Schedule D to the form of TSA with EDFT as follows:
Base Capital Cost means either (i) the actual capital cost of the Interconnecting Pipeline if the Interconnecting Pipeline is constructed with a capacity of 3,115 10³m³ per Day (the “Base Capacity”); or (ii) the estimated capital cost of an Interconnecting Pipeline sized for the Base Capacity if the Interconnecting Pipeline is constructed with a capacity exceeding the Base Capacity.
While the Base Capital Costs means the actual capital cost under the 10-inch option, PNG recognizes that the definition of Base Capital Costs under the 30-inch option does not include a point in time for its determination. However, PNG submits its intention is to determine this amount post-construction using the actual capital costs and the pre-construction estimate of the ratio between the 10-inch and 30-inch Interconnecting Pipeline capital costs. This is subject to agreement from EDFT and Triton.74F[75] PNG considers the potential for a revenue shortfall due to the timing of the determination of Base Capital Costs to be “highly unlikely as there are significant economies of scale.” However, PNG submits that it “…will not seek to recover any revenue shortfall arising due to this contractual provision from its existing ratepayers as it is completely within PNG’s control to ensure that it has sufficient contractual commitments to result in benefits from economies of scale for EDFT if PNG proceeds with an Interconnecting Pipeline with a capacity exceeding 3,115 10³m³ per day.”75F[76]
Intervener submission
With respect to the issue of responsibility for cost overruns and the termination provisions, BCOAPO submits it is satisfied that “overruns do not pose a risk to the ratepayers.”76F[77]
Commission determination
The Panel approves the Toll Calculation with respect to capital costs as proposed by PNG. The Panel accepts that tolls paid by shippers under the TSAs ensure that all appropriate capital costs and the associated revenue requirements are recovered over the term of the TSAs. Further, given that the Toll Calculation generally uses the actual costs of construction, the Panel agrees with BCOAPO that the shippers bear the risk of any increased costs related to delays, routing changes, weather, rock conditions and other cost overruns. With respect to the issue of the potential for a revenue shortfall due to the timing of the determination of Base Capital Costs under the 30-inch option, the Panel accepts PNG’s assertion that it will not seek to recover any revenue shortfall arising due to this contractual provision from its existing ratepayers.
3.3.3 Recovery of operating costs
The Toll Calculation designed by PNG is based on the incremental operating costs of the Interconnecting Pipeline and rates will be set to recover the increase in the cost of service resulting from operating the Interconnecting Pipeline.77F[78]
The issues to be addressed are whether the tolls paid by Shippers include all appropriate operating costs and whether an allocation of overheads should be included in the tolls.
3.3.3.1 Do the tolls paid by Shippers encompass all appropriate operating costs?
Table 3 sets out the details of the Interconnecting Pipeline OMG&A cost provision:78F[79]
Table 3 Interconnecting Pipeline OMG&A Cost Provision
The fixed operating, maintenance, general and administrative (OMG&A) provision of $60,000 is comprised of an annual transmission operating and maintenance cost provision of $40,000, plus an annual provision for the cost of future in-line inspections of $20,000. 79F[80] The $40,000 provision for annual transmission operating and maintenance costs was developed based on the 2013 operating and maintenance costs associated with its transmission pipelines inflated by the Consumer Price Index. PNG divided these costs by the total installed kilometers of transmission pipelines and multiplied the result by the length, in kilometers, of the Interconnecting Pipeline.80F[81]
Company overhead is not included in the fixed OMG&A provision.81F[82]
With respect to the cost provision for in-line inspections, PNG submits that the expected vendor cost per inspection on a 30-inch Interconnecting Pipeline is $95,000, with the expected vendor cost per inspection on a 10-inch Interconnecting Pipeline being “somewhat less.” PNG submits that the existing ratepayers will benefit in years when no in-line inspection occurs “but will experience an offsetting cost in the years the inspections occur, the first being some seven (7) years out.”82F[83]
PNG submits that the only expected OMG&A cost difference between the 10-inch and the 30-inch Interconnecting Pipeline is the cost of in-line inspections.83F[84]
PNG submits that the OMG&A provision is the only component of the toll for the Interconnecting Pipeline that can vary from the costs included in PNG’s approved cost of service in any given year.84F[85] PNG observes that the OMG&A charge is not material and variations will result in “negligible impacts” in respect of PNG’s other ratepayers.85F[86] PNG submits that the provision for OMG&A in the toll is administratively efficient and provides the Shippers with the certainty they need to make a positive FID for their projects.86F[87]
Intervener submission
In its final Submission, BCOAPO noted several points related to the incremental tolling approach and overhead costs (outlined in Section 3.3.3.2). BCOAPO did not make any submission with respect to the amount of the OMG&A provision or escalation of costs using the Consumer Price Index.
Commission determination
Based on the methodology used by PNG to determine the provision, the administrative efficiency and certainty it provides and the small impact of the costs on PNG’s existing ratepayers, the Panel finds the $60,000 OMG&A provision based on 2013 dollars and inflated by the Consumer Price Index used in the toll calculations to be reasonable for the 10-inch Interconnecting Pipeline option.
The Panel is concerned that there may be OMG&A costs differences between the 10-inch and the 30-inch options other than the in-line inspection costs. Specifically and as discussed in Section 3.4 of this decision, the Panel is concerned with the lack of certainty under the 30-inch option with respect to the compressor equipment and related operating costs. While the Panel accepts PNG’s submission that the OMG&A cost provision provides shippers on the Interconnecting Pipeline with the certainty they require to make a successful FID for their projects,87F[88] the Panel also notes PNG’s submission that variations in the OMG&A charge will result in “negligible impacts” in respect of other ratepayers.88F[89] Given the uncertainty surrounding the compressor equipment costs and the lack of direct incremental benefits to PNG’s existing ratepayers under the 30-inch option, we do not consider it appropriate for PNG’s existing ratepayers to be at risk for the actual OMG&A costs under the 30-inch option over and above the $60,000 allocated to shippers under the form of TSAs. Therefore, in the event that the TSAs negotiated between PNG and the shippers on a 30-inch Interconnecting Pipeline result in a revenue shortfall related to OMG&A, the Panel determines any revenue shortfall must not be recovered from existing ratepayers. Should PNG proceed with construction of a 30-inch Interconnecting Pipeline, the Panel directs PNG to provide an updated allocation of OMG&A based on actual costs, using the same methodology used in the Application, as part of its revenue requirements filings with the Commission.
3.3.3.2 Is the incremental tolling approach appropriate or should Shippers be allocated overheads?
In its final submission, PNG submits that the Toll Calculation will result in “negligible impacts” in respect of PNG’s other customers.89F[90]
Intervener submission
BCOAPO submits they disagree in principle with the incremental tolling approach. BCOAPO submits that setting a toll on an incremental basis is the minimum that a toll can be set without subsidizing a new customer and that such a toll does not benefit existing customers and does not result in any contribution towards the existing network, IT system, administration, other overhead costs, etc.90F[91]
BCOAPO argues that existing customers should get a small, positive financial benefit and submits this could be achieved by allocating a portion of overhead or existing costs to the Interconnecting Pipeline costs. BCOAPO notes that:
• While PNG and the Shippers propose that their service be tolled on an incremental basis with regard to existing PNG customers, the Shippers do not propose incremental tolling for any new shippers joining them on the pipeline extension.
• The primary Shipper recovers some of the costs paid initially from new shipper joining them on the pipeline and so free-riding does not confer a financial benefit.91F[92]
BCOAPO request that the Commission order Shippers on the Interconnecting Pipeline to pay a portion of PNG’s overhead costs and suggest that “[a]t a minimum, there should be a review within 3 years of the approval of this Application (if it is approved) to determine what the Shippers’ contribution towards system costs should be.” 92F[93]
PNG reply
With respect to the tolls charged to EDFT on the Interconnecting Pipeline, PNG submits it would be unreasonable to charge EDFT for a portion of overhead costs given that they will pay a toll for the same volume of gas to use PNG’s existing system under the GTSA. By paying the toll on the existing system, EDFT will contribute to the existing network, IT system, administration and other overhead costs.93F[94]
With respect to the tolls charged to other shippers on the Interconnecting Pipeline not using PNG’s upstream assets, PNG submits not including a provision for company overhead in the Toll Calculation “was an oversight.”94F[95] PNG proposes to amend the form of TSA for these customers to include an additional administrative and general cost provision and suggests the following process:
…PNG proposes that it file amendments to the Service Agreements to incorporate such an A&G provision, for the Commission’s review via a written process, no later than three months prior to the date that PNG expects to commence construction of the 30-inch pipeline option. Only if PNG is able to successfully incorporate an approved provision, reflected in service agreement amendments with EDFT and Triton, will it proceed with the 30-inch pipeline alternative.95F[96]
PNG states that if construction of the 30-inch pipeline proceeds they would be “amendable to reviewing the circumstances surrounding the risks and benefits” of the 30-inch pipeline to PNG’s existing ratepayers within three years.96F[97]
Commission determination
The Panel agrees with BCOAPO that the Shippers should make a contribution to PNG’s overhead costs. Conversely, the Panel recognizes the rate benefits to be received by existing customers from service to be provided under the EDFT GTSA and agrees with PNG that EDFT’s payment of the toll on the existing system will provide an appropriate contribution to existing network, IT system, administration and other overhead costs. The Panel approves the EDFT Toll Calculation with respect to operating costs as proposed by PNG.
With respect to the tolls to be charged to other shippers only taking service on the Interconnecting Pipeline, the Panel accepts PNG’s submission that not including an overhead change in the tolls for these customers was an oversight. The Panel accepts PNG’s proposed process for amendment and approval of the TSAs and for review of the risks and benefits of the 30-inch pipeline to PNG’s existing customers. PNG is directed to:
1. Amend the form of TSA for those Shippers only taking service on the Interconnecting Pipeline to include an additional administrative and general (overhead) cost provision.
2. File this amendment to the form of TSAs for the Commission’s review and approval no later than three months prior to the date PNG expects to commence construction of the 30-inch pipeline option. PNG is not to proceed with the 30-inch pipeline alternative until it has successfully incorporated the approved overhead provision into the form of TSAs.
3.3.4 Termination provisions
The following section addresses the issue of whether PNG’s existing ratepayers are adequately protected in the event of termination of either the TRA or TSA.
EDF Trading Limited Agreement
The TRA with EDFT includes several provisions related to termination of the contract. Specifically, Section 4.3 of the TRA97F[98] states that the TRA will terminate at the earliest of the following:
(a) commencement date of the TSA;
(b) termination in accordance with Article 6 of the TRA; or
(c) the outside completion date of January 1, 2018.
The termination provisions outlined in Article 6 of the TRA state that termination may take place in the event of the following:
(a) due to unsatisfied condition precedent;
(b) upon default by EDFT, PNG may terminate;
(c) due to estimated tolls, EDFT may terminate; or
(d) upon termination of the GTSA between PNG and EDFT.
Section 12.11 of the TRA with EDFT states that in the event of conflict between the EDFT TRA and the TSA, the terms and conditions of the TRA take precedence until the TRA is terminated.
The form of TSA with EDFT includes an Early Termination Charge equal to the net present value of all future demand charges multiplied by the contract capacity from the date of termination until the end of the primary term of the TSA.98F[99] PNG submits that in the event of termination by EDFT before the end of the primary term of their TSA, the Early Termination Charge is payable regardless of whether construction of the Interconnecting Pipeline is completed.99F[100]
Triton Agreement
The TRA with Triton includes several provisions related to termination of the contract. Specifically, Section 4.3 of the TRA100F[101] states that the TRA will terminate at the earliest of the following:
(a) commencement date of the TSA;
(b) termination in accordance with Article 6 of the TRA; or
(c) the outside completion date of January 1, 2018, unless an extension is mutually agreed upon.
The termination provisions outlined in Article 6 of the TRA state that termination may take place in the event of the following:
(a) due to unsatisfied condition precedent;
(b) upon default by Triton, PNG may terminate;
(c) due to estimated tolls, Triton may terminate;
(d) upon termination of any upstream transportation agreement between Triton and PNG;
(e) at any time prior to commencement of construction but no later than the 10th day following Triton’s receipt from PNG of notice to commence construction in accordance with Section 5.2 of the TRA. If Triton does not terminate prior to the commencement of construction, they are required to pay the Reservation Fee;101F[102]
(f) following the commencement of construction. If a TSA is not executed, EDFT is required to pay the Post Construction Termination Fee; or
(g) upon termination of EDFT’s TRA.
Triton’s obligations under the TRA to pay the Reservation Fee and Post Construction Termination Fee may take effect prior to the execution of a TSA. With respect to this, PNG submits that:
Triton remains responsible for paying the Reservation Fee unless it terminates the TRA and pays the Post Construction Termination Fee. For this reason, Triton is expected to make the financial commitment necessary for PNG to construct the 30-inch pipeline option only if it intends on delivering an executed TSA within a reasonable period of time. PNG does not believe there is any material risk to EDFT or to its existing ratepayers as a result of providing flexibility to Triton, allowing it to execute a Service Agreement after it has sufficiently advanced its proposed LNG project.102F[103]
PNG submits that it is their intention to secure Triton’s obligation to pay the Reservation Fee and Post Construction Termination Fee “…in the same manner that payments under the Transportation Service Agreement for service on the Interconnecting Pipeline are secured prior to commencement of construction of the 30-inch pipeline option.”103F[104]
Intervener submission
BCOAPO submits that they “…acknowledge that the post construction termination fee covers the full costs of the project and protects ratepayers.”104F[105]
Commission determination
The Panel notes the provision in Article 6.5 of the TRA with Triton related to termination due to estimated tolls. It is unclear whether the Post Construction Termination Fee would be payable by Triton in the event of termination due to estimated tolls that are provided after the commencement of construction. Accordingly, the Panel directs PNG to provide the estimated tolls to Triton 30 days prior to the commencement of construction.
The Panel agrees with PNG and BCOAPO that the EDFT Early Termination Fee covers the full costs of the project and protects PNG and existing ratepayers. The Panel has reviewed the termination provisions included in the TRAs, including the form of TSAs, with EDFT and Triton and is satisfied that the termination provisions are appropriate and sufficient. The Panel accepts PNG’s representation that it will secure Triton’s obligation to pay the Reservation Fee and Post Termination Construction Fee prior to execution of the TSA.
Approval of the TRAs is included in Section 5.0.
3.4 Consideration of Clean Energy Act and alignment with Provincial Government energy objectives
PNG states that the nature of its proposed Interconnecting Pipeline project is such that it does not provide direct support advancement of the provincial governments energy objectives that “primarily pertain to the matters of generation, cost and conservation of energy.” However, PNG asserts that that the project does support the provincial government’s LNG Strategy (Natural Gas Strategy) as it supports the government’s desire to develop the LNG export market and have export facilities up and running within the province. PNG also submit that the proposed project will contribute to the government’s goals of creating investment, jobs and new economic opportunities throughout the province.105F[106]
With respect to energy use, an issue related to the choice of compressor for the Interconnecting Pipeline has arisen. BCUC IR 1.7.2 noting that the cost estimate for the compressor equipment was the same for both the 10-inch and the 30-inch pipeline requested confirmation that the same equipment would be used for both and asked PNG to report on the rated power output required for each pipeline option. In response, PNG noted that the compressor requirements would differ based on the size of pipe and a Class 4 estimate of this infrastructure was as yet unavailable. PNG further indicated that the compression component was not deemed to a significant part of overall project risk or cost and a Class 5 estimate was inserted. In addition, PNG submits that the selection of compression and drives for the two options has yet to be completed but will be included in the Class 3 estimate it expects to release in September 2015.106F[107] PNG also submits that it has not determined whether the compressor drives will be electric (as opposed to natural gas) and has done no work on determining the greenhouse gas (GHG) emissions or conducted an evaluation of cost differences in the event a non-electric compressor drive is chosen.107F[108]
Commission determination
Section 46 of the UCA states that in deciding whether to issue a certificate (CPCN) applied for by a public utility, the commission must consider British Columbia’s energy objectives. Part 1, section 2 of the Clean Energy Act (CEA) describes British Columbia’s energy objectives with the relevant objectives including:
(d) to use and foster the development in British Columbia of innovative technologies that support energy conservation and efficiency and the use of clean or renewable resources;
(g) to reduce BC greenhouse gas emissions;
(h) to encourage the switching from one kind of energy source or use to another that decreases greenhouse gas emissions in British Columbia; and
(k) to encourage economic development and the creation and retention of jobs.
The Panel finds that the PNG Interconnecting Pipeline project as described in the Application satisfies 2(k) of the Provincial Government Energy Objectives and approval of the project will have a positive impact on the economy through the creation of jobs, investment and new economic opportunities throughout British Columbia.108F[109]
The Panel does not agree with PNG’s assertion that British Columbia’s energy objectives “primarily pertain to the matters of generation, cost and conservation of energy. Of concern to the Panel is the lack of certainty with respect to the choice of compressor equipment and the potential impact on the environment. Based on the information in Section 2.1.4, the 10-inch compressor is estimated to be one tenth the size of the 30-inch compressor with the increase of GHG emissions potentially having a similar order of magnitude. Our primary concern is with the compressor equipment required to make the 30-inch pipeline fully operational which could have a significant impact on the level of GHG emissions. Therefore, the Panel will accept PNG’s estimate and choice of compressor equipment in the event it moves forward with the 10-inch option but does not accept PNG’s choice of compressor equipment or cost estimate in the event it chooses to move forward with a 30-inch Interconnecting Pipeline unless it is confirmed to have an electric drive. If PNG is to move forward with a 30-inch Interconnecting Pipeline with a non-electric compressor drive, it is directed to file a CPCN with the Commission for the compressor equipment with justification and consideration of the British Columbia energy objectives in Part 1, section 2 of the Clean Energy Act.
4.0 Other issues
4.1 Public and stakeholder consultation and support
4.1.1 Community consultation
The District of Kitimat is identified as the sole municipality affected by the proposed Interconnecting Pipeline. PNG states that the District is generally supportive of LNG initiatives within the region. This is primarily due to economic benefits the community will derive from the proposed projects.
PNG states that the District of Kitimat has been made aware of the necessity of the PNG Interconnecting Pipeline in supplying natural gas to the DC LNG project through the outreach activities of AltaGas as a proponent of the project. PNG notes that it has not directly undertaken its own outreach activities to date but adds that there is an engagement plan under development that will be filed concurrent with this Application. PNG also notes that these engagement plans are a key element in satisfying the consultation requirements allowing for permits as part of the OGC review.109F[110]
The District of Kitimat, by letter dated September 1, 2015, extends its support for the projects pointing out that the establishment of new industries has been a high priority since the 2010 closure of Eurocan Pulp and Paper. The District states the PNG pipeline proposal will be a welcome addition to its industrial sector providing increased economic stability. It will also positively impact PNG customer rates.110F[111]
Commission determination
The Panel finds the public consultation conducted by PNG with respect to the Interconnecting Pipeline project to be adequate and meets the requirements of the CPCN Guidelines.
PNG, through its parent company AltaGas, has kept the District of Kitimat informed of the importance of the Interconnecting Pipeline and has undertaken steps to develop its own engagement plan in support of OGC requirements. In addition, the Panel notes that the District of Kitimat has sent a letter of support for the project.
4.1.2 First Nations engagement
PNG identifies the Haisla Nation as the only First Nation that may be affected by the proposed Interconnecting Pipeline based on information from the government of British Columbia’s Consultative Area Database.111F[112]
PNG points out that the Haisla Nation has agreed to lease land to the DC LNG project and has leased land for another project to be developed by Chevron Canada Ltd.112F[113] The Haisla Nation is also exploring the potential development of Cedar LNG, its own LNG project. The management of that project has provided a letter of support in principle for the project as it intends to seek capacity on the pipeline.113F[114] Cedar LNG has expressed interest in securing transportation service from PNG and along with other stakeholders is working collaboratively with PNG on the development of a common pipeline corridor study.114F[115]
The Haisla Nation Council, by letter of July 17, 2015, provides support for the Interconnecting Pipeline project as it understands the project will have capacity for the DC LNG project and the Cedar LNG project.
The Haisla Nation states that it recognizes that the provision of utility services (natural gas transportation) along the west side of Douglas Channel requires careful planning and, where possible, shared facilities. Because of this, the Haisla support in principle what it considers to be the current objective “of having the AltaGas Project and the Cedar Project each use capacity on PNG’s pipeline.” The Haisla Nation, through its commercial agreements with AltaGas have agreed to support PNG’s Interconnecting Pipeline and note that it is important to the development of the AltaGas project and also benefits existing PNG customers by reducing natural gas rates.115F[116]
PNG reports that AltaGas, as a proponent of the DC LNG project, has developed a formal stakeholder engagement plan for the Haisla First Nation and that PNG will be undertaking consultation, as that term is defined at law for First Nations, for the project.116F[117]
This project will be subject to review by the OCG. The OCG is legally responsible for consultation and, as PNG states, it is expected that the OCG will assess the adequacy of consultation as part of its permitting process.117F[118]
Commission determination
The Panel finds that First Nations engagement efforts to date are acceptable. PNG has used a comprehensive resource to identify the Haisla as the one First Nation who assert rights in the project areas, has ensured the Haisla First Nation has been notified of the projects through AltaGas and developed plans for further engagement in conjunction with the OGC permit application process. In addition, the Panel notes that PNG has received a letter of support in principle for the project directly from the Haisla Nation Council.
Of importance is that the OGC is the Crown Agency responsible for First Nations consultation which requires consultation to be ongoing. PNG is responsible for conducting preliminary discussions with identified First Nations and providing documentation for the OGC process. The adequacy of First Nation consultation is a matter to be addressed by OGC.
4.1.3 Other stakeholder engagement
In addition to First Nations and Community stakeholders, PNG has other stakeholders with assets that may be affected by the proposed Interconnecting Pipeline routing. These include LNG Canada, BC Hydro and Power Authority (BC Hydro), Rio Tinto Alcan (RTA), and the Crown (specifically the Ministry of Transport (MOT)). As noted, both LNG Canada and BC Hydro have registered as interveners and actively participated in these proceedings. PNG notes that all parties are aware of the Interconnecting Pipeline although there has not as yet been active engagement.118F[119]
It is important to note that PNG has not requested approval for a specific Interconnecting Pipeline routing from the Commission. Specific routing approval is subject to OGC review which will occur at a later date. Stakeholder consultation is a part of the OGC application assessment.119F[120]
PNG submits that it is working on its consultation plans which will include the scheduling of one-on-one consultation and negotiations with each party following completion in October 2015 of the Class 3 engineering and design studies. This will provide more certainty as to the project parameters. 120F[121]
As noted in Section 2.1.3, in April 2015, PNG initiated a Joint Corridor Study to determine a common corridor that would meet the needs of other gas pipeline proponents in the area. The study considered the needs of other stakeholders, principally RTA that has been identified as being impacted the most. When completed, PNG’s Joint Corridor Study will be shared with MOT for consideration and inclusion in its own study.121F[122]
PNG reports that west Douglas Channel stakeholders have been participants in the corridor study or provided some guidance as to what would be acceptable corridor areas. In addition, PNG is conducting negotiations with stakeholders as it expects to have to widen its existing right-of-way (ROW) at the north end of Douglas Channel to accommodate the 30-inch pipeline scenario. Stakeholder discussion topics include the acquisition of ROW, widening of the existing ROW and logistics of PNG’s execution plan.122F[123]
Intervener submissions
LNG Canada does not oppose the construction of the Interconnecting Pipeline but has concern with potential adverse impacts if the project is not properly planned, constructed and operated. While acknowledging the circumstances related to the need for an expedited regulatory process had an impact on PNG’s ability to engage stakeholders, LNG Canada submits that it had no consultations with PNG prior to the filing of the CPCN application and considers this to be contrary to the 2015 CPCN Application Guidelines.123F[124]
LNG Canada states that a CPCN issued by the Commission for the Interconnecting Pipeline should include conditions that meet the following objectives:
(a) PNG should be required to consult, or continue to consult, with all potentially affected stakeholders, including LNG Canada, regarding the Interconnecting Pipeline, including with respect to the proposed route, land requirements, construction schedule, construction activities and operating design for the Interconnecting Pipeline; and
(b) PNG should be required to file with the Commission for approval, at least 90 days prior to the commencement of any construction activities, a report on PNG’s consultation activities with potentially affected stakeholders regarding the measures taken by PNG to reduce, eliminate or offset potential adverse project effects on existing and proposed future developments in the area as outlined in 8(ii) above, including:
(i) a summary of the concerns raised by potentially affected stakeholders;
(ii) a summary of PNG’s response to all concerns raised; and
(iii) a summary of any outstanding concerns about the project’s potential effects raised by stakeholders, any steps that will be taken by PNG to address these outstanding concerns, or an explanation why no further steps are required. 124F[125]
BC Hydro states that its IRs raised safety concerns with regard to the proximity of PNG infrastructure to its own infrastructure. BC Hydro confirms it is comfortable with PNG’s response to its IRs and at this stage is comfortable “with PNG’s engagement with BC Hydro subsequent to the IR process and with PNG’s plan and commitment for continued engagement with BC Hydro…” 125F[126]
Commission determination
The Panel finds that PNG efforts to engage other stakeholders to date are acceptable. PNG has taken steps to ensure that all potentially affected parties are aware of the Interconnecting Pipeline. Actual consultation on the route for the proposed pipeline has not yet occurred but plans are being formulated and active engagement with affected parties will begin once the results of the MOT Joint Corridor study and the Class 3 engineering and design studies are available. As noted, specific routing will be subject to OGC review which will occur at a later date. Stakeholder consultation will be assessed at that time as part of OGC’s review of the application.
4.2 Terms and conditions of Transportation Agreements
PNG requests approval pursuant to section 58 of the UCA for the interconnecting TRAs between PNG and EDFT dated January 23, 2015, and between PNG and Triton LNG Limited Partnership dated July 22, 2015, including the form of TSA attached to the TRAs. PNG states this approval is necessary to provide certainty of the tolls and terms of service that will apply prior to the parties to the TRAs making large investments in the construction of the associated LNG facilities.126F[127] Under section 58 of the UCA, the Commission may determine the just, reasonable and sufficient rates and order a public utility to amend its schedules. Executed TSAs of the form approved will ultimately need to be filed with the Commission for acceptance as an approved tariff pursuant to section 61 of the UCA.
During the course of the hearing several issues related to the TSAs terms and conditions were explored in detail, and are described in Section 4.2.1 below.
4.2.1 Modernization and harmonization of terms
In response to BCUC IR 2.14.5, PNG provided a table outlining differences in the terms and conditions of its proposed form of TSA agreement and those of Rio-Tinto Alcan which PNG believes to be most representative of the terms and conditions applying to its existing TSAs.127F[128] This 33 page table highlights the number of changes in the proposed form of agreement. Many of these changes are described as reflecting modern business practices (e.g. electronic nomination vs. fax) and current industry norms and practices. In addition, there are other specific terms that differ from one TSA and shipper to another which may be considered important and potentially discriminatory. Section 59(2)(b) of the UCA states that “a public utility must not extend to any person a form of agreement,… unless the agreement, … is regularly and uniformly extended to all persons under substantially similar circumstances and conditions for service of the same description.” Under the UCA, the Commission determines whether there is undue discrimination, preference, prejudice or disadvantage in respect of a rate or service and what are substantially similar circumstances and conditions.
Specific terms that could represent material/monetary differences are discussed below.
Penalty Charges in the event shipper takes excess gas during curtailment
In comparing the existing transportation agreements with the proposed transportation agreement GT&Cs, PNG states, “Both sets of GT&Cs use penalty charges as an incentive for shippers to stick to authorized quantities during a curtailment. Penalties in the existing GT&Cs are more onerous.”128F[129]
The calculation method for toll charges on the Interconnecting Pipeline is contained in Schedule D to the form of TSA with EDFT and Triton.129F[130] The Toll Calculation as outlined by PNG in its Application covers three distinct time periods:
1. Period A: From completion of construction until the shipper’s service request date, where no toll is applied.
2. Period B: From the EDFT service request date until the service request date of a second shipper.
3. Period C: From the service request date of a second shipper until the end of the individual shippers’ respective TSA.
During Period B, when EDFT is the only shipper on either the 10-inch or the 30-inch Interconnecting Pipeline, there is no Interruptible charge.
The form of TSA with EDFT and Triton also includes GT&Cs. Section 6.4 of the GT&Cs relates to applicable charges in the event that the shipper takes gas in excess of the volume specified by PNG during curtailment. These charges are based on multiples of the interruptible charge, meaning that during Period B when EDFT is the only shipper on the Interconnecting Pipeline, the resulting charges under Section 6.4 of the GT&C are nil because of the zero dollar interruptible charge. Likewise PNG confirmed that under the EDFT Transportation and Service Agreement approved by the Commission in Order G-5-15 for service to EDFT (on the existing PNG pipeline) there are no charges that apply in the event EDFT takes gas in excess of the volume authorized during a curtailment.130F[131] For existing shippers with the terms and conditions as set out in Rio-Tinto Alcan TSA the penalty is based on a multiple of the firm T-service rate (Spectra Energy rate).131F[132]
For Period C (multiple shippers on Interconnecting pipeline) and for other existing shippers there is a penalty in the event the shipper takes excess gas during a curtailment based on a multiple of either the interruptible rate (Interconnecting Pipeline) or firm T-service rate (existing shipper).132F[133]
Commission determination
The fact that EDFT has no penalty charge for taking excess gas during a curtailment during Period B on the Interconnecting pipeline and none on the existing PNG pipeline is inconsistent with PNG’s statement that it uses penalty charges as an incentive for shippers to stick to authorized quantities during a curtailment. It is also inconsistent with penalty charges other shippers would be charged in similar circumstances. The Commission approves the form of the Transportation Service Agreements with the exception of EDFT not being required to pay penalty charges for taking excess gas during curtailment during Period B. As noted in Section 3.3.3.2, PNG plans to file amendments to the Service Agreements. The Panel directs PNG to correct the inconsistency in penalty charges for taking excess gas during curtailment in its amended Service Agreements prior to filing these amendments.
Harmonization and modernization of terms
PNG states “In the long run, PNG would like to harmonize the terms and conditions for transmission service on its existing facilities with the more modern terms and conditions found in the proposed Service Agreements…it will likely try to harmonize its transmission service terms and conditions to coincide with the expansion project going into service.” PNG also submits that it will take a significant amount of effort to consult and negotiate with its customers in this regard.133F[134]
Commission determination
PNG’s proposal to work toward the goal of harmonizing its transmission service terms and conditions prior to any significant expansion of its transportation service is reasonable given the need to modernize terminology and the variation in terms and conditions among different shippers. However, the Panel acknowledges that the work required to complete the harmonization process would be significant and require time and resources. Therefore, the Panel directs PNG to file within 6 months of this order a proposal outlining how PNG intends to approach the issues related to harmonization of terms and conditions among shippers and a proposal for the timeline.
4.2.2 Practical issues of gas balancing with multiple shippers and multiple pipe segments
In requesting approval of either a 10-inch (single shipper) and a 30-inch (single or multiple shippers) interconnecting pipeline which could see gas provided from PNG’s existing pipeline and other new pipelines, the issue of measurement and gas balancing on the interconnecting pipeline and other connected pipelines was explored. Under the EDFT GTSA on the existing pipeline, delivery point is defined as the point of interconnection between PNG’s existing 10-inch Gas pipeline at its terminus in Kitimat, BC with the planned Interconnection Pipeline. Article 12 of the EDFT GTSA provides that “all Gas delivered by PNG to Shipper at the Delivery Point shall be measured.”
Under the proposed TSA, Schedule A, the receipt point is defined as the point of interconnection with the Interconnecting Pipeline and delivery point is defined as “Shipper’s facilities at District Lot 99, Kitimat Township.” Article 12 of the proposed TSA states that “All Gas delivered by Shipper to Transporter at the Receipt Point(s) and all such Gas delivered by Transporter at the Delivery Point shall be measured…”
Commission determination
Since the Gas Balancing provisions (Article 6 of the General Terms and Conditions of the proposed TSA) include measures such as curtailment and penalties related to gas balancing it would seem reasonable that there be measurement capabilities for each shipper at both its receipt and delivery points. This would be especially important where there are multiple shippers and multiple pipeline segments with multiple receipt points and delivery points. For this Application, the aspect of where metering stations are located and match receipt and delivery points only becomes an issue in granting approval for the 30-inch option. Although measurement is provided for in the terms and conditions, it is more of a practical question of what and where physical metering stations will be provided for in the 30-inch option so that gas balancing issues (e.g. curtailment or penalties or allocation of unaccounted for gas) can be assigned appropriately for multiple shippers.
For clarity and to ensure consistency and fairness with the terms and conditions related to gas balancing where there will be more than one shipper on the Interconnecting Pipeline (30-inch option), the Panel directs PNG to address the method and location of gas metering stations and gas balancing issues with multiple shippers in its detailed design work for either the 10-inch or 30-inch options.
4.3 Potential conflict of interest
As noted in Section 1.3, PNG is a wholly-owned subsidiary of AltaGas Utility Holdings (Pacific) Inc., which in turn is wholly-owned by AltaGas Ltd. At issue is that AltaGas is also a proponent of both the DC LNG project and Triton LNG project. PNG submits that it continues to operate in compliance with its Code of Conduct as approved by the Commission. PNG states that AltaGas is not a capacity holder on the pipeline and thus, not a direct customer. Additionally PNG states that and its existing customers are broadly not at financial risk regarding the Interconnecting Pipeline and consequently, PNG considers there to be no risk of related party conflict of interest. 134F[135]
Intervener submission
BCOAPO submits that AltaGas is the owner of PNG and will be part of the customer for the Interconnecting Pipeline. BCOAPO identifies this as a potential conflict of interest, but accepts that PNG has stated they will abide by the approved Code of Conduct.135F[136]
Commission determination
The Panel accepts the assurances of PNG that it will abide by the approved Code of Conduct. However, while PNG believes that there is no risk of related party conflict of interest, strict adherence to provisions outlined in the Code of Conduct is a requirement.
5.0 CPCN determination and approval of the agreements
5.1 CPCN Commission determination
Subject to and in accordance with the findings, approvals and determinations in this decision, the Panel finds the Interconnecting Pipeline project as proposed by PNG is in the public interest and grants a CPCN for the construction and operation of either a 10-inch or 30-inch Interconnecting Pipeline and related metering facilities. In granting this CPCN PNG is also approved to make the final construction decision between the ten inch and 30 inch pipeline alternatives based on the FID made by DC LNG and the financial commitments of other project proponents.
The Panel has reviewed the evidence and examined in detail the issues which have arisen and consistent with the findings in this decision has determined that except where noted, the CPCN Guidelines have been met and approval is warranted.
5.2 Approval of the agreements
In its Application, PNG seeks approval, pursuant to section 58 of the UCA, of the TRA between PNG and EDFT dated January 23, 2015, including the form of TSA attached thereto and of the TRA between PNG and Triton dated July 22, 2015 including the form of TSA attached thereto. Both forms of TSAs include General Terms and Conditions and the Toll Calculations.
The Panel approves the TRA between PNG and EDFT dated January 23, 2015, as filed. The Panel also approves the form of TSA attached thereto with the exception of changes that are ordered in Section 4.2.1 and 3.3.3.2.
Article 6.1(b) of the TRA between PNG and EDFT includes a Condition Precedent for PNG’s receipt of an executed TSA, Service Reservation Request and all applicable Credit Support from EDFT. Article 5.2 states that PNG will proceed with construction of the Interconnecting Pipeline upon satisfaction or waiver of the Conditions Precedent outlined in the TRA.136F[137]
PNG submits that it
…will not waive any of the conditions precedent in 6.1(b) in order to commence construction as the full contractual package with the shipper, including credit support, is required in order to ensure PNG is not undertaking undue risks…PNG will not commence construction until the Board of Directors of the Shipper has approved and the Service Agreement has been duly executed and is fully enforceable, which will require that the Shipper can represent it has received all of its Shipper Authorizations.137F[138]
The Panel is in agreement with PNG that the condition precedent in Article 6.1(b) of the TRA with EDFT should not be waived prior to the commencement of construction in order to ensure PNG is not taking undue risk. Accordingly, the Commission Panel directs PNG to ensure it has an executed TSA accepted by the Commission, Service Reservation Request and all applicable credit support with EDFT prior to commencement of construction of the Interconnecting Pipeline.
The Panel approves the TRA between PNG and Triton dated July 22, 2015. The Panel also approves the form of TSA attached thereto with the exception of the changes that are ordered in Section 4.2.1 and 3.3.3.2.
The Panel notes that the TRAs with both EDFT and Triton define “Service Agreement” as “…an agreement between PNG and a Shipper, for transportation of Gas on the Interconnecting Pipeline, substantially in the form of Schedule ‘C’ to this Agreement.”138F[139] If differences arise between the form and executed TSAs that are significant these differences must be filed with the Commission for approval. Notwithstanding, all executed TSAs must be filed with the Commission.
6.0 Reporting requirements
6.1 Summary of reporting requirement submissions
PNG’s draft order on reporting requirements submitted in the Application proposes the wording, “PNG shall file with the Commission a compliance report stating its decision to build either a ten inch diameter or thirty inch diameter transportation pipeline and related compression and metering facilities prior to the commencement of construction of the pipeline.”139F[140]
The Transportation Reservation Agreement between PNG and EDFT requires PNG to submit quarterly status reports no later than 15 days after the end of each calendar quarter. The reports to be provided by PNG are to include any changes in the Target Completion date, the Actual Project Development Costs spent to date, the remaining Estimated Project Development Cost budget and any changes from the initial budget.140F[141]
In its response to information requests on reporting requirements, PNG states the following:
- PNG will file all executed Service Agreements for transportation service on the Interconnecting Pipeline for acceptance by the Commission as a filed tariff.141F[142]
- The timing of the pipeline diameter decision is dependent on the Shippers, however PNG expects a decision to be made on or before the end of 2015. PNG has not determined the exact content of the compliance filing however the filing will be made publicly available on a non-confidential basis.142F[143]
- PNG does not view the Ministry of Transportation corridor study relevant to the decision sought and does not intend to file the study with the BCUC as the study is focused on alignments and rock volumes specific to the West Douglas Channel.143F[144]
Commission determination
The Panel notes the extenuating circumstances surrounding this application which precluded the submission of a Class 3 cost estimate and other related information with the initial application. The Panel finds it reasonable for PNG to file material information that would have otherwise been submitted with the Application when it is available. The Panel concurs with PNG’s view on the relevance of the MOT corridor study to this decision and does not require the study to be filed.
The Panel notes that the Shippers will be providing project oversight and any cost over runs will be borne by the shippers. In the Panel’s judgement, this reduces the need for detailed Commission oversight of the project costs; however, project oversight is still warranted as schedule delays would potentially have negative consequences for ratepayers.
Therefore, the Panel directs PNG to file the following information in the manner described below.
1. Pipeline Diameter Compliance Report
The Pipeline Diameter Compliance Report must be filed along with a version for public release within 30 days of a determination being made on the 10-inch or 30-inch options and no later than January 29, 2016. The report must include:
a. a description of the project including a detailed route alignment with the location of the compressor station and an up-to-date construction schedule including the target completion date consistent with the CPCN Application Guidelines;144F[145]
b. a cost estimate consistent with the CPCN Application Guidelines;145F[146]
c. an up-to-date risk analysis consistent with the CPCN Application Guidelines;146F[147] and
d. an account of the Project Development Costs following the format of PNG’s response to BCUC IR 2.6.1 with an additional column stating funds receiver from shipper.
2. Project Status Reports
Anytime the target completion date is delayed beyond what was previously reported to the Commission, PNG must file within seven days a project status report which includes:
a. the current target completion date;
b. actual project development costs spent to date;
c. the remaining estimated project development cost budget; and
d. any changes from the initial budget.
e. Any other items included in quarterly status reports to EDFT.
3. Transportation Service Agreements
a. PNG must file all executed TSAs for transportation service on the Interconnecting Pipeline no later than ten days following their execution.
b. PNG must file all executed non-TSAs that reserve rights on the Interconnecting Pipeline no later than ten days following their execution.
4. A Final Report
The Final Report must be filed within six months of substantial completion of the Interconnecting Pipeline. It must provide a complete breakdown of the final costs of the Interconnecting Pipeline and compare these costs to the cost estimates provided in the Pipeline Diameter Compliance Filing. This report must provide an explanation of any cost variance of 20 percent or more and any schedule variance beyond the target completion date as reported in the first Project Status Report.
Dated at the City of Vancouver, in the Province of British Columbia, this 9th day of October 2015.
Original signed by:
____________________________________
D. A. Cote
Panel Chair
Original signed by:
____________________________________
K. A. Keilty
Commissioner
Original signed by:
____________________________________
B. A. Magnan
Commissioner
IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
Pacific Northern Gas Ltd.
An Application for a Certificate of Public Convenience and Necessity to Construct and Operate
An Interconnecting Pipeline between Kitimat and Douglas Channel
BEFORE: D. A. Cote, Panel Chair, Commissioner
B. A. Magnan, Commissioner October 14, 2015
K. A. Keilty, Commissioner
O R D E R
WHEREAS:
A. On July 16, 2015, Pacific Northern Gas Ltd. (PNG) submitted an application to the British Columbia Utilities Commission (Commission), pursuant to sections 45 and 46, of the Utilities Commission Act (UCA), for a Certificate of Public Convenience and Necessity (CPCN) to construct and operate an approximate 8.8 kilometre interconnecting pipeline between Kitimat and Douglas Channel (Application);
B. In its Application, PNG seeks the following:
1. Approval, pursuant to sections 45 and 46 of the UCA, for a CPCN for the construction and operation of an interconnecting pipeline between Kitimat, British Columbia, and the Douglas Channel area, consisting of either:
i. A 10-inch diameter transportation pipeline and related compression and metering facilities to serve a single customer, or
ii. A 30-inch diameter transportation pipeline and related compression and metering facilities to serve multiple customers.
2. Approval for PNG to make a final construction decision between the 10-inch and 30-inch diameter pipeline alternatives based on the final investment decision made by the Douglas Channel LNG project and the financial commitments of other project proponents, subsequent to which PNG would file a compliance report with the Commission on the decision made;
3. Approval, pursuant to section 58 of the UCA, for the Interconnecting Transportation Reservation Agreement (TRA) between PNG and EDF Trading Limited dated January 23, 2015 including the form of Transportation Service Agreement attached thereto; and
4. Approval, pursuant to section 58 of the UCA, for the TRA between PNG and Triton LNG Limited Partnership dated July 22, 2015 including the form of Transportation Service Agreement attached thereto.
C. By Orders G-122-15 and G-137-15, the Commission established a hearing process and the regulatory timetable for the Application;
D. On July 31, 2015, PNG filed and requested confidential treatment of supplemental information on cost estimates and revenue requirement impacts of the proposed interconnecting pipeline, citing commercial sensitivity of the information and potential harm to commercial interests in a globally competitive environment;
E. Registered interveners in the proceeding are: British Columbia Pensioners’ and Seniors’ Organization, Active Support Against Poverty, BC Coalition of People with Disabilities, Counsel of Senior Citizens’ Organizations of BC, and the Tenant Resource and Advisory Centre; LNG Canada Development Inc. ; and British Columbia Hydro and Power Authority. FortisBC Energy Inc. registered as an interested party in the proceeding;
F. The Commission has reviewed the evidence in this proceeding and finds that certain approvals are necessary and in the public interest.
NOW THEREFORE for the reasons articulated in the Decision issued concurrently with this order, the Commission orders as follows:
1. Pursuant to section 45 and 46 of the Utilities Commission Act (UCA), a Certificate of Public Convenience and Necessity (CPCN) is granted to Pacific Northern Gas Ltd (PNG) to construct and operate an interconnecting pipeline between its existing pipeline terminus at Kitimat, British Columbia and the Douglas Channel area, consisting of either:
a. A 10-inch diameter transmission pipeline and related compression and metering facilities, or
b. A 30-inch diameter transmission pipeline and related metering facilities. The related compression equipment is also approved provided the compression equipment is electrically driven.
2. Should PNG choose to utilize a non-electric compression drive sized for the 30-inch option it must apply for a CPCN for that component of the project with justification and consideration of the British Columbia energy objectives in Part 1, section 2 of the Clean Energy Act.
3. PNG must submit a compliance filing confirming its decision to proceed with either the 10-inch or 30-inch interconnecting pipeline option by the earlier of within 30 days of a decision being made or by the end of 2015, including information described in the reporting section of the attached Decision.
4. Prior to the start of construction of the interconnecting pipeline, PNG must:
a. ensure payment for all development costs are received,
b. have an executed Transportation Service Agreement (TSA) with EDF Trading Limited accepted by the Commission and all applicable credit support with EDF Trading Limited, and
c. ensure gas metering is addressed in its detailed design to address gas balancing issues for multiple shippers as described in the attached Decision.
5. Pursuant to section 58 of the UCA, approval is granted for the Interconnecting Transportation Reservation Agreements (TRAs) between PNG and EDF Trading Limited dated January 23, 2015 and between PNG and Triton LNG Limited Partnership dated July 22, 2015.
6. PNG, not its existing customers, will be responsible for any development costs in excess of amounts recovered from shippers;
7. The recovery of actual project development costs from EDF Trading Limited in material tranches, as incurred, until the development costs have been fully recovered, is approved.
8. With the exception of regulatory costs for this proceeding, PNG’s existing customers will not be at financial risk for the proposed facility should the project not proceed.
9. Pursuant to section 58 of the UCA, approval is granted for the form of the TSAs attached to the TRAs, including the toll calculations, with the following exceptions:
a. PNG is to amend the form of TSA and file with the Commission no later than three months prior to PNG’s expected start of construction as follows:
i. An amendment to include administrative and general (overhead) costs for shippers that only take service from PNG on the interconnecting pipeline;
ii. An amendment to include comparable penalty charges for all shippers in the event a shipper takes excess gas during a curtailment.
b. The fixed $60,000 in Operating, Maintenance, General and Administrative (OMG&A) provision based on 2013 dollars and inflated by the Consumer Price Index is approved in the toll calculations for the 10-inch pipeline option. In the event that the TSAs negotiated between PNG and the shippers on a 30-inch interconnecting pipeline result in a revenue shortfall related to OMG&A, such revenue shortfall must not be recovered from existing ratepayers. PNG must provide an updated allocation of OMG&A based on actual costs, using the same methodology used in the Application, as part of its revenue requirement applications with the Commission.
c. If differences arise between the approved form of TSA, including above amendments, that are significant, these differences must be filed with the Commission for approval.
d. PNG must file all executed TSAs and other agreements that reserve rights on the interconnecting pipeline with the Commission no later than ten days following their execution.
10. PNG is directed to investigate potential options and provide a cost benefit analysis for options to mitigate stranded asset risks and consequences with respect to the 10-inch pipeline on behalf of its existing ratepayers and provide this analysis with its recommended option as part of its next revenue requirements application.
11. PNG must file within 6 months of the date of this order a proposal outlining how PNG intends to approach the issues related to harmonization of terms and conditions among shippers including a timeline.
12. PNG must provide Project status reports and final project reports including information as described in the Reporting section of the attached Reasons for Decision.
13. PNG must comply with all other directives contained in the Decision issued concurrently with this order.
14. The project cost estimates and revenue requirement analysis information filed confidentially on July 31, 2015 will be held confidential by the Commission.
DATED at the City of Vancouver, in the Province of British Columbia, this 9th day of October 2015.
BY ORDER
Original signed by:
D. A. Cote
Panel Chair/ Commissioner
IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
Pacific Northern Gas Ltd.
Application for a Certificate of Public Convenience and Necessity to
Construct and Operate an Interconnecting Pipeline between Kitimat and Douglas Channel
EXHIBIT LIST
Exhibit No. Description
Commission documents
|
A-1 |
Letter dated July 22, 2015 - Appointing the Commission Panel for the review of the Pacific Northern Gas Ltd. Application for a Certificate of Public Convenience and Necessity to Construct and Operate an Interconnecting Pipeline between Kitimat and Douglas Chanel |
|
A-2 |
Letter dated July 22, 2015 – Commission Order G-122-15 establishing a Regulatory Timetable |
|
A-3 |
Letter dated August 14, 2015 – Commission Order G-137-15 amending the Regulatory Timetable |
|
A-4 |
Letter dated August 17, 2015 – Commission Information Request No. 1 to PNG |
|
A-5 |
Confidential Letter dated August 17, 2015 – Commission Confidential Information Request No. 1 to PNG |
|
A-6 |
Letter dated September 3, 2015 – Commission Information Request No. 2 to PNG |
|
A-7 |
Confidential Letter dated September 3, 2015 – Commission Confidential Information Request No. 2 to PNG |
Applicant documents
|
B-1 |
Pacific Northern Gas Ltd. (PNG) Letter dated July 16, 2015 – Application for a Certificate of Public Convenience and Necessity to Construct and Operate an Interconnecting Pipeline between Kitimat and Douglas Channel |
|
B-2 |
Letter dated July 29, 2015 – PNG Submitting Supplemental Information |
|
B-2-1 |
Confidential Letter dated July 31, 2015 – PNG Submitting Confidential Supplemental Information |
|
B-3 |
Letter dated August 11, 2013 – PNG Submitting comments on review process |
|
B-4 |
Letter dated August 28, 2015 – PNG Submitting Response to BCUC IR No. 1 |
|
B-5 |
Confidential Letter dated August 28, 2015 – PNG Submitting Response to Confidential BCUC IR No. 1 |
|
B-6 |
Letter dated August 28, 2015 – PNG Submitting Response to BC Hydro IR No. 1 |
|
B-7 |
Letter dated August 28, 2015 – PNG Submitting Response to BCOAPO IR No. 1 |
|
B-8 |
Letter dated August 28, 2015 – PNG Submitting Response to LNG Canada IR No. 1 |
|
B-9 |
Confidential Letter dated September 10, 2015 - PNG Submitting Response to Confidential BCUC IR No. 2 |
|
B-10 |
Letter dated September 10, 2015 - PNG Submitting Response to BCUC IR No. 2 |
|
B-11 |
Letter dated September 10, 2015 - PNG Submitting Response to BCOAPO IR No. 2 |
|
B-12 |
Letter dated September 10, 2015 - PNG Submitting Response to LNG Canada IR No. 2 |
Intervener documents
|
C1-1 |
British Columbia Old Age Pensioners’ Organization, Disability Alliance BC, Council of Senior Citizens’ Organizations of BC, and the Tenant Resource and Advisory Centre (BCOAPO) Letter Dated July 29, 2015– Request for Intervener Status by Sarah Khan, and James Wightman |
|
C1-2 |
Letter dated August 11, 2015 – BCOAPO Submitting comments on review process |
|
C1-3 |
Letter dated August 24, 2015 – BCOAPO Submitting Information Request No. 1 |
|
C1-4 |
Letter dated September 3, 2015 – BCOAPO Submitting Information Request No. 2 |
|
C2-1 |
LNG Canada Development Inc. (LNGC) Letter Dated August 7, 2015 – Request for Intervener Status by Lisa Jamieson, Robin Sirett, Jan Poetsch and Krey Stirland |
|
C2-2 |
Letter Dated August 17, 2015 – LNGC Submitting IR No. 1 to PNG |
|
C2-3 |
Letter Dated September 3, 2015 – LNGC Submitting IR No. 2 to PNG |
|
C3-1 |
British Columbia Hydro and Power Authority (BC Hydro) – Web registration dated August 7, 2015 – Request for Intervener Status |
|
C3-2 |
Letter dated August 11, 2015 – BC Hydro Submitting comments on review process |
|
C3-3 |
Letter Dated August 17, 2015 – BC Hydro Submitting IR No. 1 to PNG |
Interested party documents
|
D-1 |
FortisBC Energy Inc. (FEI) Letter dated July 28, 2015 – Request for Interested Party Status |
Letters of comment
|
E-1 |
District of Kitimat Council - Letter of Comment dated September 1, 2015 |
[1] Exhibit B-1, PNG Cover Letter.
[2] Exhibit B-1, p. 2.
[3] Exhibit B-1, pp. 8–9.
[4] Exhibit B-1, pp. 6–7.
[5] Exhibit B-1, p. 7.
[6] Exhibit B-1, Cover Letter, p. 2; Exhibit B-4, BCUC IR 1.8.3.1.
[7] Exhibit B-1, Appendix D, Article 5.1.
[8] Exhibit B-4, BCUC IR 1.2.0, pp. 4–6.
[9] Exhibit B-1, Section 3.5, p. 19.
[10] Exhibit B-4, BCUC IR 1.9.4, p. 21.
[11] Exhibit B-8, LNG Canada IR 1.3.3; Exhibit B-1, p. 21.
[12] Exhibit B-1, Exhibit 4-4, p. 24.
[13] Exhibit B-10, BCUC IR 2.5.1, p. 15.
[14] Exhibit B-4, BCUC IR 1.9.3, p. 21.
[15] Exhibit B-1, Section 4.2, pp. 22–23.
[16] Exhibit B-1, Exhibit 3-1, p. 13.
[17] Exhibit B-1, Section 4.4, pp. 24–25.
[18] Exhibit B-1, Appendix F, Physical Environment – Clean Surface Water and Groundwater.
[19] Exhibit B-10, BCUC IR 2.2.5.
[20] Exhibit B-1, Section 4.6, p. 27.
[21] Exhibit B-1, Exhibit 4-5, p. 28.
[22] Exhibit B-4, p. 34.
[23] Ibid.
[24] Exhibit B-1, Appendix D and E, Schedule D.
[25] Ibid.
[26] Exhibit B-1, p. 12.
[27] Ibid.
[28] Ibid.
[29] Exhibit B-1, p. 18.
[30] Exhibit B-2-1.
[31] Exhibit B-1, p. 18.
[32] Ibid.
[33] Exhibit B-4, BCUC IR 1.8.3.
[34] Exhibit B-1, p. 26.
[35] Exhibit B-1, p. 25.
[36] Exhibit B-1, p. 18.
[37] Exhibit B-4, BCUC IR 1.5.3.
[38] Exhibit B-1, p. 18.
[39] Exhibit B-1, p. 20.
[40] Exhibit B-1, pp. 16–18.
[41] Exhibit B-4, BCUC IR 1.5.1.
[42] Ibid.
[43] Ibid.
[44] Exhibit B-1, Appendix D, Schedule C, Schedule C: General Terms and Conditions, pp. 2–4.
[45] Ibid. p. 5.
[46] Ibid. pp. 2–5.
[47] Exhibit B-4, BCUC IR 1.5.1.
[48] Exhibit B-4, BCUC IR 1.5.2 & 1.5.3.
[49] Exhibit B-10, Appendix A.
[50] Exhibit B-4, BCUC IR 1.5.2 & 1.5.3.
[51] Exhibit B-10, BCUC IR 2.1.2 & 2.1.3.
[52] BCOAPO Final Submission, p. 3
[53] Ibid., pp. 3–5.
[54] PNG Reply Submission, p. 5.
[55] PNG Final Submission, p 5.
[56] Exhibit B-4, BCUC IR 1.9.12
[57] Exhibit B-1, Cover Letter, p. 3.
[58] Exhibit B-1, pp.5–6; Exhibit B-2-1, p. 2.
[59] BCOAPO Final Submission, p. 5.
[60] PNG Final Submission, p. 6.
[61] Exhibit B-4, BCUC IR 1.14.1.
[62] Ibid.
[63] Exhibit B-4, BCUC IR 1.14.2.
[64] Exhibit B-10, BCUC IR 2.6.2.1.
[65] Exhibit B-1, Appendix D, pp. 4, 5.
[66] Exhibit B-1, Appendix D, p. 4.
[67] Exhibit B-4, BCUC IR 1.14.1.1.
[68] Exhibit B-4, BCUC IR 1.14.1.2.
[69] BCOAPO Final Submission, p. 5.
[70] PNG Reply Argument, p. 6.
[71] Exhibit B-1, PNG Cover Letter.
[72] Exhibit B-1, Appendix D and E, Schedule D.
[73] Exhibit B-4, BCUC IR 1.9.11.
[74] Ibid.
[75] Exhibit B-4, BCUC IR 1.20.2.
[76] Exhibit B-4, BCUC IR 1.23.1, 1.23.1.2.
[77] BCOAPO Final Submission, p. 5.
[78] Exhibit B-4, p. 34.
[79] Exhibit B-1, p. 42.
[80] Exhibit B-1, pp. 41–42.
[81] Exhibit B-1, p. 41.
[82] Exhibit B-10, BCUC IR 2.13.1.
[83] Exhibit B-1, p. 42.
[84] Exhibit B-4, BCUC IR 1.27.1.
[85] Exhibit B-1, p. 43.
[86] PNG Final Submission, p. 14.
[87] Ibid.
[88] Ibid.
[89] Ibid.
[90] PNG Final Submission, p. 4.
[91] BCOAPO Final Submission, p. 3.
[92] Ibid.
[93] BCOAPO Final Submission, p. 3.
[94] PNG Reply Submission, p. 2.
[95] Ibid.
[96] PNG Reply Submission, p. 3.
[97] Ibid.
[98] Exhibit B-1, Appendix D, p. 5.
[99] Exhibit B-1, Appendix D, Schedule C to the Service Agreement, General Terms and Conditions.
[100] Exhibit B-4, BCUC IR 1.5.1.
[101] Exhibit B-1, Appendix E, p. 5.
[102] Exhibit B-4, BCUC IR 1.5.1.
[103] Exhibit B-4, BCUC IR 1.19.1.1.
[104] Exhibit B-4, BCUC IR 1.19.2.
[105] BCOAPO Final Submission, p. 5
[106] Exhibit B-1, p. 33.
[107] Exhibit B-4, BCUC IR 1.7.3.
[108] Exhibit B-4, BCUC IR 1.7.3.1.
[109] Exhibit B-1, p. 33.
[110] Exhibit B-1, pp. 31–32.
[111] Exhibit E-1.
[112] Exhibit B-4, BCUC IR 1.34.1.
[113] Exhibit B-2, Appendix G.
[114] Exhibit B-1, Appendix H.
[115] Exhibit B-1, p. 31.
[116] Exhibit B-2, Appendix G.
[117] Exhibit B-4, BCUC IR 1.34.2.
[118] Exhibit B-4, BCUC IR 1.34.3.
[119] PNG Final Submission, p. 20.
[120] Exhibit B-4, BCUC IR 1.33.3; Exhibit B-1, p. 28.
[121] PNG Final Submission, p. 20; Exhibit B-8, LNG Canada IR 1.4.1.
[122] Exhibit B-4, BCUC IR 1.33.1.
[123] Exhibit B-4, BCUC IR 1.33.2.
[124] LNG Canada Final Submission, pp. 1–2.
[125] LNG Canada Final Submission, p. 3.
[126] BC Hydro Final Submission.
[127] Exhibit B-4, BCUC IR 1.16.2.
[128] Exhibit B-10, BCUC IR 2.14.5, Appendix B.
[129] Exhibit B-10, Appendix B, p. 5.
[130] Exhibit B-1, Appendix D and E, Schedule D.
[131] Exhibit B-4, BCUC IR 1.29.1.
[132] Exhibit B-10, Appendix B, p .5.
[133] Ibid.
[134] Exhibit B-4, BCUC IR 1.29.6.
[135] Exhibit B-4, BCUC IR 1.11.2.
[136] BCOAPO Final Submission, p. 5.
[137] Exhibit B-1, Appendix D, pp. 6,7.
[138] Exhibit B-4, BCUC IR 1.15.1.
[139] Exhibit B-1, Appendix D and E, Schedule A, p. 4.
[140] Exhibit B-1, Appendix B, Order 2.
[141] Exhibit B-1, Appendix D, Article 2.3, p. 3.
[142] Exhibit B-4, BCUC IR 1.16.2.1, p. 40.
[143] Exhibit B-8, LNG Canada IR 2.5, p. 3.
[144] Exhibit B-12, LNG Canada IR 2.7, p. 3.
[145] Order G-50-10, Appendix A, Sections 4(i-ii)
[146] Order G-50-10, Appendix A, Section 5
[147] Order G-50-10, Appendix A, Section 4(v)