| Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd.
Application for Approval of a Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements |
| Decision and Order G-339-22 |
| November 25, 2022 |
|
|
| Before: R. I. Mason, Panel Chair A. C. Dennier, Commissioner M. Kresivo, KC, Commissioner |
TABLE OF CONTENTS
Page no.
1.4 Regulatory Process and Participants
2.0 Definitions of Low Carbon Energy and Renewable Natural Gas
3.1 Objectives of the Low Carbon Energy Program
3.2 Low Carbon Energy Disposition Methodology
3.2.1 Smart Energy Program Customers
3.2.4 Allocation to PNG Customers
4.0 Low Carbon Energy Program Cost Recovery
4.1 Low Carbon Energy Cost Variance Account
4.1.2 Configuration of the Customer Information System
4.1.6 Amortization of Non-Recurring Expenses
4.2 Low Carbon Commodity Charge
4.3 Transfer of Costs to the Company Use Gas Account
4.5 Transfer to Gas Cost Variance Account
4.6 Low Carbon Energy Cost Recovery Rider
4.7 Tariffs and General Terms and Conditions
6.0 Review of the Low Carbon Energy Program
APPENDICES
Appendix A List of Acronyms
Appendix B Exhibit List
On November 17, 2021, Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. (collectively, PNG) submitted an application to the British Columbia Utilities Commission (BCUC) seeking, among other things, approval of its low carbon energy (Low Carbon Energy) cost recovery methodology pursuant to sections 59 to 61 of the Utilities Commission Act (UCA)(Application).[1]
PNG has variously defined the term Low Carbon Energy to mean “biomethane” and “forms of energy delivered by PNG that have a lower carbon intensity than natural gas”, and characterizes its energy portfolio as “low carbon” rather than biomethane because it “recognizes that, in addition to biomethane, other forms of gaseous energy can be delivered through PNG’s natural gas distribution systems that lower the GHG [Greenhouse Gas] emissions associated with providing energy to heat homes and fuel industries in PNG’s service area.”
In the Panel’s view, PNG’s definitions and characterizations of the term “Low Carbon Energy” are potentially contradictory and confusing. Therefore, for the purposes of this decision the Panel defines the term “Low Carbon Energy” to be synonymous with the term “renewable natural gas” as defined by the BCUC in the BCUC’s Inquiry into the Acquisition of Renewable Natural Gas by Public Utilities in British Columbia. Based on the BCUC’s current definition of renewable natural gas, Low Carbon Energy thus includes both biomethane and conventional natural gas combined with separately acquired environmental attributes that arise from the production of biomethane. PNG may apply to the BCUC to add other forms of energy to its Low Carbon Energy program.
PNG is acquiring Low Carbon Energy from two suppliers through biomethane purchase agreements accepted by the Panel earlier in this proceeding (Biomethane Purchase Agreements).[2] The Biomethane Purchase Agreements were accepted as prescribed undertakings pursuant to Section 18 of the Clean Energy Act (CEA) and the Greenhouse Gas Reduction Regulation (GGRR).
PNG proposes to dispose of its Low Carbon Energy supply in a manner which it states will mitigate, as much as possible, the impact of higher priced Low Carbon Energy costs on PNG’s customers, while maximizing the greenhouse gas emission reduction benefits of Low Carbon Energy to PNG and its customers.[3] PNG proposes four disposition mechanisms, in the following order of priority:[4]
1. Supply the demand from PNG’s voluntary Low Carbon Energy program (Smart Energy program) customers;
2. Supply the demand from company use;
3. Sell to off-system counterparties; and
4. Allocate to PNG customers.
The Panel approves PNG’s proposed disposition mechanisms, subject to the following findings and determinations:
• The Panel does not accept PNG’s proposal to exclude its customers in Tumbler Ridge from the Smart Energy program, because PNG has an obligation to serve all customers who apply for service within its service area. PNG must provide service without undue discrimination or undue delay, and any additional demand from Smart Energy customers from Tumbler Ridge, however small, would potentially reduce the costs of the Low Carbon Energy imposed involuntarily on PNG’s customers who are not part of the Smart Energy program.
• The Panel does not accept that PNG’s customers in Tumbler Ridge should be excluded from the additional costs associated with using Low Carbon Energy for Company Use Gas. In the Panel’s view, PNG’s customers in Tumbler Ridge should bear some portion of PNG’s cost to decarbonize its distribution system, and the assignment of 100 percent of the company use Low Carbon Energy to PNG’s natural gas customers other than those in Tumbler Ridge is unduly discriminatory.
• The Panel finds that off-system sales of Low Carbon Energy are reasonable if PNG recovers an amount at least equivalent to the cost of the same quantity of conventional natural gas. In the absence of off-system sales, any surplus Low Carbon Energy not used by customers of the Smart Energy program or by PNG for Company Use Gas would be used by PNG’s customers in place of conventional natural gas. If PNG were to make off-system sales at a price lower than the cost of conventional natural gas, PNG’s other customers would have been better off without the off-system sale being made and using the Low Carbon Energy themselves.
• The Panel does not agree with PNG that the BCUC has no jurisdiction over PNG’s sales of Low Carbon Energy to parties unless they are public utilities. In the Panel’s view, the BCUC has jurisdiction over all of PNG’s sales of Low Carbon Energy, either under section 71 of the UCA if the sale is to a public utility, and under sections 61 and 63 otherwise. The Panel directs PNG to file a rate schedule for off-system sales of Low Carbon Energy for review and approval by the BCUC if it wishes to sell Low Carbon Energy to parties that are not public utilities.
PNG’s proposed low carbon energy cost recovery mechanism includes establishing a non-rate base deferral account, the low carbon energy cost variance account (Low Carbon Energy Cost Variance Account), to capture costs and recoveries associated with its Low Carbon Energy program. PNG’s proposed costs include acquiring Low Carbon Energy and marketing and administering its Low Carbon Energy program, and the recoveries come from the following sources:[5]
• Sales of Low Carbon Energy to voluntary Low Carbon Energy customers through a Low Carbon Energy commodity charge (Low Carbon Energy Commodity Charge);
• Transfers of Low Carbon Energy used by PNG’s for its own use;
• Off-system sales; and
• Recovery of the remaining costs from PNG customers through the Low Carbon Energy cost recovery rate rider (Low Carbon Energy Cost Recovery Rider).
The Panel makes the following findings and recommendations regarding PNG’s proposed cost recovery mechanisms:
• The Panel approves PNG to create the Low Carbon Energy Cost Variance Account, a non-rate base regulatory account bearing interest at PNG’s short term interest rate applied to both debit and credit balances. Pursuant to section 18 (2) of the CEA the BCUC must allow PNG to collect the cost of acquiring renewable natural gas (RNG), and the Low Carbon Energy Cost Variance Account is an appropriate regulatory mechanism for those costs to be recovered.
• The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the cost of Low Carbon Energy acquired as prescribed undertakings as defined in section 2(3.8) of the GGRR.
• The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the cost of configuring its customer information to a maximum cost of $75,000 amortized equally over 10 years.
• The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the costs associated with performance assurances that may be required as a result of acquiring RNG as a prescribed undertaking pursuant to the GGRR.
• The Panel directs PNG to record in the Low Carbon Energy Cost Variance Account any incremental administration costs associated with managing the supply of the Low Carbon Energy portfolio, administering the Smart Energy program, and monitoring and reporting on the performance of the Low Carbon Energy portfolio. Allocating PNG’s administrative costs properly between its Low Carbon Energy program and its other regulated services better supports rate setting for each of PNG’s service consistent with the cost causation principle and supports the “full transparency to the cost of [Low Carbon Energy]” that PNG itself supports.[6]
• The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account actual marketing expenses associated with the Smart Energy program to the following limits: up to $95,000 in 2024; up to $95,000 in 2025; and up to $60,000 in 2026.
• The Panel is concerned that PNG’s proposed spending on incentives might be unduly discriminatory pursuant to section 39 or 59 of the UCA because PNG plans to offer incentives only to those Smart Energy customers who take specific blends of Low Carbon Energy. PNG provides no specifics as to the incentives it will offer. Therefore, the Panel directs PNG to report annually starting in 2022 its expenditure on Smart Energy program incentives, providing details of the nature and recipients of the incentives and why the incentives were not unduly discriminatory.
• The Panel approves the creation of a Smart Energy Marketing Cost Deferral Account, a non-rate base regulatory account bearing interest at PNG’s short term interest rate applied to both debit and credit balances, and to record in this account its actual marketing expenses associated with the Smart Energy program up to a limit of $285,000 between 2022 and 2023.
• The Panel approves PNG to amortize the balance in the Smart Energy Marketing Cost Deferral Account into the Low Carbon Energy Cost Variance Account over the years from 2022 to 2025 inclusive such that the Low Carbon Commodity Cost remains close to its long-term average.
• The Panel approves PNG to charge a Low Carbon Commodity Charge of $27.50 per GJ and directs PNG to record the revenues received from the Low Carbon Commodity Charge in the Low Carbon Energy Cost Variance Account.
• The Panel approves PNG to use an adjustment mechanism for the Low Carbon Commodity Charge whereby the Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting to the BCUC.
• The Panel approves PNG to transfer the cost of Low Carbon Energy allocated to company use gas from the Low Carbon Energy Cost Variance Account to the Company Use Gas Account.
• The Panel accepts that the Low Carbon Energy transferred from the Low Carbon Energy Cost Variance Account to the Company Use Gas Account will be valued at the Low Carbon Commodity Charge (i.e. the full cost of the Low Carbon Energy). However, the Panel has reservations that PNG has not adequately justified the use of Low Carbon Energy as the most cost-effective way to reduce its GHG emissions. When the BCUC reviews PNG’s Low Carbon Energy program, the Panel recommends that the BCUC consider whether the valuation at the Low Carbon Commodity Charge is justified.
• The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the revenues received from its off-system sales of Low Carbon Energy.
• The Panel approves PNG to transfer the cost of Low Carbon Energy allocated to its customers from the Low Carbon Energy Cost Variance Account to the Gas Cost Variance Account at the natural gas commodity rate in effect at the time of the transfer.
• The Panel approves PNG to levy an initial Low Carbon Energy Cost Recovery Rider of $0.00 per GJ and directs PNG to record the revenues received from the Low Carbon Energy Cost Recovery Rider in the Low Carbon Energy Cost Variance Account.
• The Panel directs PNG to collect the Low Carbon Energy Cost Recovery Rider from all its non-bypass customers including those in its Granisle and Tumbler Ridge service areas. The costs of Low Carbon Energy supply in excess of recoveries from the Smart Energy program are a required cost of PNG continuing to serve all its customers, as PNG itself has noted. As a result, the costs collected by the Low Carbon Energy Cost Recovery Rider are not related to any PNG specific service area, fuel type or type of customers, and apply to all customers whether or not they choose or are able to participate in the Smart Energy program.
• The Panel approves PNG to use an adjustment mechanism for the Low Carbon Energy Cost Recovery Rider whereby the Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting to the BCUC.
• The Panel is concerned about how PNG’s proposed rate adjustment mechanism for the Low Carbon Energy Cost Recovery Rider will work with respect to PNG’s proposal to maintain six months supply of Low Carbon Energy supply, the cost of which will be recorded in the Low Carbon Energy Cost Variance Account. The Panel directs PNG, in a compliance filing, to propose a mechanism by which the cost of its six months’ inventory of Low Carbon Energy supply may be recovered from the Smart Energy customers who benefit from it rather than from all PNG’s customers.
• The Panel is also concerned about the disposition of any variances between the forecast and actual Low Carbon Energy program costs, which will be retained in the Low Carbon Energy Cost Variance Account and recovered from all PNG’s customers. The Panel anticipates that such variances between forecast and actual costs will be small, and that no significant inequities will result, but recommends that the BCUC monitor PNG’s forecast and actual spending to ensure this is the case. The Panel directs that PNG report annually its forecast and actual expenditures in all categories related to the Smart Energy program.
The Panel directs PNG to file with the BCUC, by June 30, 2026, an analysis of its Low Carbon Energy program from the date of its inception to December 31, 2025. However, if there is any change to the circumstances affecting PNG’s Low Carbon Energy program, including regulatory or legislative changes, PNG may submit an application to modify the program at any time.
1.0 Introduction
On November 17, 2021, Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. (collectively, PNG) submitted an application to the British Columbia Utilities Commission (BCUC) seeking approval of its low carbon energy (Low Carbon Energy) cost recovery methodology pursuant to sections 59 to 61 of the Utilities Commission Act (UCA), which would enable PNG to sell Low Carbon Energy to its customers and recover Low Carbon Energy related costs through rates and rate riders charged to PNG customers; and approval pursuant to section 71 of the UCA and the BCUC Rules for Natural Gas Energy Supply Contracts of two executed biomethane purchase agreements (Biomethane Purchase Agreements) (Application).[7]
PNG’s Low Carbon Energy cost recovery mechanism includes establishing a non-rate base deferral account, the low carbon energy cost variance account (Low Carbon Energy Cost Variance Account), to capture costs incurred by PNG to acquire Low Carbon Energy; and the recovery of Low Carbon Energy-related costs by sales to voluntary Low Carbon Energy customers through a Low Carbon Energy commodity charge (Low Carbon Energy Commodity Charge), by supplying loads associated with PNG’s own operations (Company Use Gas) and off-system sales, with the remaining costs allocated to PNG customers through the Low Carbon Energy cost recovery rate rider (Low Carbon Energy Cost Recovery Rider). PNG requests approval of an initial Low Carbon Energy Commodity Charge of $27.50 per gigajoule. PNG’s Application includes supporting amendments to rate schedules.[8]
The Biomethane Purchase Agreements, with ATCO Future Fuel RNG Limited Partnership (ATCO RNG) and Tidal Energy Marketing Inc. (Tidal RNG), form the initial tranche of Low Carbon Energy supply in PNG’s Low Carbon Energy portfolio.[9] By Order E-7-22 dated April 1, 2022, the BCUC accepted the Biomethane Purchase Agreements as prescribed undertakings pursuant to Section 18 of the Clean Energy Act (CEA) and the Greenhouse Gas Reduction (Clean Energy) Regulation (GGRR). Section 18(2) of the CEA requires the BCUC to allow PNG to recover the costs incurred with respect to the prescribed undertaking of acquiring renewable natural gas from ratepayers .[10]
1.1 Background
PNG owns and operates the PNG-West natural gas transmission and distribution system in west central British Columbia. The pipeline system commences at Summit Lake, just north of Prince George, and extends west to the deep-water ports of Prince Rupert and Kitimat. PNG-West serves approximately 20,400 natural gas customers in these communities as well as in Port Edward, Terrace, Smithers, Telkwa, Houston, Burns Lake, Fraser Lake, Fort St. James and Vanderhoof. PNG-West also serves approximately 130 propane customers in the community of Granisle, BC.[11]
PNG is the parent company of Pacific Northern Gas (N.E.) Ltd. (PNG(N.E.)) which owns and operates natural gas distribution systems and a gas processing plant in northeastern British Columbia. PNG(N.E.) provides service to approximately 21,500 natural gas customers in the communities of Fort St. John, Dawson Creek and Tumbler Ridge.[12]
PNG is a wholly-owned subsidiary of TriSummit Utilities Inc., the owner of a number of Canadian utilities and renewable power infrastructure assets.[13]
1.2 Legislative Framework
Sections 58—61 of the UCA provide the BCUC with its rate setting jurisdiction over public utilities. These sections provide the following:
• Sections 58 and 60 include mandatory considerations, including the requirement that rates not be “unjust, unreasonable, unduly discriminatory or unduly preferential” and authorize the BCUC to establish rates;
• Section 59(4) states that it is a question of fact, of which the BCUC is the sole judge, (a) whether a rate is unjust or unreasonable, (b)whether, in any case, there is undue discrimination, preference, prejudice or disadvantage in respect of a rate or service, or (c) whether a service is offered or provided under substantially similar circumstances and conditions;
• Section 59(5) provides that a rate is "unjust" or "unreasonable" if the rate is (a) more than a fair and reasonable charge for service of the nature and quality provided by the utility, (b) insufficient to yield a fair and reasonable compensation for the service provided by the utility, or a fair and reasonable return on the appraised value of its property, or (c) unjust and unreasonable for any other reason; and
• Section 60(1)(b.1) states that in setting a rate, the BCUC may use “any mechanism, formula or other method of setting the rate that it considers advisable and may order that the rate derived from such a mechanism, formula or other method is to remain in effect for a specified period.”
Further, the acquisition of renewable natural gas is a prescribed undertaking under section 2(3.8) of the GGRR.[14] Under section 18 of the CEA, the BCUC must set rates that allow a public utility to collect sufficient revenue in each fiscal year to enable it to recover costs incurred with respect to a prescribed undertaking and must not exercise a power under the UCA in a way that would directly or indirectly prevent a public utility from carrying out a prescribed undertaking.[15]
1.3 Approvals Sought
PNG outlined its original approvals sought in section 1.2 of the Application and identified one further item which required approval in response to information requests. Approvals sought are listed in the table below, along with the reference to sections of this Decision where the Panel addresses and makes determinations on the various requests:
Table 1: Approvals Sought
| Approval Sought |
Location in this Decision |
| Approve new Rate Schedules as set out in Section 6.2.1 of the Application: RS1-LCE: Residential Low Carbon Energy Service; RS2-LCE: Small Commercial Low Carbon Energy Service; RS3-LCE: Large Commercial Low Carbon Energy Service; RS4-LCE: Industrial Low Carbon Energy Service; RS5-LCE: Commercial Interruptible Low Carbon Energy Service; and RS6-LCE: Seasonal Low Carbon Energy Service. |
Section 4.2 |
| Approve proposed amendments to PNG’s General Terms and Conditions to include the addition of new definitions relating to the Low Carbon Energy Service, and the introduction of a Section 24 – Low Carbon Energy Service (Section 6.2.1 of the Application). |
Section 4.2 |
| Approve the cost recovery methodology related to the cost of acquiring Low Carbon Energy and its recovery, through rates, from PNG customers as described in Section 7 of the Application. |
Section 4 |
| Approve a non-rate base deferral account to capture the costs incurred by PNG to acquire Low Carbon Energy, and the revenues collected through the Low Carbon Commodity Charge, and thereby accumulate any differences between the two (the “Low Carbon Energy Cost Variance Account”) (Section 7.1 of the Application). |
Section 4.1 |
| Low Carbon Commodity Charge rate setting mechanism as described in Sections 7.8.1 and 7.8.4 of the Application, with the Low Carbon Commodity Charge set at $27.50 per gigajoule. |
Section 4.2 |
| Approve the Low Carbon Energy Cost Variance Account balance quarterly reporting process and the Low Carbon Energy Cost Recovery Rider[16] rate setting mechanism on a basis consistent with PNG’s existing gas cost reporting and rate setting mechanisms, as described in Sections 7.8.4 and 7.8.5 of the Application. |
Section 4.6 Section 5.0 |
| Allocation of costs to all customers and the accounting treatment of those costs as described in Section 7 of the Application. |
Section 4.6 |
| Biomethane Purchase Agreements with ATCO Future Fuel RNG Limited Partnership (Section 8.4 and confidential Appendix F) and Tidal Energy Marketing Inc. (Section 8.5 and confidential Appendix G). |
n/a[17] |
| Approval Sought |
Location in this Decision |
| Approval of a non-rate base interest-bearing deferral account to record implementation and marketing costs incurred in 2022 and 2023 with respect to the Smart Energy program.[18] |
Section 4.1.6 |
1.4 Regulatory Process and Participants
By Order G-6-22 dated January 11, 2022,[19] the BCUC established a written hearing process to review the Application, including intervener registration, two rounds of information requests, final submissions on the Biomethane Purchase Agreements and reply, submissions on further process, final arguments, and PNG’s reply.
Three parties registered as interveners:
• BC Sustainable Energy Association (BCSEA);
• FortisBC Energy Inc. (FEI); and
• the Residential Consumer Intervener Association (RCIA).
BCSEA and RCIA participated fully in the proceeding. FEI did not submit any information requests or intervener arguments. The BCUC received one letter of comment on the Application.
1.5 Decision Framework
In this Decision, the Panel reviews the relevant evidence, considers the positions of the parties, discusses the issues arising in the course of the proceeding and outlines the reasons for its determinations. The Decision is structured to specifically address the following items:
• Section 2.0 addresses the overarching principles and objectives for PNG’s Low Carbon Energy program.
• Section 3.0 addresses PNG’s proposed Low Carbon Energy disposition methodology, including:
o PNG’s proposed voluntary Smart Energy program;
o PNG’s proposal to allocate Low Carbon Energy supply as Company Use Gas;
o Off-system sales of Low Carbon Energy; and
o Allocation of remaining Low Carbon Energy to PNG’s customers.
• Section 4.0 addresses PNG’s proposed cost recovery mechanisms.
• Section 5.0 addresses PNG’s proposed annual reporting on the Low Carbon Energy Program.
• Section 6.0 addresses future evaluation of PNG’s Low Carbon Energy program.
• Section 7.0 addresses biomethane tax credit considerations.
2.0 Definitions of Low Carbon Energy and Renewable Natural Gas
PNG submits that biomethane is often referred to as renewable natural gas (RNG) and is a renewable and lower carbon energy source compared to conventional natural gas. In PNG’s submission, biomethane is created by processing biogas from the decomposition of organic materials into a product with properties indistinguishable from natural gas. PNG submits blending biomethane with its natural gas in pipelines will reduce the greenhouse gas (GHG) emissions associated with the delivery of energy to natural gas customers.[20]
PNG characterizes its portfolio of Low Carbon Energy supplies as “low carbon energy” rather than biomethane, as PNG recognizes that other forms of energy can be delivered through PNG’s distribution systems to lower the GHG emissions associated with providing energy in its service area.[21] PNG notes that this is consistent with the May 25, 2021, amendment to the GGRR, which includes the acquisition by utilities of (i) renewable natural gas, (ii) hydrogen produced using electricity generated from clean or renewable resources, (iii) waste hydrogen, (iv) synthesis gas derived from biomass (syngas), and (v) lignin derived from black liquor as prescribed undertakings.[22]
PNG states that although its Low Carbon Energy portfolio is designed to include hydrogen, lignin, and syngas, PNG will initially limit its Low Carbon Energy portfolio to biomethane.[23] PNG’s proposed general terms and conditions for its gas sales tariff accomplish this by defining Low Carbon Energy to mean biomethane.[24]
PNG will notionally receive custody of biomethane at Westcoast Station 2 under the Biomethane Purchase Agreements.[25] The delivery of biomethane to PNG is notional since the biomethane acquired will be physically introduced into a pipeline network outside of PNG’s system, and the physical natural gas delivered to PNG at Westcoast Station 2 may not contain any of the original biomethane injected into the pipeline network;[26] however, the environmental attributes of the biomethane will be contractually passed to PNG such that the physical commodity delivered will have all the same environmental attributes as the biomethane introduced into the pipeline system for the purposes of relevant legislation in BC.[27] PNG customers who opt-in to the voluntary Smart Energy program will receive a notional blend of biomethane with their natural gas service, with customers receiving credit for the associated emissions reduction and biomethane credit under the Carbon Tax Regulation.[28]
In the Final Report of Phase 1 of the BCUC Inquiry into the Acquisition of Renewable Natural Gas by Public Utilities in British Columbia (RNG Inquiry’s Phase 1 Report), the BCUC concluded that:[29]
The definition of RNG includes biomethane and also the acquisition of natural gas combined with separately acquired Environmental Attributes that arise from the production of biomethane.
Positions of the Parties
PNG considers the terms “biomethane” and “RNG” to be synonymous, and except when citing references to the GGRR, has used the term biomethane rather than RNG. PNG notes that this terminology is consistent with that found in the BC Carbon Tax Regulation, and with the purchase agreements that PNG is seeking BCUC acceptance of in this Application. [30]
PNG uses the term “RNG” in the Application to be consistent with the terminology used in the GGRR which identifies the acquisition of renewable natural gas as a prescribed activity. PNG submits it uses the term Low Carbon Energy, or “LCE,” when discussing forms of energy delivered by PNG that have a lower carbon intensity than natural gas. Low Carbon Energy includes, but is not limited to, biomethane.[31]
BCSEA submits it appreciates PNG’s definition of the terms “biomethane,” “renewable natural gas” and “low carbon energy.”
Panel Discussion
PNG has variously defined the term Low Carbon Energy to mean “biomethane” (in its proposed general terms and conditions for its gas sales tariff); and “forms of energy delivered by PNG that have a lower carbon intensity than natural gas” (in its Final Argument). PNG further states that it has characterized its portfolio as “low carbon” rather than as a portfolio of biomethane supply resources because it “recognizes that, in addition to biomethane, other forms of gaseous energy can be delivered through PNG’s natural gas distribution systems that lower the GHG emissions associated with providing energy to heat homes and fuel industries in PNG’s service area.”
In the Panel’s view, PNG’s definitions and characterizations of the term “Low Carbon Energy” are potentially contradictory and confusing. Therefore, for the purposes of this Decision, and for the following reasons, the Panel defines the term “Low Carbon Energy” to be synonymous with the term “renewable natural gas” as defined by the BCUC in the BCUC’s Inquiry into the Acquisition of Renewable Natural Gas by Public Utilities in British Columbia. Based on the BCUC’s current definition of renewable natural gas, Low Carbon Energy thus includes both biomethane and conventional natural gas combined with separately acquired environmental attributes that arise from the production of biomethane.
In the Biomethane Purchase Agreements accepted by the BCUC in this proceeding, PNG is acquiring its renewable natural gas notionally, which means that it is acquiring conventional natural gas combined with separately acquired environmental attributes that arise from the production of biomethane. The Panel’s definition of Low Carbon Energy as renewable natural gas permits PNG to include the gas it is acquiring under the Biomethane Purchase Agreements in its Low Carbon Energy program. The Panel also considers that defining Low Carbon Energy as renewable natural gas gives PNG the flexibility to acquire additional forms of energy that the BCUC may in future determine to be renewable natural gas under the GGRR as part of its Low Carbon Energy program without further application to the BCUC.
The Panel recognizes that its definition of Low Carbon Energy differs from PNG’s alternative definition of the term, “forms of energy delivered by PNG that have a lower carbon intensity than natural gas.” The Panel finds that PNG’s alternative definition of Low Carbon Energy is not consistent with the GGRR, which doesn’t refer to carbon intensity, and is not sufficiently specific for the purposes of the Low Carbon Energy program being considered in this Decision.
The Panel also recognizes that its definition of Low Carbon Energy does not include other forms of energy such as hydrogen, syngas and lignin. While the GGRR includes certain acquisitions of hydrogen, syngas and lignin as prescribed undertakings, as PNG notes, the cost of acquiring these other forms of energy could be materially different to the cost of acquiring renewable natural gas. Further, the Smart Energy program is defined as a blend of Low Carbon Energy with a customer’s natural gas supply. PNG has not explained how it would blend these other forms of energy with natural gas. As a result, the Panel finds it is inappropriate to include forms of energy other than renewable natural gas in the definition of Low Carbon Energy at present. This is consistent with PNG’s express exclusion of these other forms of energy from its proposed tariff. PNG may apply to the BCUC to add other forms of energy to its Low Carbon Energy program.
For additional clarity, in this Decision the Panel adopts from the BCUC’s RNG Inquiry’s Phase 1 Report the definition of Conventional Natural Gas as “natural gas which is formed from fossils and extracted from and below rocks within the earth’s surface.”
3.0 Low Carbon Energy Program
3.1 Objectives of the Low Carbon Energy Program
PNG aims to develop a portfolio of Low Carbon Energy supplies to replace a portion of PNG’s existing natural gas supply portfolio, which PNG submits will reduce the GHG emissions associated with the consumption of natural gas by PNG and its ratepayers.[32] PNG submits that its Low Carbon Energy acquisition strategy intends to balance two key considerations in PNG’s operating environment:[33]
1. The need for PNG to build a foundational portfolio of Low Carbon Energy supply in preparation to meet the Clean BC Policy objective of 15 percent renewable content in natural gas deliveries; and which remains a voluntary target at this time; and
2. The rate impact to PNG ratepayers, given that a 15 percent blend of Low Carbon Energy would result in an increase in delivered gas costs of approximately 17 to 27 percent to PNG’s residential ratepayers and some PNG customers already face the highest burner tip rates for natural gas in the province.
Based on these considerations, PNG has set four near-term goals for developing its Low Carbon Energy portfolio:[34]
1. Building PNG’s knowledge and capacity to identify sources of Low Carbon Energy supplies inside and outside of B.C., and to establish relationships with project developers and marketers of Low Carbon Energy for future sources of supply;
2. Developing the framework for recovering the cost of Low Carbon Energy supply from its customers in an appropriate, cost causal manner while minimizing the impact on customers’ rates as much as possible;
3. Developing demand for Low Carbon Energy from voluntary customers and to provide a source of Low Carbon Energy that helps customers meet their emission reduction goals; and
4. Utilizing a portion of its Low Carbon Energy to reduce emissions from its own facilities.
3.2 Low Carbon Energy Disposition Methodology
PNG proposes to dispose of its Low Carbon Energy supply in a manner which will mitigate, as much as possible, the impact of higher priced Low Carbon Energy costs on PNG’s customers, while maximizing the GHG emissions reduction benefits of Low Carbon Energy to PNG and its customers.[35] PNG proposes four disposition mechanisms, in the following order of priority:[36]
1. Supply the demand from PNG’s voluntary Low Carbon Energy program (Smart Energy program) customers;
2. Supply the demand for Company Use Gas;
3. Sell to off-system counterparties; and
4. Allocate to PNG customers.
Each of the disposition mechanisms and their prioritization are addressed in Sections 3.2.1 to 3.2.4 below.
PNG anticipates the risk that it is unable to supply the demand from the Smart Energy program during supply interruptions of a few months to be very low. However, if PNG is unable to supply the demand from the Smart Energy program, PNG would curtail the supply of Low Carbon Energy sold to off-system counterparties first, followed by curtailment for its own use. In the extremely unlikely event that PNG’s Low Carbon Energy supply cannot meet the demand from the Smart Energy program, PNG will have the ability to remove customers from the program, as described in the proposed amendment to PNG’s General Terms and Conditions – Gas Sales Tariff.[37]
3.2.1 Smart Energy Program Customers
PNG proposes to establish a voluntary Smart Energy program and make it available to residential, commercial, and industrial sales customers in its PNG-West, Fort St. John, and Dawson Creek service areas. The Smart Energy program will allow PNG sales customers the option to purchase a blend of Low Carbon Energy supply with their natural gas supply from 2 to 100 percent. [38]
PNG states it intends to set the price for Low Carbon Energy in the Smart Energy program “based on the full recovery of the cost of acquiring and delivering” the Low Carbon Energy.[39]
Customers participating in the Smart Energy program will be transferred the environmental attributes of the biomethane received and will receive a biomethane credit for the quantities of biomethane purchased pursuant to the BC Carbon Tax Regulation.[40]
PNG notes that transportation customers who acquire their natural gas either from marketers or directly from producers and receive that gas under PNG’s transportation service will not have access to Low Carbon Energy through the Smart Energy program. However, they will be able to access specific quantities, but not specific blending rates, of PNG’s Low Carbon Energy through an off-system sales agreement, either directly with PNG, or through a gas marketer.[41]
PNG proposes not to make the Smart Energy program available to customers of the Tumbler Ridge and Granisle service territories at this time.[42]
PNG states that customers and facilities in the Tumbler Ridge service area receive their natural gas directly from a gas producer, and that there is no physical path available to supply Low Carbon Energy to PNG’s customers or facilities in Tumbler Ridge from the Low Carbon Energy delivery point under the Biomethane Purchase Agreements at Westcoast Station 2.[43]
Customers located in the village of Granisle in the PNG-West service territory are not connected to the
PNG-West natural gas distribution system, and instead receive propane service from PNG.[44]
PNG also states that Granisle and Tumbler Ridge customers already pay some of the highest energy rates in BC, and consequently expects that participation in the voluntary Smart Energy program would be low in these areas. PNG forecasts that including these service territories would only add roughly 90 additional voluntary customers, resulting in minimal impacts to Smart Energy program participation and to the resulting Low Carbon Energy Cost Recovery Rider to be recovered from PNG ratepayers.[45]
PNG suggests that it would be possible to notionally transfer the environmental attributes to Granisle and Tumbler Ridge customers who choose to participate in the voluntary Smart Energy program if the BCUC accepts that this practice is consistent with definition of biomethane.[46] PNG proposes to consider whether the exclusion of these two service territories remains appropriate as it considers various amalgamation and associated rate design scenarios in the future.[47]
PNG also proposes to hold Low Carbon Energy supply equivalent to six months of winter demand from the Smart Energy program in a transactional storage account within the Low Carbon Energy Cost Variance Account.[48] This will help PNG to mitigate risks of supply disruptions to Smart Energy program participants in the event of unplanned or planned supply interruptions from its single source of supply anticipated for 2023.[49] PNG states it may alternatively elect to acquire additional biomethane under a short term agreement to mitigate a shortfall lasting only a few months.[50]
PNG estimates participation in the Smart Energy program to be relatively modest, with demand estimates ranging from 4,000 to 11,000 gigajoules per year.[51]
Positions of the Parties
PNG submits its proposed disposition methodology is structured to mitigate, as much as possible, the impact of higher priced Low Carbon Energy on the costs borne by PNG’s customers, while maximizing the GHG emission reduction benefits of Low Carbon Energy to those customers and to PNG itself.[52]
PNG submits that in the absence of a mandatory emissions cap, its proposed Low Carbon Energy cost recovery mechanism is appropriate because it spreads the costs of acquiring biomethane across the greatest number of customers to minimize rate impacts associated with the acquisition of biomethane. [53]
PNG submits it anticipates it can achieve “adequate enrolment” in the Smart Energy program provided the cost to residential customers is between $2 and $8 per month, equivalent to a blend of Low Carbon Energy of approximately one to five percent.[54]
BCSEA accepts that the Smart Energy program is not available to PNG’s transportation service customers. [55]
RCIA submits that it supports the principle of providing alternatives to natural gas while avoiding cross-subsidization “between customers opting into greater amounts of Low Carbon Energy purchases and those that opt for less Low Carbon Energy in their delivered natural gas.”[56]
RCIA supports the disposition mechanisms proposed by PNG because they appear to be practical and efficient means of addressing logistical issues associated with the procurement of Low Carbon Energy physically.[57]
None of the interveners in the proceeding made submissions regarding the proposed exclusion of the Tumbler Ridge and Granisle service areas from the voluntary Low Carbon Energy program.
Panel Discussion
The Panel finds that PNG’s proposed disposition of Low Carbon Energy to customers of its Smart Energy program as the highest priority for its Low Carbon Energy program is reasonable. Prioritizing the available supply of Low Carbon Energy to customers who voluntarily sign up to acquire it from PNG reduces the potential cost of the Low Carbon Energy imposed on PNG’s customers who are not part of the Smart Energy program.
The Panel finds that it is appropriate for PNG to hold a portion of Low Carbon Energy supply equivalent to six months of winter demand from the Smart Energy program. PNG currently only has one primary supplier of Low Carbon Energy, and six months of winter demand gives PNG time to acquire more Low Carbon Energy from a short-term supply agreement if customer demand for the Smart Energy program is higher than anticipated.
The Panel accepts that PNG will not offer the Smart Energy program to its transportation customers because the Smart Energy service is a percentage blend of renewable natural gas with conventional natural gas, and PNG does not provide conventional natural gas service to these customers. PNG does, however, make Low Carbon Energy available to its transportation customers through off-system sales.
The Panel accepts that PNG will not offer the Smart Energy program to its customers in Granisle. The Smart Energy program is a blend of renewable natural gas and conventional natural gas, and PNG’s customers in Granisle receive propane rather than conventional natural gas.
The Panel does not accept PNG’s proposal to exclude its customers in Tumbler Ridge from the Smart Energy program for three reasons. First, PNG has an obligation to serve all customers who apply for service within its service area and within the limits of its capacity and must serve any customer who is willing and able to pay for the service[58], which includes its current customers in Tumbler Ridge. Second, pursuant to section 39 of the UCA, PNG must provide service “without undue discrimination or undue delay” and in the Panel’s view there is no reason why PNG’s customers in Tumbler Ridge should not be “reasonably entitled” to the Smart Energy service. Third, PNG’s stated goal is to “mitigate as much as possible, the impact of higher priced Low Carbon Energy on the costs borne by PNG’s customers.” Any additional demand from Smart Energy customers from Tumbler Ridge, however small, would potentially reduce the costs of the Low Carbon Energy imposed involuntarily on PNG’s customers who are not part of the Smart Energy program.
In the Panel’s view, the fact that Tumbler Ridge has no physical connection to PNG’s delivery point for the Low Carbon Energy at Westcoast Station 2 is not a reason to deny customers in Tumbler Ridge access to the Smart Energy service. As noted in Section 2.0 above, the Panel has found that renewable natural gas includes the combination of conventional natural gas and biomethane-related environmental attributes, which allows PNG to receive renewable natural gas notionally at Westcoast Station 2 and to deliver it notionally from Westcoast Station 2 to its customers. Since there is no requirement that either PNG or its Smart Energy customers receive any actual biomethane, as long as they receive conventional natural gas and biomethane-related environmental attributes they are deemed to have received renewable natural gas. As a result, PNG can deliver Low Carbon Energy notionally to its customers in Tumbler Ridge.
The Panel directs PNG to submit to the BCUC as a compliance filing within 30 days of the date of issuance of this Decision a rate schedule for providing Low Carbon Energy service to its Tumbler Ridge ratepayers.
The Panel further finds that PNG’s forecast demand from its residential and commercial customers for biomethane, the only fuel it anticipates selling in the Smart Energy program at present, is reasonable because it was based on PNG’s 2019 Customer Attitudes Survey.
3.2.2 PNG Company Use Gas
PNG proposes to deliver a portion of its Low Carbon Energy as Company Use Gas to supply to loads associated with its own operations. At this time, PNG is proposing to deliver Low Carbon Energy supply only to the metered portion of its Company Use Gas demand to ensure verifiable claims on emissions reductions associated with the supply of Low Carbon Energy. PNG estimates the applicable demand from its facilities in PNG-West, Fort St. John and Dawson Creek to be more than 100 terajoules per year.[59]
PNG states that the Low Carbon Energy supply utilized for its own facilities will reduce its direct GHG emissions.[60] PNG believes this is a cost effective and readily implementable alternative to electrification. PNG has not completed the calculation of the full cost of electrification but estimates the capital cost of electrifying one compressor at Station R1 to be in the range of $8 million. Moreover, PNG notes that in many cases electrification of its field equipment is simply not possible, owing to the lack of sufficient electric transmission system capacity.[61]
PNG believes allocating Low Carbon Energy supply to Company Use Gas will also minimize the rate impacts to sales customers, as Company Use Gas costs are recovered from transportation and sales customers.[62] RECAP customers, a subset of transportation customers who provide their own fuel gas in-kind, do not pay a Company Use Gas rider and therefore will not be subject to any increased costs arising from PNG’s use of Low Carbon Energy supply as Company Use Gas.[63]
PNG does not propose to allocate any Low Carbon Energy for Company Use Gas in the Tumbler Ridge service area.[64] PNG states that customers and facilities in the Tumbler Ridge service area receive their natural gas directly from a gas producer, and that there is no physical path available to supply Low Carbon Energy to PNG’s customers or facilities in Tumbler Ridge from the Low Carbon Energy delivery point under the Biomethane Purchase Agreements at Westcoast Station 2.[65]
PNG states that the Company Use Gas rate for Tumbler Ridge is based on Company Use Gas costs within the service territory and is recovered as a component of the delivery charge from sales and transportation service customers of Tumbler Ridge only, consistent with the recovery of Company Use Gas costs in PNG-West, Fort St. John, and Dawson Creek. [66]
PNG also proposes to exclude the village of Granisle, in the PNG-West service territory, from the allocation of Low Carbon Energy as Company Use Gas. Granisle customers are not connected to the PNG-West natural gas distribution system and instead receive propane service from PNG.[67] PNG states that Company Use Gas for Granisle is de minimis, and limited to line-heater usage and unaccounted for gas volumes. A separate Company Use Gas component does not exist in Granisle and as such, Company Use Gas costs are recovered in the commodity component of rates through the propane commodity cost rider.[68]
PNG suggests that it would be possible to notionally transfer the environmental attributes to Company Use Gas consumed in PNG’s facilities in Tumbler Ridge and Granisle, if the BCUC accepts that transferring deliveries to facilities not physically connected to Station 2 is consistent with definition of biomethane. PNG proposes to consider whether this exclusion remains appropriate as it considers various amalgamation and associated rate design scenarios.[69]
PNG proposes to prioritize supplying its own Company Use Gas demand ahead of entering into any off-system sales arrangements. However, PNG notes that RNG is not supplied to meet Company Use Gas demand under any contractual obligation. As such, a shortfall to the supply of Company Use Gas will simply result in PNG’s emission reductions being lower than their potential. [70]
PNG views the costs of Low Carbon Energy supply in excess of recoveries from the Smart Energy program as a required cost of continuing to carry on the business of delivering energy to all customers.[71] PNG acknowledges that the CleanBC GHG Reduction Standard, a greenhouse gas emissions cap for natural gas utilities stated as a goal of the CleanBC Roadmap to 2030, is not mandatory at this time.[72]
Positions of the Parties
PNG submits it intends to allocate a portion of its Low Carbon Energy supply to serve its own operational loads, but to limit this allocation to the metered portion of its own demand to “ensure verifiable claims on emissions reductions associated with the supply of [Low Carbon Energy].” PNG submits that the full cost of the Low Carbon Energy it consumes will be recovered through the Company Use Gas Cost Rate from all natural gas service customers in PNG-West, Fort St. John and Dawson Creek.[73]
BCSEA welcomes the use of biomethane for PNG’s own loads and accepts that limiting this use to metered loads is appropriate at this time. [74]
Panel Determination
The Panel finds that PNG’s use of Low Carbon Energy for is own metered use is reasonable because it reduces PNG’s GHG emissions, which is consistent with government policy to reduce GHG emissions in BC.
The Panel finds that allocations of Low Carbon Energy to PNG’s own use should be a lower priority than allocating Low Carbon Energy to voluntary Smart Energy customers, as PNG proposes, because this reduces the risk to the Smart Energy program of having insufficient inventory to meet the demand of voluntary, paying customers.
The Panel accepts PNG’s proposed disposition of Low Carbon Energy to Company Use Gas as a higher priority than off-system sales, but with reservations. PNG asserts that using Low Carbon Energy is “a cost effective and readily implementable solution”[75] to reducing its GHG emissions. However, PNG provides limited evidence that this is the case, and acknowledges that it “has not completed the calculation of the full cost” of electrification, an alternative solution. It is unknown, therefore, whether the use of Low Carbon Energy is more cost-effective than electrification for PNG to reduce its GHG emissions. If electrification were more cost-effective than using Low Carbon Energy, it could be in ratepayers’ interests for PNG to sell the Low Carbon Energy to off-system counterparties rather than use it as Company Use Gas.
The Panel directs PNG to include the following in its review of the Low Carbon Energy program, addressed in Section 6.0 below:
• a more comprehensive analysis of the relative costs of using Low Carbon Energy versus electrification to decarbonize its gas distribution system; and
• an analysis of the relative benefits to ratepayers of using Low Carbon Energy for Company Use Gas versus selling the Low Carbon Energy to off-system counterparties.
The Panel accepts PNG’s proposed exclusion of its customers in Granisle from the additional costs associated with using Low Carbon Energy for Company Use Gas because these customers do not have a separate Company Use Gas component to their rate and their use of company gas is minimal.
The Panel does not accept that PNG’s customers in Tumbler Ridge should be excluded from the additional costs associated with using Low Carbon Energy for Company Use Gas. In the Panel’s view, PNG’s customers in Tumbler Ridge should bear some portion of PNG’s cost to decarbonize its distribution system, and the assignment of 100 percent of the Low Carbon Energy used as Company Use Gas to PNG’s natural gas customers other than those in Tumbler Ridge is unduly discriminatory. PNG itself acknowledges that the costs of Low Carbon Energy supply in excess of recoveries from the Smart Energy program are “a required cost of continuing to carry on the business of delivering energy to all customers,” and the Panel sees no adequate reason that customers in Tumbler Ridge, to whom PNG delivers energy, should be excluded from such costs.
PNG states it does not propose to allocate any Low Carbon Energy for Company Use Gas to its customers in the Tumbler Ridge service area because those customers receive their natural gas directly from a gas producer, and that there is no physical path available to supply Low Carbon Energy to PNG’s customers or facilities in Tumbler Ridge from the Low Carbon Energy delivery point under the Biomethane Purchase Agreements at Westcoast Station 2.[76] The Panel does not find these reasons to be compelling. PNG’s customers in Tumbler Ridge are charged for Company Use gas at present, notwithstanding the source of the natural gas they receive. In addition, as the Panel found in section 3.2.1 above, the lack of a physical connection from the delivery point of the Low Carbon Energy that PNG is acquiring to PNG’s customers in Tumbler Ridge is not a satisfactory reason for excluding them from the Smart Energy program.
The Panel directs PNG to allocate Low Carbon Energy to Company Use Gas for Tumbler Ridge ratepayers on the same basis that it allocates Low Carbon Energy to Company Use Gas for all other ratepayers.
PNG is further directed to make a compliance filing within 30 days of the date of the issuance of this Decision explaining how it will allocate Low Carbon Energy to Company Use Gas for its Tumbler Ridge ratepayers.
3.2.3 Off-System Sales
PNG proposes to sell Low Carbon Energy supply which is not necessary to meet demand of the Smart Energy program or Company Use Gas to off-system counterparties, including PNG customers receiving transportation service or their gas marketers. PNG states this is consistent with PNG’s current practice of off-system sales of conventional natural gas when firm contracted quantities of natural gas are in excess of PNG’s requirements. PNG intends to facilitate these off-system sales on a monthly, quarterly or annual basis depending on the quantities available.[77]
PNG proposes to prioritize off-system sales before allocating the remaining quantities to PNG customers.[78] PNG states that the Low Carbon Energy cost recovery mechanism is structured in a way where any off-system sales at prices exceeding that of the natural gas commodity cost rate in effect at the time will generate revenues that reduce the costs recovered from all customers through the Low Cardon Energy Cost Recovery Rider.[79] PNG believes this will help mitigate the short-term rate impacts to PNG customers from securing long term Low Carbon Energy supply commitments.
PNG intends to limit off-system sales of biomethane to contracts with a two-year term or less, giving PNG the flexibility to deploy those supplies to its own customers on short notice should it become necessary under the GHG Reduction Standard, contemplated in the CleanBC Roadmap to 2030.[80] PNG further notes that it will include provisions in the GasEDI contracts entered with third parties to constrain the sales of biomethane and the related environmental attributes to counterparties consuming the biomethane in BC, to ensure consistency with section 18(1) of the CEA and sections 2(3.7) and 2(3.8) of the GGRR.[81]
PNG states that it will provide qualified purchasers with the biomethane tax credit for Low Carbon Energy purchased through off-system sales. PNG defines a qualified purchaser as a purchaser who consumes the blend of natural gas and biomethane, delivered pursuant to the terms of a biomethane contract, and who is required under the Carbon Tax Act to pay the Carbon Tax in respect of quantities of biomethane purchased. PNG does not believe it is able to provide the biomethane credit to third parties who are wholesale or retail dealers.[82]
Positions of the Parties
PNG submits that it will attempt to sell any Low Carbon Energy supply that is not required to meet the demand from Smart Energy customers and from PNG’s own use to off-system counterparties including customers receiving transportation service or their gas marketers.[83]
PNG submits that the terms of its off-system sales of RNG are not directly subject to BCUC review because section 71 of the UCA “does not impose any limitations, restrictions or terms on off-system natural gas sales that are made to a non-public utility.” However, PNG adds that the BCUC will still have insight because it proposes to report its off-system sales of RNG to the BCUC as part of its annual reporting.[84]
BCSEA submits that, pursuant to section 71 of the UCA, there are no legal limitations on sales of RNG by PNG to entities that are not public utilities. BCSEA further submits that the BCUC can be satisfied that it will have adequate insight into any off-system sales of RNG by PNG under its proposed Low Carbon Energy cost recovery mechanism because PNG has committed to providing the details of such off-system sales to the BCUC and has committed to requiring purchasers of its RNG to consume the RNG within BC. [85]
RCIA submits that off-system sales of renewable natural gas should be treated in the same way as similar sales of conventional natural gas as they pertain to section 71 (1.1) of the UCA.[86]
Panel Determination
The Panel finds that off-system sales of Low Carbon Energy are reasonable if PNG recovers an amount at least equivalent to the cost of the same quantity of conventional natural gas. In the absence of off-system sales, any surplus Low Carbon Energy not used by customers of the Smart Energy program or by PNG for Company Use Gas would be used by PNG’s customers in place of conventional natural gas, as described in Section 3.2.4 below. If PNG were to make off-system sales at a price lower than the cost of conventional natural gas, PNG’s other customers would have been better off without the off-system sale being made and using the Low Carbon Energy themselves.
The Panel agrees that the BCUC has jurisdiction to review under section 71 of the UCA only those sales of natural gas that are to entities that are public utilities. However, pursuant to sections 61 and 63 of the UCA, PNG may not provide a regulated service without a rate schedule. Thus, the BCUC has jurisdiction over all of PNG’s sales of Low Carbon Energy, either under section 71 if the sale is to a public utility, and under sections 61 and 63 otherwise.
The Panel directs PNG to file a rate schedule for off-system sales of Low Carbon Energy for review and approval by the BCUC if it wishes to sell Low Carbon Energy to parties that are not public utilities.
In addition, the Panel recommends that the BCUC monitor PNG’s off-system sales of Low Carbon Energy to ensure that its program is being well-managed and directs PNG to include details of all off-system sales of Low Carbon Energy in its annual report.
3.2.4 Allocation to PNG Customers
PNG proposes to transfer any remaining Low Carbon Energy supply after sales to voluntary customers, allocation to Company Use Gas, and sales to off-system counterparties to PNG’s natural gas supply portfolio through the Gas Cost Variance Account at the commodity rate in effect at the time.[87]
Positions of the Parties
BCSEA supports the four components of PNG’s proposed Low Carbon Energy Cost Recovery Mechanism, including the transfer of remaining low carbon energy supply to the Gas Cost Variance Account at the commodity rate in effect at the time.[88]
RCIA also supports the disposition methodologies proposed by PNG, including the allocation of costs to all PNG customers as described in Section 7 of the Application.[89]
Panel Discussion
The Panel finds that allocating any surplus Low Carbon Energy remaining in the Low Carbon Energy Cost Variance Account to PNG’s customers via the Gas Cost Variance Account, as proposed by PNG, is reasonable.
Pursuant to section 18 of the CEA, the BCUC must allow PNG to recover the cost of any Low Carbon Energy it acquires as a prescribed undertaking as defined in the GGRR. Unless allocated elsewhere, surplus volumes of Low Carbon Energy would remain in the Low Carbon Energy Cost Variance Account, and the full cost of the surplus Low Carbon Energy would be recovered from PNG’s customers including its transportation customers via the Low Carbon Energy Cost Recovery Rider.
By allocating the surplus Low Carbon Energy to the Gas Cost Variance Account, as PNG proposes, the only remaining balance in the Low Carbon Energy Cost Variance Account is the cost of the Low Carbon Energy in excess of the natural gas commodity rate in effect at the time. As a result, when this excess is recovered via the Low Carbon Energy Cost Recovery Rider, PNG’s transportation customers do not incur the cost of any conventional natural gas embedded in the total cost of the surplus Low Carbon Energy, which is appropriate because transportation customers do not take natural gas service from PNG.
The allocation of costs to the Gas Cost Variance Account is addressed in Section 4.5 below.
4.0 Low Carbon Energy Program Cost Recovery
This section of the Decision addresses how PNG proposes to recover the cost of the Low Carbon Energy supply that it has acquired and disposed of in the manner described in Section 3.0 above.
Under PNG’s proposal, all costs of the Low Carbon Energy program will be captured in the Low Carbon Energy Cost Variance Account.[90] The Low Carbon Energy Cost Variance Account balance will be recovered through the Low Carbon Commodity Charge collected from customers of the Smart Energy program, transfers of Low Carbon Energy used for Company Use Gas to PNG’s Company Use Gas Account, off-system sales, and transfers of unsold gas to PNG’s Gas Cost Variance Account (Gas Cost Variance Account). Any unrecovered balances in the Low Carbon Energy Cost Variance Account will be recovered through a Low Carbon Energy cost recovery rider (Low Carbon Energy Cost Recovery Rider) added to the delivery charge of non-bypass customers.[91]
PNG illustrates how the Low Carbon Energy Cost Variance Account is used to recover Low Carbon Energy costs in figure 1 below:[92]
Figure 1: Illustration of the Low Carbon Energy Cost Variance Account
The elements of the Low Carbon Energy cost recovery mechanism are addressed as follows:
• The Low Carbon Energy Cost Variance account, including the costs proposed to be captured (Section 4.1 of this Decision);
• The Low Carbon Commodity Charge, which recovers the costs of the Low Carbon Energy program from voluntary Smart Energy customers (Section 4.2);
• Transfer of Low Carbon Energy costs from the Low Carbon Energy Cost Variance account to the Company Use Gas Account (Section 4.3);
• Off-system sales of Low Carbon Energy (Section 4.4);
• Transfers of Low Carbon Energy costs from the Low Carbon Energy Cost Variance account to the Gas Cost Variance Account (Section 4.5); and
• The Low Carbon Energy Cost Recovery Rider, which recovers any unrecovered costs in the Low Carbon Energy Cost Variance account (Section 4.6).
4.1 Low Carbon Energy Cost Variance Account
PNG proposes to capture all Low Carbon Energy program related costs in the Low Carbon Energy Cost Variance Account. These costs include:[93]
1. Commodity costs of Low Carbon Energy supply acquired, including delivery of the Low Carbon Energy supply acquired to the PNG system;
2. Costs for configuration of the customer information system;
3. Transactional expenses related to the provision of performance assurance that may be required under the terms of a biomethane purchase agreement;
4. Administrative expenses, including those related to management of the Low Carbon Energy portfolio, administration of the Smart Energy program, reporting, and billing adjustments and rate changes; and
5. Marketing expenses, including a proposed incentive program.
Any variances between the Low Carbon Energy program costs and the recoveries will be retained in the Low Carbon Energy Cost Variance Account.[94] PNG states it will apply for the Low Carbon Energy program costs and any variances in the previous test period in its revenue requirement application which would be subject to review by the BCUC and interveners to determine whether the costs were prudently incurred and in the public interest.[95] PNG acknowledges a potential timing difference between when the Low Carbon Energy program costs are incurred and when they will be reviewed in a revenue requirement application, given that revenue requirements are often approved on a multi-year basis. [96] PNG does not believe there will be a material impact to PNG or its ratepayers as a result of these timing differences given that the forecast implementation and marketing costs are relatively modest.[97]
PNG proposes the Low Carbon Energy Cost Variance Account to be a non-rate base interest-bearing deferral account with carrying costs based on PNG’s short term interest rate to both debit and credit balances held in the Low Carbon Energy Cost Variance Account, consistent with the treatment for the Gas Cost Variance Account.[98]
Positions of the Parties
RCIA does not oppose the Low Carbon Energy Cost Variance Account, and submits it is “within PNG’s right to collect all costs associated with [Low Carbon Energy] (under GGRR rules).”[99]
BCSEA supports approval of the cost recovery related orders requested by PNG, which include establishment of the Low Carbon Energy Cost Variance Account.[100]
Panel Determination
The Panel approves PNG to create the Low Carbon Energy Cost Variance Account, a non-rate base regulatory account bearing interest at PNG’s short term interest rate applied to both debit and credit balances.
As noted above, pursuant to section 18 (2) of the CEA the BCUC must allow PNG to collect the cost of acquiring RNG, and the Low Carbon Energy Cost Variance Account is an appropriate regulatory mechanism for those costs to be recovered.
In the following Sections 4.1.1 through 4.6 the Panel determines the costs and revenues that PNG may record in the Low Carbon Energy Cost Variance Account.
4.1.1 Commodity Costs
PNG proposes to record the cost and quantity of Low Carbon Energy supply received each month in the Low Carbon Energy Cost Variance Account.[101]
PNG notes that at this time, it has not identified any opportunities for the ownership of biomethane or hydrogen production facilities, and consequently is not proposing in the Application a mechanism for recovering the cost of “service associated with PNG-owned facilities that produce, process or distribute biogas, biomethane or hydrogen.” However, should PNG identify such an opportunity in the future, PNG anticipates that it would file an application at that time to address the acquisition of Low Carbon Energy and accounting treatment of the associated costs.[102]
Panel Determination
The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the cost of Low Carbon Energy acquired as prescribed undertakings as defined in section 2(3.8) of the GGRR.
Pursuant to section 18 (2) of the CEA the BCUC must allow PNG to collect the cost of acquiring RNG, and the Low Carbon Energy Cost Variance Account is an appropriate regulatory mechanism for those costs to be recovered.
As noted in Section 2.0 above, the Panel’s definition of Low Carbon Energy is synonymous with renewable natural gas. As a result, the Panel does not approve the recording in the Low Carbon Energy Cost Variance Account of costs associated with acquisition of any form of energy other than renewable natural gas, even if such energy was acquired as a prescribed undertaking as defined in the GGRR. The cost of other forms of energy, such as hydrogen, is likely to be significantly different to the cost of RNG and therefore the cost recovery mechanism approved in the decision may not be appropriate. As PNG notes, it should apply to the BCUC for a recovery mechanism for other forms of energy whose costs it wishes to record in the Low Carbon Energy Cost Variance Account.
4.1.2 Configuration of the Customer Information System
PNG states its customer information system will need to be configured to support PNG’s Low Carbon Energy cost recovery mechanism, including the voluntary Smart Energy program and Low Carbon Energy Cost Recovery Rider. PNG estimates a one-time expense of $75,000 will be required to implement and configure these changes. PNG intends to amortize the configuration costs through the Low Carbon Energy Cost Variance Account over the remaining life of the customer information system software, which is being depreciated over a total of ten years.[103]
Panel Determination
The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the cost of configuring its customer information to a maximum cost of $75,000 amortized equally over 10 years.
Pursuant to section 18 (3) of the CEA the BCUC must not exercise a power that would directly or indirectly prevent PNG from carrying out a prescribed undertaking. The acquisition of RNG is a prescribed undertaking, and PNG must configure its customer information system to collect the Low Carbon Commodity Charge and the Low Carbon Energy Cost Recovery Rider to recover the costs incurred with respect to the acquisition of the RNG.
4.1.3 Transactional Expenses
PNG proposes to record in the Low Carbon Energy Cost Variance Account any costs associated with the provision of performance assurances that may be required under the terms of a biomethane purchase agreement. PNG does not anticipate that it will incur any such expenses for the Biomethane Purchase Agreements which it has entered into with ATCO RNG and Tidal RNG, and therefore has not included any anticipated transactional expenses in the Application. Typical costs could include carrying charges associated with a Letter of Credit or a parental guarantee from TriSummit Utilities Inc. that may be requested by a seller under the terms of a biomethane purchase agreement.[104]
Panel Determination
The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the costs associated with performance assurances that may be required as a result of acquiring RNG as a prescribed undertaking pursuant to the GGRR.
Pursuant to section 18 (2) of the CEA the BCUC must allow PNG to collect the cost of acquiring RNG, which the Panel finds includes the costs associated with performance assurances in acquiring RNG. While PNG does not anticipate any such costs at present, PNG has applied for approval of its proposed cost recovery mechanism.
4.1.4 Administration Expenses
PNG proposes to record in the Low Carbon Energy Cost Variance Account any incremental administration costs associated with managing the supply of the Low Carbon Energy portfolio, administering the Smart Energy program, and monitoring and reporting on the performance of the Low Carbon Energy portfolio.[105]
For ongoing management of Low Carbon Energy supply, PNG estimates an annual cost of $20,000 per annum, based on 0.1 of a full-time equivalent person’s effort.[106] For administration of the Smart Energy program, PNG estimates an annual cost of $1,500 to $2,000 per annum.[107] For the monitoring and reporting of the Low Carbon Energy portfolio performance, PNG estimates an annual cost of $8,000 per annum based on 0.4 of a full-time equivalent person’s effort.[108]
PNG anticipates that its current staffing levels are adequate to manage the additional administrative tasks and, in consideration of the nominal amounts, proposes to not record these costs in the Low Carbon Energy Cost Variance Account.[109]
If Low Carbon Energy is injected locally into its gas distribution system, PNG anticipates new heat content zones may need to be configured and adjustments to customer bills may be required. At this time, PNG has not identified a source of Low Carbon Energy that will be injected in its local gas distribution system. As such, no associated administrative costs have been estimated and included in the Low Carbon Energy Cost Variance Account. In the event that an opportunity for PNG to acquire on-system Low Carbon Energy supply becomes available, PNG will provide an updated cost estimate associated with administering the Low Carbon Energy program as part of an application to the BCUC seeking approval for the acquisition of the related supply.[110]
Positions of the Parties
RCIA submits that PNG’s administrative costs “seem reasonable.”[111]
BCSEA supports approval of the cost recovery related orders requested by PNG, which include approval of PNG’s proposed allocation of costs to all customers and accounting treatment of those costs.[112] BCSEA makes no submission specific to administration costs.
Panel Determination
The Panel directs PNG to record in the Low Carbon Energy Cost Variance Account any incremental administration costs associated with managing the supply of the Low Carbon Energy portfolio, administering the Smart Energy program, and monitoring and reporting on the performance of the Low Carbon Energy portfolio.
The Panel disagrees with PNG that the administrative costs identified should not be recorded in the Low Carbon Energy Cost Variance Account just because they appear to be nominal. Allocating PNG’s administrative costs properly between its Low Carbon Energy program and its other regulated services better supports rate setting for each of PNG’s service consistent with the cost causation principle. Further, this allocation supports the “full transparency to the cost of [Low Carbon Energy]” that PNG itself supports.[113]
4.1.5 Marketing Expenses
PNG intends to undertake a branding and marketing campaign, designed to raise awareness of and promote the voluntary Smart Energy program amongst its customers. PNG provided a cost forecast based on estimates received for a social media campaign, with additional budget to support a broader range of advertising media and outreach. PNG proposes to record these costs in the Low Carbon Energy Cost Variance Account.[114]
A summary of PNG’s proposed marketing budget for the Smart Energy program is shown in the following table:[115]
Table 2: Summary of Proposed Marketing Budget for the Smart Energy Program
PNG submits that the cost of raising awareness and educating all customers about its Smart Energy program, about Low Carbon Energy and about PNG’s commitment to supporting the Province’s GHG reduction policies and goals, and specifically the CleanBC Roadmap to 2030 is appropriately borne by all customers.[116] PNG anticipates that marketing and incentives are crucial to raising awareness of, and interest in, PNG’s Smart Energy program. Absent a marketing campaign, PNG does not expect significant participation in the Smart Energy program.[117]
PNG forecasts a potential demand of 4,000 to 11,000 gigajoules per year from voluntary residential and commercial customers depending on the blend offered.[118]
Included in the marketing budget is a forecast for incentive costs. PNG proposes to provide incentives to customers who elect to receive Low Carbon Energy blending rates of greater than two percent of their natural gas supply.[119] PNG states that these incentives will be prizes provided to either randomly selected, or to the first tranche of participants in the Smart Energy program, in each of the first years of the program.[120]
PNG states the purpose of the incentives is to raise awareness of the Smart Energy program and drive participation at blending rates greater than two percent, thereby promoting more rapid growth in demand and revenue. PNG acknowledges that the incentive to participants in the Smart Energy program is a benefit to PNG’s other customers only if the incremental recoveries from the Smart Energy program are greater than the costs of the incentives. PNG proposes to carefully consider the nature and magnitude of the individual incentives it may offer and monitor their efficacy and benefit to all of PNG’s customers.[121]
Panel Determination
The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account actual marketing expenses associated with the Smart Energy program to the following limits:
• Up to $95,000 in 2024;
• Up to $95,000 in 2025; and
• Up to $60,000 in 2026.
The Panel addresses PNG’s marketing expenses for the years 2022 and 2023 in the following Section 4.1.6.
The Panel finds that PNG’s marketing expenses are reasonable because they encourage customer participation in the voluntary Smart Energy program, which in turn reduces the Low Carbon Energy costs imposed on the involuntary PNG customers. The Panel considers that the magnitude of the marketing expenses is reasonable for the size of the market PNG is seeking to develop.
The Panel is concerned that PNG’s proposed spending on incentives might be unduly discriminatory pursuant to section 39 or 59 of the UCA because PNG plans to offer incentives only to those Smart Energy customers who take specific blends of Low Carbon Energy. The Panel also notes that incentives, like all marketing costs, are only beneficial if they reduce the recoveries from all PNG’s customers by more than their cost.
PNG provides no specifics as to the incentives it will offer. Therefore, the Panel directs PNG to report annually starting in 2022 its expenditure on Smart Energy program incentives, providing details of the nature and recipients of the incentives and why the incentives were not unduly discriminatory. PNG’s annual reporting on the Low Carbon Energy program is discussed in more detail in section 5.
4.1.6 Amortization of Non-Recurring Expenses
PNG expects to incur $60,000 of non-recurring expenses related to marketing of the Smart Energy program in 2022, with an additional $130,000 of forecast marketing costs in 2022 to execute the marketing campaign. The two Biomethane Purchase Agreements which PNG has entered into provide only a small quantity of Low Carbon Energy supply beginning in 2022, which increases each year until 2024. Based on the proposed Low Carbon Commodity Rate rate-setting mechanism, recovery of the non-reoccurring implementation and marketing costs in the year they are incurred would result in a high Low Carbon Commodity Charge rate in 2022.[122]
PNG proposes to amortize implementation and marketing costs incurred in 2022 and 2023 over the period of 2022 to 2025, to reduce the 2022 Low Carbon Commodity Charge to the long term average Low Carbon Commodity Charge which it believes would remove barriers to participation by Smart Energy customers and spread the implementation and marketing costs over a larger number of voluntary customers in later years of the program.[123] PNG does not believe that the deferral of implementation and marketing costs would result in intergenerational inequalities as the marketing materials are expected to be reused to support future marketing initiatives without incurring significant development costs.[124]
PNG proposes to record the implementation and marketing costs incurred in 2022 and 2023 in a non-rate base interest-bearing deferral account and amortize the amount into the Low Carbon Energy Cost Variance Account over the period 2022 to 2025.[125]
Panel Determination
The Panel approves the creation of a Smart Energy Marketing Cost Deferral Account, a non-rate base regulatory account bearing interest at PNG’s short term interest rate applied to both debit and credit balances.
The Panel approves PNG to record in the Smart Energy Marketing Cost Deferral Account actual marketing expenses associated with the Smart Energy program up to a limit of $285,000 between 2022 and 2023. Although PNG has requested $190,000 in 2022 and $95,000 in 2023, PNG may not have sufficient time remaining in 2022 subsequent to the issuance of this decision to implement its planned marketing activities. Therefore, the Panel approves the combined amounts for 2022 and 2023 to be spent by the end of 2023.
The Panel approves PNG to amortize the balance in the Smart Energy Marketing Cost Deferral Account into the Low Carbon Energy Cost Variance Account over the years from 2022 to 2025 inclusive such that the Low Carbon Commodity Cost remains close to its long-term average. The Panel directs PNG to report annually the activity and closing balance of the Smart Energy Marketing Cost Deferral Account. PNG’s annual reporting on the Low Carbon Energy program is discussed in more detail in section 5.
The Panel finds that the marketing expenses in 2022 and 2023 are reasonable for the same reasons set out in Section 4.1.5 above. The Panel further finds it reasonable to amortize the marketing expenses in 2022 and 2023 over the period 2022 to 2025 because this approach better matches the timing of the expenditures to the period in which customers would be expected to sign up to the Smart Energy program as a result.
4.2 Low Carbon Commodity Charge
PNG seeks the BCUC’s approval for its proposed Low Carbon Commodity Charge rate setting mechanism as well as a Low Carbon Commodity Charge rate of $27.50 per gigajoule [126]
PNG states the Low Carbon Commodity Charge rate is intended to reflect the forecast full cost of providing Low Carbon Energy supply, including the costs to implement and market the Low Carbon Energy portfolio. The Low Carbon Commodity Charge is applicable to the blend of biomethane sold to voluntary customers through the Smart Energy program as well as the cost of Low Carbon Energy supply used for PNG’s own Company Use Gas.
PNG states that its primary criterion informing the design of the Smart Energy program is to maximize program revenues.[127] However, PNG has no data on the price-elasticity of demand for biomethane in order to determine the optimal Low Carbon Commodity Charge rate to maximize revenues from the Smart Energy program.[128] PNG submits that it is unclear whether decreasing the Low Carbon Commodity Charge rate below that set for full cost recovery would result in an increase to program revenues, and setting the Low Carbon Commodity Charge for full cost recovery will eliminate additional costs associated with deliveries under the Smart Energy program that would need to be recovered from all ratepayers.[129]
PNG further submits that full recovery of Low Carbon Energy costs through the voluntary Low Carbon Commodity Charge rate is consistent with results of its 2019 customer attitudes survey.[130] In the survey, PNG notes that over three quarters of residential and commercial respondents did not oppose the proposition that “customers who want biomethane should pay more for it,” and less than fifteen percent of respondents agreed that all ratepayers should bear the incremental cost of developing sources of biomethane.[131]
PNG proposes to align the Low Carbon Commodity Charge rate-setting mechanisms with the existing natural gas rate setting processes, where the Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting to the BCUC.[132]
PNG submits that it is not averse to establishing additional triggers for the adjustment of the Low Carbon Commodity Charge that would be assessed during the quarterly review of the Low Carbon Energy portfolio. However, it is against quarterly adjustments of the Low Carbon Commodity Charge in order to provide some consistency in price signals to voluntary Smart Energy participants and avoid increasing administrative burden.[133]
Position of the Parties
PNG submits its proposed rates and rate schedules are just and reasonable and should be approved.[134] PNG further submits that its proposed cost recovery mechanism reduces, as much as possible, the impact on all its customers. [135]
PNG submits it intends to set the price for biomethane sold through the Smart Energy program based on “the full recovery of the cost of acquiring and delivering biomethane that includes not only the cost of biomethane supply but also the cost associated with offering the Smart Energy program.”[136]
BCSEA submits that the Smart Energy program, with voluntary purchase at full cost recovery, is appropriate and consistent with customer survey results indicating a preference that “customers who want biomethane should pay more for it.” BCSEA accepts PNG’s explanation of why the price of biomethane under the Smart Energy program is based on full cost recovery rather than revenue maximization or minimization of cross subsidy.[137]
BCSEA submits that quarterly adjustments to the Low Carbon Commodity Charge could “diminish the consistency of the price signal received by participants” of the Smart Energy program.[138]
RCIA submits it is reasonable for PNG to establish separate rate schedules for Low Carbon Energy “such that the service may be offered to customers that choose to participate” and supports the rate orders requested by PNG.[139] RCIA does not oppose the Low Carbon Commodity Charge being set at $27.50 per gigajoule because this level is “a reasonable proxy for the LCE [Low Carbon Energy] procurement cost, and of course, because it is compliant with the GGRR guidelines (i.e., lower than the cap price).”[140]
RCIA adds that if the Low Carbon Commodity Charge is “materially influenced by costs relating to procurement of other forms of renewable gas, such as hydrogen, synthetic gas, or lignin, RCIA believes a more substantive hearing will be warranted.”[141]
PNG submits in reply that additional sources of Low Carbon Energy supply acquired by PNG will be subject to BCUC acceptance pursuant to section 71 of the UCA and that this is the appropriate forum for discussing the impact on the Low Carbon Commodity Charge and adjusting it if necessary.[142]
RCIA further submits that there is no obvious cross subsidization of voluntary Smart Energy program participants by non-participants.[143]
Panel Determination
The Panel approves PNG to charge a Low Carbon Commodity Charge of $27.50 per gigajoule and directs PNG to record the revenues received from the Low Carbon Commodity Charge in the Low Carbon Energy Cost Variance Account.
The Panel has reviewed the evidence, including the confidential evidence on PNG’s cost of acquiring Low Carbon Energy, and finds that the rate of $27.50 per gigajoule is a reasonable forecast of the full cost of PNG’s Low Carbon Energy including administration and marketing costs in 2022.
The Panel agrees with PNG that maximizing revenues from the Smart Energy program would minimize the cross-subsidy paid by PNG’s customers, but that there is insufficient evidence available to determine the rate that would achieve this. The Panel directs PNG to provide in its review of the Low Carbon Energy program information that would enable the BCUC to evaluate whether a different Low Carbon Commodity Charge rate would better maximize revenues from the Smart Energy program.
The Panel addresses the matter of differences between forecast and actual Low Carbon Energy costs in Section 4.6 below.
The Panel approves PNG to use an adjustment mechanism for the Low Carbon Commodity Charge, whereby the Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting to the BCUC. There is no evidence that more frequent reviews of the Low Carbon Commodity Charge are required.
4.3 Transfer of Costs to the Company Use Gas Account
For the Low Carbon Energy supply used in its metered portion of Company Use Gas demand, PNG proposes to transfer the associated costs to the Company Use Gas Account at the Low Carbon Commodity Charge rate to be recovered through the existing Company Use Gas Rider from natural gas service customers.[144] PNG clarifies that RECAP customers, a subset of transportation customers, do not pay the Company Use Gas Rider as they provide their own Company Use Gas in kind.[145]
Panel Determination
The Panel approves PNG to transfer the cost of Low Carbon Energy allocated to Company Use Gas from the Low Carbon Energy Cost Variance Account to the Company Use Gas Account.
The Panel has found in Section 3.2.2 that Company Use Gas is a reasonable use of Low Carbon Energy and therefore the transfer of Low Carbon Energy from the Low Carbon Energy Cost Variance Account to the Company Use Gas Account is appropriate.
The Panel accepts that the Low Carbon Energy transferred from the Low Carbon Energy Cost Variance Account to the Company Use Gas Account will be valued at the Low Carbon Commodity Charge (i.e. the full cost of the Low Carbon Energy). However, the Panel expressed reservations in Section 3.2.2 that PNG has not adequately justified the use of Low Carbon Energy as the most cost-effective way to reduce its GHG emissions. When the BCUC reviews PNG’s Low Carbon Energy program, as set out in Section 6.0 below, the Panel recommends that the BCUC consider whether the valuation at the Low Carbon Commodity Charge is justified.
The Panel in Section 3.2.2 above has directed PNG to allocate Low Carbon Energy to Company Use Gas for its customers in Tumbler Ridge. PNG is further directed to ensure that the costs transferred from the Low Carbon Energy Cost Variance Account to the Company Use Gas Account are transferred consistently with the Panel’s direction in Section 3.2.2 above, and to explain to the BCUC in a compliance filing within 30 days of the date of issuance of this Decision how the costs from the Low Carbon Energy Cost Variance Account will be allocated to the Company Use Gas Account for each of PNG’s service areas.
4.4 Off-system Sales
PNG proposes to sell excess Low Carbon Energy that is not required to meet the demand from voluntary customers and from Company Use Gas, to off-system counterparties including customers receiving transportation service or their gas marketers.[146]
PNG believes that, consistent with conventional natural gas, terms of off-system sales of Low Carbon Energy, including price and volume, are exempt from the BCUC’s review pursuant to section 71 of the UCA. PNG intends to structure its agreements for off-system sales pursuant to a GasEDI with the specific terms on price and quantity being set out in related transaction confirmations. PNG notes that the BCUC will still have insight into the terms of off-system sales, as PNG has proposed to report terms its off-system RNG sales, including price and volume, to the BCUC as part of its annual reporting.[147]
Panel Determination
The Panel approves PNG to record in the Low Carbon Energy Cost Variance Account the revenues received from its off-system sales of Low Carbon Energy.
4.5 Transfer to Gas Cost Variance Account
PNG proposes to transfer the remaining Low Carbon Energy supply to its Gas Cost Variance Account at the natural gas commodity rate in effect at the time of the transfer to be recovered through the existing Gas Cost Variance Account rate rider from all non-bypass customers. Costs related to the premium of the Low Carbon Energy over natural gas will remain in the Low Carbon Energy Cost Variance Account and will be recovered from all non-bypass customers through a rider on the delivery charge.[148] PNG expects to transfer the excess quantities of Low Carbon Energy into the Gas Cost Variance Account on a basis no less frequently than PNG’s quarterly review of its gas commodity rates.[149]
PNG states the use of the natural gas commodity rate reduces the administrative burden associated with developing and administering a second pricing method as gas commodity rates are reviewed quarterly and adjusted based on established and well-defined criteria that includes an examination of forward gas prices and projected revenues received through existing rates. The gas commodity rate therefore reflects the weighted average cost of PNG’s gas supply portfolio. PNG submits that this is the most appropriate price at which to transfer Low Carbon Energy supply into the Gas Cost Variance Account.[150]
Panel Determination
The Panel approves PNG to transfer the cost of Low Carbon Energy allocated to its customers from the Low Carbon Energy Cost Variance Account to the Gas Cost Variance Account at the natural gas commodity rate in effect at the time of the transfer.
The Panel has found in Section 3.2.4 that it is reasonable for PNG to allocate any surplus Low Carbon Energy remaining in the Low Carbon Energy Cost Variance Account to PNG’s customers via the Gas Cost Variance Account.
4.6 Low Carbon Energy Cost Recovery Rider
PNG seeks the BCUC’s approval for its proposed Low Carbon Energy Cost Recovery Rider rate setting mechanism.[151] Additionally, PNG proposes that the initial Low Carbon Energy Cost Recovery Rider be set at $0.00 per gigajoule.[152]
PNG states the Low Carbon Energy Cost Recovery Rider is intended to recover the difference between the cost of the Low Carbon Energy supply including all associated implementation, administrative and marketing costs, and the cost recovered from the sale of Low Carbon Energy to voluntary customers in the Smart Energy program, from transfers to the Company Use Gas Account, from sales to off-system counterparties, and from transfers to the Gas Cost Variance Account. The Low Carbon Energy Cost Recovery Rider applies to the delivery rate and is recovered from all of PNG’s non-bypass sales and transportation customers, excluding those in the service areas of Granisle and Tumbler Ridge.[153]
PNG views the costs of Low Carbon Energy supply in excess of recoveries from the Smart Energy program as a required cost of continuing to carry on the business of delivering energy to all customers, despite the fact that the GHG Reduction Standard is not mandatory at this time.[154] Based on this, PNG believes the costs of Low Carbon Energy supply in excess of recoveries are to be recovered in a similar manner as all other operating costs though a delivery charge.[155]
PNG states Smart Energy program participants are also subject to the Low Carbon Energy Cost Recovery Rider that recovers additional costs related to the provision of Low Carbon Energy supply. In this regard, Smart Energy participants are treated identically to all other sales customers who are subject to charges and riders that recover the cost of acquiring and delivering natural gas and result in the cost for the natural gas commodity that is different and often times higher than the market price paid by PNG. PNG also notes that it would be administratively complicated to adjust the Low Carbon Energy Cost Recovery Rider based on the percentage blend chosen by a customer taking Low Carbon Energy supply.[156]
PNG proposes to exclude the Granisle and Tumbler Ridge service areas from Low Carbon Energy cost recovery through the Low Carbon Energy Cost Recovery Rider.[157] PNG states that customers and facilities in the Tumbler Ridge service area receive their natural gas directly from a gas producer, and that there is no physical path available to supply Low Carbon Energy to PNG’s customers or facilities in Tumbler Ridge from the Low Carbon Energy delivery point under the Biomethane Purchase Agreements at Westcoast Station 2.[158] Customers located in the village of Granisle in the PNG-West service territory are not connected to the PNG-West natural gas distribution system, and instead receive propane service from PNG.[159]
PNG believes this exclusion is appropriate under its proposed rate structure, where Granisle and Tumbler Ridge customers are excluded from participation in the Smart Energy program, but submits that it will consider whether this exclusion remains appropriate as it considers various amalgamation and rate design scenarios.[160]
PNG submits that including Granisle and Tumbler Ridge customers in the Low Carbon Energy Cost Recovery Rider would have miniscule impacts on the Low Carbon Energy Cost Recovery Rider rates paid by other PNG customers, given that total deliveries to Granisle and Tumbler Ridge customers are relatively small at approximately 750 terajoules per year.[161]
PNG proposes to align the Low Carbon Energy Cost Recovery Rider rate-setting mechanisms with the existing natural gas rate setting processes, where the Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting to the BCUC.[162]
PNG submits that it is not averse to establish additional triggers for the adjustment of the Low Carbon Energy Cost Recovery Rider that would be assessed during the quarterly review of the Low Carbon Energy portfolio. PNG considers that a trigger based on the amount of excess Low Carbon Energy costs retained in the Low Carbon Energy Cost Variance Account due to under-recovery through the Low Carbon Energy Cost Recovery Rider is best aligned with the goals of such a review, namely minimizing the cost of carrying a balance in the Low Carbon Energy Cost Variance Account.[163]
PNG submits that an appropriate threshold for considering an adjustment to the Low Carbon Energy Cost Recovery Rider before the annual review would be a change in the Low Carbon Energy Cost Variance Account balance averaged over three months of more than 50 percent. PNG also proposes to reserve the right to consider other factors, at its discretion, when considering whether a change to the Low Carbon Energy Cost Recovery Rider is warranted .[164]
Positions of the Parties
BCSEA submits that PNG’s Low Carbon Energy cost recovery mechanism is “an appropriate step forward,” but adds that should a mandatory GHG reduction standard for gas utilities be put in place, PNG may need to redesign this cost recovery mechanism and include an allocation of Low Carbon Energy to all PNG customers.[165]
BCSEA supports approval of the cost recovery orders requested by PNG. [166]
RCIA supports the cost recovery mechanisms proposed by PNG because they appear to be practical and efficient means of accounting for Low Carbon Energy financially.[167] RCIA also supports PNG’s proposed accounting treatment and cost allocation.[168]
Panel Determination
The Panel approves PNG to levy an initial Low Carbon Energy Cost Recovery Rider of $0.00 per gigajoule and directs PNG to record the revenues received from the Low Carbon Energy Cost Recovery Rider in the Low Carbon Energy Cost Variance Account.
As previously noted, pursuant to section 18 of the CEA, the BCUC must allow PNG to recover the cost of any Low Carbon Energy it acquires as a prescribed undertaking as defined in the GGRR. The cost of any Low Carbon Energy not allocated to PNG’s Smart Energy customers, Company Use Gas, off-system sales or PNG’s customers will remain in the Low Carbon Energy Cost Variance Account and must be recovered in some other manner. The Panel finds that recovering these costs from all PNG’s non-bypass customers through the Low Carbon Energy Cost Recovery Rider is reasonable as it spreads the cost equitably between as many of PNG’s customers as possible.
The Panel directs PNG to collect the Low Carbon Energy Cost Recovery Rider from all its non-bypass customers including those in its Granisle and Tumbler Ridge service areas. The costs of Low Carbon Energy supply in excess of recoveries from the Smart Energy program are a required cost of PNG continuing to serve all its customers, as PNG itself has noted. As a result, the costs collected by the Low Carbon Energy Cost Recovery Rider are not related to any PNG specific service area, fuel type or type of customers, and apply to all customers whether or not they choose or are able to participate in the Smart Energy program.
PNG is directed to explain, in its review of the Low Carbon Energy program addressed in Section 6.0 below, why bypass customers should continue to be excluded from the Low Carbon Energy Cost Recovery Rider.
The Panel approves PNG to use an adjustment mechanism for the Low Carbon Energy Cost Recovery Rider, whereby the Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting to the BCUC.
The Panel has no evidence that changes to the Low Carbon Energy Cost Recovery Rider are required on a quarterly basis. PNG is directed to provide a submission to the BCUC at each annual review of the Low Carbon Energy Cost Recovery Rider as to whether quarterly changes to the Low Carbon Energy Cost Recovery Rider should be considered, and if so whether setting a threshold for making such changes is appropriate.
However, the Panel has concerns about how PNG’s proposed rate adjustment mechanism for the Low Carbon Energy Cost Recovery Rider will work.
As noted in Section 3.2.1 above, PNG proposes to hold six months of Low Carbon Energy supply, the cost of which will be recorded in the Low Carbon Energy Cost Variance Account. PNG’s intention appears to be that this quantity of Low Carbon Energy supply would not be allocated during the year of its acquisition, so its cost would remain in the Low Carbon Energy Cost Variance Account at the end of the year. However, according to the rate adjustment mechanism proposed by PNG, the cost of this inventory would then be recovered through the Low Carbon Energy Cost Recovery Rider. Since the inventory of Low Carbon Energy supply is intended for the benefit of Smart Energy customers, it is not appropriate that its cost be recovered from all PNG’s customers who pay the Low Carbon Energy Cost Recovery Rider.
The Panel directs PNG, in a compliance filing within 30 days of the date of issuance of this Decision, to propose a mechanism by which the cost of its six months’ inventory of Low Carbon Energy supply may be recovered from the Smart Energy customers who benefit from it rather than from all PNG’s customers.
As PNG notes, any variances between the Low Carbon Energy program costs and the recoveries will be retained in the Low Carbon Energy Cost Variance Account.[169] Thus, any differences between the actual costs incurred and the forecast costs used to calculate recovery rates, will remain in the Low Carbon Energy Cost Variance Account.
For example, the Low Carbon Commodity Charge recovers (among other things) PNG’s forecast marketing expenditures. If PNG were to underspend on marketing in one year, the Low Carbon Commodity Charge would over-collect in this regard from PNG’s Smart Energy customers, reducing the balance in the Low Carbon Energy Cost Variance Account. This over-collection would then be returned to all PNG’s customers, not merely the Smart Energy customers, in the following year through the Low Carbon Energy Cost Recovery Rider.
The Panel anticipates that such variances between forecast and actual costs will be small, and that no significant inequities will result, but recommends that the BCUC monitor PNG’s forecast and actual spending to ensure this is the case. The Panel directs that PNG report annually its forecast and actual expenditures in all categories related to the Smart Energy program.
4.7 Tariffs and General Terms and Conditions
To enable the sale of Low Carbon Energy through the Smart Energy program, PNG seeks the BCUC’s approval for new Rate Schedules RS1-LCE, RS2-LCE, RS3-LCE, RS4-LCE, RS5-LCE and RS6-LCE. PNG states the new rate schedules mirror the existing sales tariffs and include provisions enabling customers to select from a range of Low Carbon Energy blending options. Additionally, PNG proposes to amend its General Terms and Conditions to include the addition of new definitions relating to the Low Carbon Energy Service, and the introduction of a Section 24 – Low Carbon Energy Service.[170]
Panel Determination
The Panel approves PNG to use the new rate schedules for the Smart Energy program as set out in section 6.2.1 of the Application, subject to the following changes:
• PNG is directed to add the Tumbler Ridge service area to the Smart Energy program for rates schedules RS1-LCE, RS2-LCE, RS3-LCE and RS4-LCE.
• PNG is directed to file any changes to the Company Use Gas rate schedules needed to implement the Panel’s directives in Sections 3.2.2 and 4.3 above.
The Panel directs PNG to file updated rate schedules for the Smart Energy program as a compliance filing within 30 days of the date of issuance of this Decision.
The Panel consents to the modifications to PNG’s general terms and conditions, subject to the following changes:
• PNG is directed to change the definition of Low Carbon Energy to be consistent with the Panel’s direction in Section 2.0 of this Decision.
• PNG is directed to incorporate the changes to the rate schedules directed in this Section 4.0 above.
• PNG is directed to specify that any and all environmental attributes associated with the sales of Low Carbon Energy are transferred to the customer purchasing the Low Carbon Energy.
5.0 Reporting
PNG proposes to report annually on the performance of its Low Carbon Energy program, with reports containing the following information for the previous 12-month period:[171]
1. Quantities of Low Carbon Energy supply under contract and the quantities that were actually delivered to PNG during each month.
2. The performance of the Smart Energy program as determined through customer additions and cumulative enrollment.
3. The disposition of Low Carbon Energy to: (i) the Smart Energy program, (ii) transfers to the Company Use Gas Account, (iii) sales to off-system third parties, and (iv) transfers to the Gas Cost Variance Account.
4. The remaining costs in the Low Carbon Energy Cost Variance Account that are amortized through rates and whether an adjustment to the Low Carbon Commodity Charge is required.
5. The average cost of supply in the Low Carbon Energy portfolio and whether an adjustment to the Low Carbon Commodity Charge for the next 12-month period is required.
Positions of the Parties
RCIA submits that it supports PNG’s proposed quarterly reporting of the Low Carbon Energy Cost Variance Account balance.[172]
In BCSEA’s view, it is effective and efficient to align the Low Carbon Energy Cost Variance Account reporting and rate setting mechanism with the existing rate-setting process, whereby Low Carbon Energy costs and recoveries are reviewed on an annual basis as part of PNG’s quarterly gas cost reporting.[173]
Panel Determination
The Panel directs PNG to report the following in its annual report to the BCUC for the previous 12-month period starting with the year ending on December 31, 2022:
1. Quantities of Low Carbon Energy supply under contract and the quantities that were actually delivered to PNG during each month.
2. The performance of the Smart Energy program as determined through customer additions and cumulative enrollment.
3. The disposition of Low Carbon Energy to: (i) the Smart Energy program, (ii) transfers to the Company Use Gas Account, (iii) sales to off-system third parties, and (iv) transfers to the Gas Cost Variance Account.
4. The remaining costs in the Low Carbon Energy Cost Variance Account that are amortized through rates and whether an adjustment to the Low Carbon Commodity Charge is required.
5. The average cost of supply in the Low Carbon Energy portfolio and whether an adjustment to the Low Carbon Commodity Charge for the next 12-month period is required.
6. Details of all off-system sales of Low Carbon Energy, including price, date quantity, counterparty, carbon intensity and delivery point.
7. Expenditures on Smart Energy program incentives, including details of the nature and recipients of the incentives and why the incentives were not discriminatory.
8. The activity and closing balance of the Smart Energy Marketing Cost Deferral Account.
9. Forecast and actual expenditures in all categories related to the Smart Energy Program.
6.0 Review of the Low Carbon Energy Program
PNG proposes to monitor customers’ participation in blending options within the Smart Energy program as well as the impact of commodity prices and the BC Carbon Tax on the premium for biomethane paid by customers for information on customers’ elasticity of demand. After three years of operation, PNG expects that it will have sufficient experience with the Smart Energy program to determine whether adjustments to either the blending options, the pricing, or both is warranted in order to maximize the revenues recovered through the program.[174]
PNG also anticipates that regulations related to the Province’s contemplated GHG Reduction Standard could come into force as early as the spring of 2023, which are expected to provide further clarity on PNG’s GHG reduction obligations, as well as details of any compliance pathways, in addition to Low Carbon Energy, which may be available.[175] PNG therefore submits that a review of its Low Carbon Energy Cost Recovery Mechanism in the middle of 2024 would be an appropriate review timeframe to allow sufficient experience with the current Low Carbon Energy Cost Recovery Mechanism and know the impact of any regulatory changes supporting the CleanBC GHG Reduction Standard.[176] However, PNG also notes that this review would not likely result in changes to the Smart Energy program, and a more in-depth review of the Low Carbon Energy cost recovery mechanism should still take place in 2026, following three years of operation.[177]
PNG will consider its Low Carbon Energy cost recovery mechanism to be successful if it creates awareness of renewable natural gas and the opportunities it provides for emission reduction, minimizes the costs recovered from all customers through the Low Carbon Energy Cost Recovery Rider, and reduces the GHG emissions associated with energy deliveries to PNG’s facilities and customers. PNG submits that to achieve these goals, participation in the Smart Energy program would meet or exceed projected potential demand of up to 11 terajoules, and PNG would be successful in selling a portion of Low Carbon Energy off-system under short term agreements.[178]
Positions of the Parties
PNG submits that its proposed Low Carbon Energy recovery mechanism is “suited to current regulation that allows for the voluntary acquisition of biomethane and balances the need for PNG to develop a portfolio of biomethane supply, with consideration of the cost impact to customers of doing so.” PNG also submits that the Low Carbon Energy Cost Recovery Mechanism would be suited to a future GHG Reduction Standard.[179]
Notwithstanding this, PNG submits that a review of its Low Carbon Energy recovery mechanism in the middle of 2024, or approximately 18 months after the enactment of the GHG Reduction Standard, is appropriate. PNG submits this timing “balances the requirement of having sufficient experience with the current Low Carbon Energy Cost Recovery Mechanism, and the impact of any regulatory changes supporting the CleanBC GHG Reduction Standard.” However, PNG submits that it would only have sufficient experience with the Smart Energy program after three years of operation to determine whether adjustments would be warranted.[180]
BCSEA submits that the middle of 2024, or approximately 18 months after the anticipated enactment of the BC GHG Reduction Standard, is a reasonable balance between the benefits of an early review and the benefits of experience with the anticipated GHG Reduction Standard. BCSEA adds that the question of whether there is sufficient experience to make adjustments to the Smart Energy program can be dealt with at that time.[181]
BCSEA submits that PNG should include in its three-year review the topic of whether the price of Low Carbon Energy in the Smart Energy program should be based on full cost recovery or revenue maximization.[182]
RCIA submits that a comprehensive review of the Low Carbon Energy program in three years would be appropriate, or sooner if PNG implements material changes to its Low Carbon Energy program.[183]
Panel Determination
• PNG’s supply of Low Carbon Energy, including sufficiency to meet demand and flexibility to avoid purchasing surplus quantities;
• Customer demand for the Smart Energy program, including whether changes to the Smart Energy program could be made to maximize program revenues;
• The success of the Low Carbon Energy program, including GHG emission reductions achieved and program costs to PNG’s ratepayers avoided;
• The degree to which the marketing activities for the Smart Energy program were successful in promoting demand for Low Carbon Energy;
• A comprehensive analysis of the relative costs of using Low Carbon Energy versus electrification to decarbonize its gas distribution system;
• An analysis of the relative benefits to ratepayers of using Low Carbon Energy for Company Use Gas versus selling the Low Carbon Energy to off-system counterparties;
• Why bypass customers should continue to be excluded from the Low Carbon Energy Cost Recovery Rider;
• Information for the BCUC to determine whether the valuation of transfers of Low Carbon Energy for Company Use Gas at the Low Carbon Commodity Charge rate remains justified; and
• Information that would enable the BCUC to evaluate whether a different Low Carbon Commodity Charge rate would better maximize revenues from the Smart Energy program.
The Panel does not consider that PNG will have sufficient experience with the Low Carbon Energy program by 2024 to warrant a review of the program by that date, and further considers that there is insufficient certainty that there will be any regulatory or legislative changes by that time. However, if there is any change to the circumstances affecting PNG’s Low Carbon Energy program, including regulatory or legislative changes, PNG may submit an application to modify the program at any time.
7.0 Biomethane Credits
PNG submits that it will receive all environmental attributes associated with the production of biomethane purchased under the Biomethane Purchase Agreements. [184] For each Biomethane Purchase Agreement, the seller must prepare a “Carbon Intensity Report,” detailing the carbon intensity delivered to PNG in the previous year, using protocols under the Greenhouse Gas Reduction (Renewable and Low Carbon Fuel Requirements) Act and its regulations.[185] The sellers under the Biomethane Purchase Agreements must also represent and warrant that no third party has any claim to any environmental attribute sold to PNG and that none of the environmental attributes have been accounted in another jurisdiction.[186]
PNG adopts, as a principle for determining the types of Low Carbon Energy offered through the Smart Energy program, whether such forms of Low Carbon Energy receive a credit under the provisions of the BC Carbon Tax Act and associated BC Carbon Tax regulation. [187] PNG therefore proposes to limit its voluntary Low Carbon Energy program to an offering of biomethane, until such time that the BC Carbon Tax Act and the BC Carbon Tax Regulation are amended to include crediting mechanisms for biogas, hydrogen, and syngas.[188] PNG submits that this will preserve the benefit to customers of acquiring Low Carbon Energy supply, of a reduction in carbon tax paid.[189]
PNG submits it will account for the acquisition and disposition of biomethane to the voluntary Smart Energy program, to Company Use Gas, to off-system counterparties, and to PNG’s natural gas supply portfolio to ensure biomethane and its associated environmental attributes will be accurately tracked.[190] PNG submits that for biomethane transferred under each of these mechanisms, the associated environmental attributes of biomethane are transferred and retired.[191] PNG submits that this transfer of environmental attributes will result in a biomethane credit, pursuant to the BC Carbon Tax regulation, for customers of the Smart Energy program,[192] and further submits that PNG will be able to transfer carbon intensity attributes to customers of the Smart Energy program in a manner which will allow customers to receive emissions credits under the Renewable and Low Carbon Fuel Requirements Act.[193] PNG submits that, aside from the Renewable and Low Carbon Fuel Requirements Act , no other registry currently exists for the accounting of inventory, transfers, and retirements of environmental attributes specific to utility sales of biomethane.[194]
Using biomethane as Company Use Gas will allow PNG to displace conventional natural gas to reduce its own direct GHG emissions.[195] Despite this, PNG notes that under current BC Carbon Tax Regulation, its customers do not receive a biomethane credit from PNG’s use of biomethane as Company Use Gas.[196] PNG has not identified any alternative arrangements that will allow PNG to claim the biomethane credit on behalf of its customers; however, PNG proposes to continue to engage with the Ministry of Finance to determine whether there are alternative contractual supply arrangements that PNG could enter into that would allow PNG to claim the biomethane credit.[197]
Regarding off-system sales to third parties, PNG states it will include provisions in the off-system sales contract that will constrain the third party’s sales of biomethane and the related environmental attributes to counterparties consuming the biomethane in BC.[198] PNG states that it will provide qualified off-system purchasers with the biomethane tax credit for Low Carbon Energy purchased.[199] PNG defines a qualified purchaser as a purchaser who consumes the blend of natural gas and biomethane, delivered pursuant to the terms of a biomethane contract, and who is required under the Carbon Tax Act to pay the Carbon Tax in respect of quantities of biomethane purchased.[200] PNG does not believe it is able to provide the biomethane credit to third parties who are wholesale or retail dealers.[201]
PNG states that its customers outside of the Smart Energy program will not be able to claim an emissions reduction or the biomethane credit for quantities of biomethane which are allocated to all PNG customers through blending with the natural gas supply portfolio.[202] PNG states it is considering the opportunity to modify all sales tariffs to specify a specific blend of biomethane delivered with its natural gas; however, it has not identified a suitable option to do so due to the variability of gas supply and demand, expected variability in biomethane supply, and requirements of the Carbon Tax Regulation to receive a biomethane credit.[203] PNG notes that it will continue to engage with the Ministry of Finance to determine whether there are alternative contractual supply arrangements which would allow PNG to claim the biomethane credit for volumes of biomethane allocated to PNG customers through blending with the natural gas supply portfolio.[204]
Positions of the Parties
PNG confirms that the BC Carbon Tax will continue to be payable on all natural gas combusted at PNG facilities, including biomethane. The full cost of Company Use Gas supply, including Carbon Tax expense, is incorporated into the Company Use Gas charge, which is typically reviewed and approved by the BCUC during its review of PNG’s revenue requirement applications. PNG submits that recovery of Carbon Tax costs, regardless of whether they are charged to natural gas or biomethane, is consistent with PNG’s current practice and therefore no further determination by the BCUC is necessary. PNG will continue to evaluate opportunities to access the biomethane credit for biomethane used as Company Use gas, and in the event that PNG is able to receive the biomethane credit on Company Use Gas, the associated benefit will be reflected in the Company Use Gas charge recovered from customers.[205]
Regarding the Low Carbon Energy Cost Recovery Rider, PNG submits that no deliveries of biomethane are associated with this rate, and therefore the BC Carbon Tax does not apply.[206]
BCSEA concurs that recovery of BC Carbon Tax costs through the Company Use Gas charge, whether charged to natural gas or biomethane, is consistent with PNG’s current practice and therefore no further determination by the BCUC is necessary.[207] BCSEA submits it is unfortunate that biomethane for PNG’s own use is not eligible for the biomethane credit under the current BC Carbon Tax Regulation and supports PNG’s efforts to “rectify this situation.” [208]
RCIA encourages PNG to seek full biomethane credit recovery and credit such recovery to the Low Carbon Energy Cost Recovery Rider or lowering the PNG Company Use Gas rate. [209] RCIA additionally encourages PNG to provide clear reporting of the steps regarding the recovery of biomethane credits.[210]
Panel Discussion
The Panel makes no determinations with respect to biomethane credits related to PNG’s Low Carbon Energy program. PNG appears to be taking appropriate advantage of biomethane credits where they are available, including passing them on to customers where applicable.
8.0 Confidentiality
PNG requests that portions of the Application and certain documents supporting the Application be kept confidential pursuant to Section 18 of the BCUC’s Rules of Practice and Procedure regarding confidential documents, and Section 6.0 of the Rules for Natural Gas Energy Supply Contracts adopted by Order G-130-06. Items for which PNG requests confidential treatment include: [211]
• The ATCO and Tidal Biomethane Purchase Agreements attached as Appendix F and Appendix G, respectively;[212]
• The confidential financial schedules attached as Appendix H;[213] and
• Certain information on the Biomethane Purchase Agreements as presented in Section 8 of the Application.
PNG states that this information is “market-sensitive and believes that disclosure of the information may adversely affect PNG’s ability to secure the most competitively-priced biomethane supply arrangements in the future and result in increased costs of PNG’s Low Carbon Energy portfolio.” [214]
PNG also submitted responses to BCUC information requests on a confidential basis for information requests including confidential information, in Exhibits B-4 and B-9-1.
On January 27, 2022, the BCUC wrote PNG requesting that PNG file a redacted version each of the ATCO and Tidal Biomethane Purchase Agreements pursuant to section 18.01(b) of the BCUC’s Rules of Practice and Procedure.[215] PNG subsequently provided public versions of each of the ATCO and Tidal Biomethane Purchase Agreements with commercially sensitive information redacted.[216]
PNG believes that disclosure of this information may adversely affect PNG’s ability to secure the most competitively priced biomethane supply agreements in the future, resulting in increased costs to PNG’s Low Carbon Energy portfolio. [217]
Panel Determination
The Panel is not satisfied that all the information in PNG’s financial schedules is “market sensitive” and needs to be held confidentially. The Panel invites PNG to file a submission to this Panel within 30 days of the date of issuance of this Decision to expand on its reasons for requesting that Appendix H (financial schedules) be held confidential with specific reference to:
• The forecast number of customers of the Smart Energy program;
• The forecast quantity of Low Carbon Energy to be sold; and
• The forecast revenue from sales of Low Carbon Energy.
Dated at the City of Vancouver, in the Province of British Columbia, this 25th day of November 2022.
Original signed by:
____________________________________
R. I. Mason
Panel Chair / Commissioner
Original signed by:
____________________________________
A. C. Dennier
Commissioner
Original signed by:
____________________________________
M. Kresivo, KC
Commissioner
Pacific Northern Gas Ltd and Pacific Northern Gas (N.E.) Ltd.
Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements
Acronym List
| Acronym |
Description |
| Application |
Application for approval of a Low Carbon Energy (LCE) Cost Recovery Mechanism, and pursuant to section 71 of the UCA and the BCUC Rules for Natural Gas Energy Supply Contracts approval of Biomethane Purchase Agreements with ATCO Future Fuel RNG Limited Partnership (ATCO) and Tidal Energy Marketing Inc. (Tidal) |
| ATCO RNG |
ATCO Future Fuel RNG Limited Partnership |
| BCSEA |
BC Sustainable Energy Association |
| BCUC |
British Columbia Utilities Commission |
| CEA |
Clean Energy Act |
| FEI |
FortisBC Energy Inc. |
| GGRR |
Greenhouse Gas Reduction (Clean Energy) Regulation |
| GHG |
Greenhouse gas |
| IR |
Information request |
| LCCVA |
Low Carbon Energy Cost Variance Account |
| LCE |
Low Carbon Energy |
| PNG |
Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. |
| PNG(N.E.) |
Pacific Northern Gas (N.E.) Ltd. |
| RCIA |
Residential Consumer Intervener Association |
| RNG |
Renewable natural gas |
| RNG Inquiry’s Phase 1 Report |
BCUC Inquiry into the Acquisition of Renewable Natural Gas by Public Utilities in British Columbia, Phase 1 Report dated July 28, 2022 |
| Tidal |
Tidal Energy Marketing Inc. |
| UCA |
Utilities Commission Act |
Pacific Northern Gas Ltd and Pacific Northern Gas (N.E.) Ltd.
Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements
EXHIBIT LIST
Exhibit No. Description
Commission documents
| A-1 |
1. Letter dated December 29, 2021 – BCUC appointing the Panel for the review of Pacific 2. Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. application of a Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements
|
| A-2 |
Letter dated January 11, 2022 – BCUC Order G-6-22 establishing a regulatory timetable |
| A-3 |
Letter dated January 27, 2022 – BCUC Request PNG to resubmit documents |
| A-4 |
Letter dated February 7, 2022 – BCUC Information Request No. 1 to PNG |
| A-5 |
CONFIDENTIAL - Letter dated February 7, 2022 – BCUC Confidential Information Request No. 1 to PNG |
| A-6 |
Letter dated March 31, 2022 – BCUC Order G-90-22 establishing a further regulatory timetable |
| A-7 |
Letter dated April 1, 2022 – BCUC Order E-7-22 regarding Acceptance of BPAs |
| A-8 |
Letter dated April 12, 2022 – BCUC Information Request No. 2 to PNG |
| A-9 |
Letter dated May 19, 2022 – BCUC request to parties for submissions and BCUC Order G‑138-22 establishing a further regulatory timetable |
| A-10 |
Letter dated May 20, 2022 – BCUC Order G-141-22 amending the regulatory timetable |
Applicant documents
| B-1 |
Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. (PNG) – Redacted Application for Approval of a Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements dated November 17, 2021
|
| B-1-1 |
CONFIDENTIAL – Letter dated November 17, 2021 - PNG submitting confidential application for approval of a Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements
|
| B-1-2 |
REDACTED - Letter dated February 3, 2022 – PNG submitting redacted application for approval of a Low Carbon Energy Cost Recovery Mechanism and Biomethane Purchase Agreements
|
| B-2 |
Letter dated December 15, 2021 - PNG submitting errata to application
|
| B-3 |
Letter dated March 4, 2022 – PNG submitting responses to BCUC Information Request No. 1
|
| B-4 |
CONFIDENTIAL - Letter dated March 4, 2022 – PNG submitting responses to BCUC confidential Information Request No. 1
|
| B-5 |
Letter dated March 4, 2022 – PNG submitting responses to RCIA Information Request No. 1
|
| B-6 |
Letter dated March 4, 2022 – PNG submitting responses to BCSEA Information Request No. 1
|
| B-7 |
Letter dated March 10, 2022 – PNG submitting comment on further regulatory process |
| B-8 |
Letter dated March 28, 2022 – PNG submitting reply to Intervener submissions on further process
|
| B-9 |
Letter dated May 10, 2022 – PNG submitting responses to BCUC Information Request No. 2
|
| B-9-1 |
CONFIDENTIAL - Letter dated May 10, 2022 – PNG submitting confidential response to BCUC Information Request No. 2 Question 26.1
|
| B-10 |
Letter dated May 10, 2022 – PNG submitting responses to BCSEA Information Request No. 2
|
| B-11 |
Letter dated May 10, 2022 – PNG submitting responses to RCIA Information Request No. 2
|
| B-12 |
Letter dated May 19, 2022 – PNG submitting request to amend the Regulatory Timetable |
Intervener documents
| C1-1 |
BC SUSTAINABLE ENERGY ASSOCIATION (BCSEA) - Letter dated January 18, 2022 Request to Intervene by T. Hackney |
| C1-2 |
Letter dated February 7, 2022 – BCSEA submitting Confidentiality Declaration and Undertakings |
| C1-3 |
Letter dated February 14, 2022 – BCSEA Information Request No. 1 to PNG |
| C1-4 |
Letter dated March 17, 2022 – BCSEA submitting response on further process regarding Rates and Cost Recovery |
| C1-5 |
Letter dated April 19, 2022 – BCSEA Information Request No. 2 to PNG |
| C2-1 |
FortisBC Energy Inc. (FEI) – Letter dated February 2, 2022 Request to Intervene by Diane Roy |
| C3-1 |
Residential Consumer Intervenor Association (RCIA) – Letter dated February 3, 2022 Request to Intervene by Samuel Mason |
| C3-2 |
Letter dated February 11, 2022 – RCIA Information Request No. 1 to PNG |
| C3-3 |
Letter dated March 18, 2022 – RCIA submission on further process |
| C3-4 |
Letter dated April 19, 2022 – RCIA Information Request No. 2 to PNG |
Interested party documents
| D-1 |
Steventon, D. (Steventon) - Submission dated February 5, 2022 Request for Interested Party Status |
| D-2 |
Heller, M. (Heller) - Submission dated April 6, 2022 Request for Interested Party Status |
Letters of comment
| E-1 |
Steventon, D. – Letter of Comment dated February 8, 2022 |
[1] Exhibit B-1, Section 1, p. 1.
[2] Order E-7-22.
[3] Exhibit B-1, Section 5.1, p.25
[4] Ibid., Sections 5.1, 5.2, 5.3, 5.4 and 5.5, pp. 25–28.
[5] Exhibit B-1, Section 1.2, p. 4; Exhibit B-2, p. 4.
[6] Exhibit B-3, IR 12.4.
[7] Exhibit B-1 p. 1.
[8] Ibid., p. 4; Exhibit B-2, p. 4.
[9] Ibid., pp. 5, 20.
[10] Clean Energy Act 18(2).
[11] Exhibit B-1, p. 2.
[12] Ibid., p. 2.
[13] Ibid., p. 2.
[14] Greenhouse Gas Reduction (Clean Energy) Regulation, Section 2(3.8).
[15] Clean Energy Act, Section 18.
[16] PNG requests approval of the “Low Carbon Energy Recovery Charge” rate setting mechanism on p. 4 of Exhibit B-3, but the referenced section 7.8.4 on p. 53 of Exhibit B-3 discusses the Low Carbon Energy Cost Recovery Rider.
[17] Previously accepted by BCUC Order E-7-22 dated April 1, 2022.
[18] Exhibit B-3, BCUC information request (IR) 1.15.4.
[19] As amended by Orders G-90-22, G-138-22 and G-141-22.
[20] Exhibit B-1, Section 2.1.1.1, pp.7-8.
[21] Ibid., Section 2.1, p. 7.
[22] Ibid.
[23] Exhibit B-5, RCIA IR 1.2.5.
[24] Exhibit B-1, Appendix D, p. D-3.
[25] Ibid., Section 8.4.1.2, p. 58; Section 8.5.4, p. 59.
[26]Exhibit B-1, Appendix D, p. 24-1
[27] Exhibit B-3, BCUC IR 1.1.1.
[28] Ibid., BCUC IR 1.1.2.1.
[29] BCUC Inquiry into the Acquisition of Renewable Natural Gas by Public Utilities in British Columbia, Phase 1 Report dated July 28, 2022, Executive summary, p. ii.
[30] PNG Final Argument, p. 3.
[31] Ibid.
[32] Exhibit B-1, Section 2.1, p. 7.
[33] Ibid., Section 4, p. 19.
[34] Exhibit B-1, Section 4.0, pp. 19–20.
[35] Ibid., Section 5.1, p. 25.
[36] Ibid., Sections 5.1, 5.2, 5.3, 5.4 and 5.5, pp. 25–28.
[37] Exhibit B-9, BCUC IR 2.23.1.
[38] Exhibit B-1, Section 5.2, p. 26.
[39] Ibid., p. 36.
[40] Exhibit B-3, BCUC IRs 1.1.2.1 and 1.6.2.
[41] Exhibit B-6, BCSEA IR 1.6.1.
[42] Exhibit B-1, Section 5.1, p. 25.
[43] Ibid.
[44] Ibid.
[45] Exhibit B-3, BCUC IRs 1.3.1 and 1.3.3.
[46] Ibid., BCUC IR 1.3.2.
[47] Exhibit B-1, Section 5.1, p. 26.
[48] Exhibit B-3, BCUC IR 1.7.2; Exhibit B-9, BCUC IR 2.23.1.
[49] Exhibit B-1, Section 6.4, p. 41.
[50] Ibid, p. 41.
[51] Exhibit B-1, Sections 5.2 and 6.1.2, pp. 26 and 35.
[52] PNG Final Argument, p. 3.
[53] Ibid., p. 6.
[54] Ibid.
[55] BCSEA Final Argument, p. 6.
[56] RCIA Final Argument, p. 6.
[57] Ibid., p. 7.
[58] Section 28 of the UCA.
[59] Exhibit B-1, Section 5.3, p. 27.
[60] Ibid., Section 4.1.5, p. 23; Exhibit B-3, BCUC IR 1.4.2.
[61] Exhibit B-9, BCUC IR 2.20.4.
[62] Exhibit B-3, BCUC IR 1.4.1.
[63] Ibid., BCUC IR 1.13.4.
[64] Exhibit B-1, Section 5.1, p. 25.
[65] Ibid.
[66] Exhibit B-3, BCUC IR 1.4.5.
[67] Exhibit B-1, Section 5.1, p. 25.
[68] Exhibit B-3, BCUC IR 1.4.5.
[69] Ibid., BCUC IR 1.4.6.
[70] Ibid., BCUC IR 1.5.3.
[71] Exhibit B-9, BCUC IRs 2.27.3 and 2.27.5.
[72] Exhibit B-3, BCUC IR 1.5.1, Exhibit B-9, BCUC IRs 2.27.3 and 2.27.5.
[73] PNG Final Argument, p. 4.
[74] BCSEA Final Argument, p. 6.
[75] Exhibit B-9, IR 20.4.
[76] Ibid.
[77] Exhibit B-1, Section 5.4, p. 28.
[78] Ibid.
[79] Exhibit B-3, BCUC IR 1.5.4.
[80] Ibid., BCUC IR 1.5.1.
[81] Exhibit B-9, BCUC IR 2.22.3.
[82] Ibid., BCUC IR 2.21.2.
[83] PNG Final Argument, p. 5.
[84] Ibid., pp. 8–9.
[85] Ibid.
[86] RCIA Final Argument, p. 9.
[87] Exhibit B-1, Sections 5.5 and 7.8.2, pp. 28, 49.
[88] PNG Final Argument, p. .6
[89] RCIA Final Argument, p. 7.
[90] Ibid., Section 7.1, p. 43.
[91] Ibid., pp 43–44.
[92] Exhibit B-1, Section 7.1, Figure 8, p. 43.
[93] Ibid., Sections 7.2, 7.3, 7.4, 7.5 and 7.6, pp. 44–48.
[94] Exhibit B-1, Section 7.8.4, p. 53.
[95] Exhibit B-3, BCUC IR 1.13.7.
[96] Exhibit B-9, BCUC IR 2.27.8.
[97] Ibid.
[98] Exhibit B-3, BCUC IR 1.7.1; Exhibit B-9, BCUC IR 2.28.2.
[99] RCIA Final Argument, p. 7.
[100] BCSEA Final Argument, p. 7.
[101] Exhibit B-1, Section 7.2, p. 44.
[102] Ibid.
[103] Ibid., Section 7.3, pp.44–45.
[104] Exhibit B-1, Section 7.4, p. 45.
[105] Ibid.
[106] Ibid., Section 7.5.1, p. 46.
[107] Ibid., Section 7.5.2, p. 46; Exhibit B-3, BCUC IR 1.10.4.
[108] Ibid, Section 7.5.3, p. 46.
[109] Ibid., Sections 7.5, 7.5.1, 7.5.2 and 7.5.3; Exhibit B-3, BCUC IR 1.10.1.
[110] Exhibit B-1, Section 7.5.4, p. 47.
[111] RCIA Final Argument, p. 7.
[112] BCSEA Final Argument, pp. 4, 7.
[113] Exhibit B-3, BCUC IR 12.4.
[114] Exhibit B-1, Section 7.6, pp. 47–48.
[115] Exhibit B-3, BCUC IR 1.11.2.
[116] Ibid., BCUC IR 1.13.9.
[117] Exhibit B-9, BCUC IR 2.25.1.
[118] Exhibit B-1, Section 6.1.2, p. 35.
[119] Ibid., Section 6.3.1, p. 40.
[120] Exhibit B-3, BCUC IR 1.11.3.
[121] Exhibit B-1, Section 6.3.1, p. 40; Exhibit B-3, BCUC IR 1.11.3.1.
[122] Exhibit B-1, Section 8.6.1, p. 70.
[123] Ibid., p. 71; Exhibit B-3, BCUC IRs 1.11.1 and 1.15.1.
[124] Exhibit B-3, BCUC IR 1.15.3.
[125] Ibid., BCUC IR 1.15.4.
[126] Exhibit B-1, Section 1.2, p. 4; Exhibit B-2, p. 4.
[127] Ibid., Section 6.1.3, p. 36.
[128] Exhibit B-3, BCUC IR 1.12.1.
[129] Exhibit B-6, BCSEA IR 1.6.3.
[130] Exhibit B-1, Section 6.1.3, p. 36.
[131] Ibid., Section 6.1.1, p. 30.
[132] Exhibit B-1, Section 7.8.4, p. 53.
[133] Exhibit B-3, BCUC IR 1.14.1.
[134] PNG Final Argument, p. 12.
[135] Ibid.
[136] Ibid., p. 4.
[137] BCSEA Final Argument, p. 6.
[138] Ibid., p. 9.
[139] RCIA Final Argument, p. 8.
[140] Ibid., p. 7.
[141] Ibid., p. 9.
[142] PNG Reply, p. 4.
[143] RCIA Final Argument, p. 7.
[144] Exhibit B-1, Sections 5.3 and 7.8.1, pp. 27, 49.
[145] Exhibit B-3, BCUC IR 1.13.4.
[146] Exhibit B-1, Section 5.4, p. 28.
[147] Exhibit B-9, BCUC IR 2.22.1.
[148] Exhibit B-1, Section 7.8.2, p. 49.
[149] Exhibit B-3, BCUC IR 1.13.3.
[150] Ibid.
[151] Exhibit B-1, Section 1.2, p. 4; Exhibit B-1, Section 7.8.2, p.50; Exhibit B-2, p. 4.
[152] Ibid.; Exhibit B-1, Appendix E.
[153] Exhibit B-1, Section 7.8.2, pp. 49–50.
[154] Exhibit B-9, BCUC IRs 2.27.3 and 2.27.5.
[155] Exhibit B-3, BCUC IR 1.13.5.
[156] Exhibit B-9, BCUC IR 2.27.7.
[157] Exhibit B-1, Section 5.1, p. 25.
[158] Ibid.
[159] Ibid.
[160] Ibid., Section 6.2.2, p. 38.
[161] Exhibit B-3, BCUC IR 1.3.3.
[162] Exhibit B-1, Section 7.8.4, p. 53.
[163] Exhibit B-3, BCUC IR 1.14.1.
[164] Exhibit B-9, BCUC IR 2.28.1.
[165] BCSEA Final Argument, p. 7.
[166] Ibid.
[167] RCIA Final Argument, p. 7.
[168] Ibid.
[169] Exhibit B-1, p. 53.
[170] Exhibit B-1, Section 6.2.1, pp. 37–38.
[171] Exhibit B-1, section 7.8.5, pp. 53–54
[172] RCIA Final Argument, p. 7.
[173] BCSEA Final Argument, p. 9.
[174] Exhibit B-1, p. 36.
[175] Exhibit B-3, BCUC IR 1.14.3.
[176] Ibid.
[177] Exhibit B-9, BCUC IR 2.28.3.
[178] Exhibit B-3, BCUC IR 1.14.2.
[179] PNG Final Argument, p. 11.
[180] PNG Final Argument, p. 11.
[181] BCSEA Final Argument, pp. 9–10.
[182] Ibid., p. 6.
[183] RCIA Final Argument, p. 9
[184] Exhibit B-1, Section 8.4.5, p. 63; Section 8.5.5, p. 69.
[185] Exhibit B-3, BCUC IR 1.17.3.
[186] Ibid.
[187] Exhibit B-1, Section 5.2, p. 26.
[188] Ibid.
[189] Exhibit B-1, Section 5.2, p. 26.
[190] Exhibit B-3, BCUC IR 1.1.1.
[191] Ibid., BCUC IR 1.1.2.
[192] Ibid., BCUC IR 1.1.2.1.
[193] Exhibit B-9, BCUC IR 2.19.1.
[194] Exhibit B-3, BCUC IR 1.1.2.2.
[195] Exhibit B-1, Section 4.1.5, p.23; Exhibit B-3, BCUC IR 1.4.2
[196] Exhibit B-3, BCUC IRs 1.4.2.1 and 1.4.4; Exhibit B-9, BCUC IR 2.21.7.
[197] Exhibit B-9, BCUC IRs 2.20.3 and 2.21.7.1.
[198] Ibid., BCUC IR 2.22.3.
[199] Ibid., BCUC IR 2.21.2.
[200] Ibid., BCUC IR 2.21.2.
[201] Ibid., BCUC IR 2.21.2.
[202] Exhibit B-3, BCUC IR 1.4.2.1.
[203] Ibid., BCUC IR 1.4.2.1; Exhibit B-6, BCSEA IR 1.9.2; Exhibit B-9, BCUC IRs 2.20.1, 2.20.2 and 2.21.5.
[204] Exhibit B-9, BCUC IR 2.20.3.
[205] PNG Final Argument, pp. 7–8.
[206] PNG Final Argument, p. 8.
[207] BCSEA Final Argument, p. 8.
[208] Ibid., p. 6.
[209] RCIA Final Argument, p. 7.
[210] Ibid.
[211] Exhibit B-1, Cover Letter p. 2.
[212] Page 2 of the cover letter of Exhibit B-1 identifies the ATCO and Tidal BPAs as Appendices E and F to the Application, respectively, but the BPAs are found in Appendices F and G to the Application.
[213] Page 2 of the cover letter of Exhibit B-1 identifies the confidential financial schedules as Appendix G to the Application, but the confidential financial schedules are found in Appendix H.
[214] Exhibit B-1, Cover Letter p. 2.
[215] Exhibit A-3.
[216] Exhibit B-1-2.
[217] Exhibit B-1, Cover Letter p. 2.