IN THE MATTER OF
FortisBC Inc.
Application for Approval of Stepped and Stand-by Rates
for Transmission [Voltage] Customers
Decision – STAGE IV
Celgar Stand-by Billing Demand
(See
Order G-67-14 for STAGE I,
Order G-46-15 for STAGE II and
Order G-93-15 for Stage III)
September 22, 2015
Before:
L. A. O’Hara, Commissioner/Panel Chair
R. D. Revel, Commissioner
TABLE OF CONTENTS
Page No
3.0 Celgar’s Stand-by billing demand
3.1.1 Founding Principles of the Stand-by Rate
3.2 Framework and considerations for the evaluation of an appropriate SBBD
3.2.1 Legislative and regulatory framework
3.2.2 Framework for the evaluation of Wires Demand Charges
3.2.3 Other Substantial Considerations
3.2.3.1 Clean Energy Act and
the BC Energy Plan and their relevance
to a SBBD for Celgar
3.2.3.2 Consideration of the divergent views in the design of Wires Charges
3.3 Positions of FortisBC and Celgar on setting a SBBD for Celgar
3.3.1 Synopsis of the positions
3.3.2 Cost Causation principles and fairness test
3.3.2.1 The Stage I Proceeding
3.3.4 Overall Commission Determination on Cost Causation
3.3.5 Benefits of Celgar’s self-generation to FortisBC and other ratepayers
3.3.6 Planning reserve margins
3.3.7 Availability of stand-by service
3.3.8 Significance of past brokerage agreements
3.3.8.3 Service between 2006 and 2011 (RS 33)
3.3.8.4 Service between 2000 and 2006
3.3.8.4.2 Installation of load management system
3.3.8.4.3 Communications and control system investments
3.3.8.4.4 Reliability upgrades
4.0 PANEL Determination on Celgar’s Stand-by Billing Demand
5.2 General Service Agreement (GSA)
5.3.2 Celgar’s retroactive billing requests
COMMISSION ORDER G-149-15
Appendices
Appendix A –Rate Schedules 31, 33 and 37
Appendix B– Acronyms
Appendix C– Exhibit List
The Stage I, II and III Decisions established and approved the final form of the FortisBC Inc. (FortisBC) Stand-by Service Rate in Rate Schedule 37 (RS 37).
This Stage IV Decision addresses matters that are exclusively related to the relationship between FortisBC and one of its customers, Zelstoff Celgar Limited Partnership (Celgar). Consistent with the final approved RS 37, in the absence of FortisBC and Celgar negotiating a Stand-by Billing Demand (SBBD) it will be set by the British Columbia Utilities Commission (Commission). Consequently, the subject of this decision relates entirely to establishing a SBBD for Celgar as a negotiated SBBD was not reached by the parties.
FortisBC in its Stage IV submission takes the position that there is no basis on which to set the SBBD for Celgar at anything less than 100 percent of the Stand-By Demand Limit (SBDL) or 42 MVA. Celgar submits that a SBBD of zero percent of SBDL is supported by regulatory precedent, the cost causation evidence, past brokerage agreements and Celgar’s decreased energy needs. However, it is willing to support a SBBD of 10 percent of SBDL or 4.2 MVA in honour of its first settlement proposal. This decision establishes Celgar’s Stand-by Billing Demand at 40 percent of its Stand-by Demand Limit or 16.8 MVA. The Panel determines the resultant Wires Charge would not lead to a rate that is unjust, unreasonable, unduly discriminatory or unduly preferential.
In arriving at this determination the Panel applied the framework for the evaluation established in the Stage I Decision that relates to setting a SBBD. Namely, the principles of economic efficiency, fairness, the BC Energy Policy, as well as the last contract demand that the parties agreed to. In addition, the divergent views in the design of Wires Charges were also considered. After addressing cost causation principles, and cost recovery matters the Panel determined that FortisBC failed to justify its proposed 42 MVA SBBD for Celgar as the basis for Wires Charges in the Stand-by Rate and rejected FortisBC’s proposal. The Panel then considered the benefits of Celgar’s self‑generation to FortisBC and other ratepayers, planning reserve margins, availability of Stand-by Service and the last contract demand the parties agreed to and found none of them determinative by themselves; however the Panel did find them to be indicators that assisted in testing the order of magnitude for a reasonable SBBD for Celgar. The Panel finds that there is no single, correct approach to setting a SBBD for Celgar. As observed numerous times, setting SBBD is more of an art than a science. Accordingly, the Panel explored these various different avenues to arrive at its final determination.
In the end, the Panel found that the SBBD could be set as high as at 52 percent of the SBDL or 22 MVA, as indicated by the normalized contract demand established in the 2000 General Service Agreement, which was the last contract demand the parties agreed to. However, because the other approaches indicated that directionally the SBBD should be set below that level, the Panel considered a range of possible SBBDs that could be deemed reasonable and determined that the SBBD should be set at 40 percent of Celgar’s SBDL.
Now that Celgar’s SBBD is established by this decision, the only other remaining issue to be resolved is the retroactive billing determination due to the interim nature of service provided by FortisBC to Celgar since March 25, 2011. The Panel has directed the parties to attempt to negotiate a resolution and within 30 days of the date of this decision and either file the negotiated settlement with the Commission for approval or, in the event that an agreement cannot be reached, to file a proposed retroactive billing adjustment.
1.0 INTRODUCTION
On March 28, 2013, FortisBC Inc. (FortisBC or the Company) filed an application for approval of a new set of rates for its transmission voltage customers including Rate Schedule 37 Stand-by Service (Original Application). Rate Schedule 37 (RS 37) describes the terms and conditions under which a customer with self‑generation will be able to call upon FortisBC service to replace its self-generation output during times when its generation is unavailable or operating at less than normal capacity.
The scope of the Original Application was multifaceted and complex and therefore the British Columbia Utilities Commission (Commission) has reviewed it, and ruled on it, in stages. To date, the Commission has issued three decisions (Stage I, II and III) and has made many determinations along the way. The only remaining outstanding issues relate exclusively to one of FortisBC’s customers, Zellstoff Celgar Limited Partnership (Celgar).
Celgar operates a pulp mill at Castlegar, BC (the Mill). FortisBC and its predecessor companies have served the electricity needs of Celgar and its predecessors since 1959.[1] Under most circumstances Celgar’s load is satisfied by its 52 MW turbo generator, which was installed in the early 1990s. The Mill generates steam it uses for its operations, including electricity generation, by burning wood waste and black liquor, by-products of the pulp-making process. From time to time, the turbo generator may be unavailable due to maintenance shutdowns or equipment failures. The pulp mill can operate independently of the turbo generator; therefore, when the turbo generator is not operating Celgar needs a back-up source of power.[2]
Numerous regulatory proceedings have considered the provision of this service. Most notably, in the decision on FortisBC’s 2009 Rate Design Application, the Commission directed FortisBC to provide Celgar service under Rate Schedule 31 (RS 31), effective January 2, 2011, and recommended that the parties reconsider the options available for designing a practical and workable rate schedule for Celgar. On March 25, 2011, by Order G‑188‑11, the Commission directed FortisBC to bill Celgar in accordance with RS 31 on an interim basis.
The Original Application, among other things, addressed a workable rate for Celgar (RS 37 in conjunction with RS 31.) The subject at this stage of the proceeding (Stage IV) relates specifically to determining a Stand-by Billing Demand for Celgar. After this has been determined the only other remaining issue to be resolved is the retroactive application of rates due to the interim nature of service to Celgar since March 25, 2011.
For context, a brief summary of the stages as they relate to Stage IV is provided below.
1.1 Stages I, II, and III
Stage I
In the Original Application FortisBC, among other things, designed RS 37 which it requested the Commission approve. On March 26, 2014 by Order G-67-14 the Commission issued the Stage I Decision which among other things addressed RS 37.
The Commission did not approve RS 37 as filed by FortisBC but it did make several determinations regarding that rate which set the foundation for the final rate. The Panel directed FortisBC to make a filing with the Commission requesting approval for a revised RS 37 incorporating the findings in the Stage I Decision (Revised RS 37 Filing).
The Stage I Decision also addressed certain Celgar specific issues. Specifically, the Panel directed FortisBC to file, in conjunction with the Revised RS 37 Filing, an appropriate RS 31 Contract Demand and an appropriate RS 37 Stand-by Contract Demand for Celgar.
Stage II
On June 26, 2014, FortisBC submitted the Revised RS 37 Filing. On March 24, 2015, the Panel issued the Stage II Decision by Order G-46-15. The Stage II Decision approved the form of RS 37 as directed by the Panel in its decision and established, among other things, the following Three RS 37 components: (i) RS 31 Contract Demand; (ii) Stand-by Billing Demand (previously referred to as Stand-by Contract Demand); and (iii) Stand-by Demand Limit (Three RS 37 Components) which are normally to be negotiated between the customer and FortisBC. However, the Commission’s approval was subject to the Panel approving a penalty component to the rate. Pursuant to Order G-46-15 the Commission sought further submissions from the parties on an appropriate penalty (Penalty Submissions). The Panel also provided FortisBC with an opportunity to comment on the workability of the RS 37 language directed by the Panel in the Stage II Decision (Language Submissions) and stated that it would issue a final determination on RS 37 after considering the Penalty Submissions and Language Submissions.
In regard to the Celgar issues, the Panel urged FortisBC and Celgar to negotiate and agree to the values attributable to the Three RS 37 Components reflecting the principles outlined in the Stage II Decision and asked the parties to advise the Commission of the outcome of their negotiations.
Stage III
On May 29, 2015, the Commission issued the Stage III Decision by Order G-93-15 approving the final form of RS 37[3] after considering the Penalty and Language Submissions.
In regard to the Celgar issues, the Panel set Celgar’s Contract Demand at 3 MVA and the Stand-by Demand Limit at 42 MVA after taking into consideration the information filed with the Commission in the negotiation status reports. Consequently, the only remaining component of RS 37 to be agreed to by parties, or determined by the Panel, is the Stand-by Billing Demand.
In the Stage III Decision the Panel again urged FortisBC and Celgar to negotiate and agree to a Stand-by Billing Demand, as a negotiated agreement would be preferable to the Commission making a determination. To further facilitate the progress on negotiations, the Panel determined that any by-pass options available to Celgar should not be a consideration in setting the Stand-by Billing Demand.
By Order G-93-15 the Panel, as suggested by FortisBC, gave FortisBC and Celgar an opportunity to make a further final submission on the Stand-by Billing Demand if they could not come to an agreement. The Panel also requested the parties address a specific list of issues relating to Operating Reserves (Stage IV Submissions).
The initial regulatory timetable for filing the Stage IV Submissions was established by Order G-93-15 as follows:
FortisBC submission June 19, 2015
Celgar submission July 3, 2015
FortisBC reply submission July 10, 2015
The Panel subsequently granted a one week extension as requested by Celgar. Accordingly, Celgar’s submission was due on July 10, 2015, and FortisBC’s reply on July 24, 2015 (Amended Timetable).
1.2 Stage IV Decision
The parties informed the Commission that they were not able to come to an agreement and filed their Stage IV Submissions in accordance with the Amended Timetable. This decision (Stage IV Decision) makes a final determination on an appropriate Stand-by Billing Demand for Celgar and addresses the Panel’s Operating Reserves concerns. The Stage I, II, III and IV Decisions are meant to work in conjunction with each other.
The Panel will address the issue of Operating Reserves before making a determination on Celgar’s Stand-by Billing Demand. Finally, the Panel will address certain remaining outstanding matters.
2.0 Operating RESERVES
2.1 Background
The Panel determined that the issue of whether a Stand-by customer should incur additional charges for Operating Reserves supplied by FortisBC when taking service under RS 37 could be within scope of this proceeding.[4]
FortisBC reported that, in the negotiations that took place after the Stage II Decision was issued, the parties agreed that the treatment of Operating Reserves might fairly impact the overall evaluation of the treatment of a self-generating customer and FortisBC set out six principles (Six Principles) by which the Operating Reserves are to be governed.[5]
Celgar acknowledged that the parties discussed Operating Reserves and that each party was basing its proposals on a common understanding as to how Operating Reserves were to work if one of its proposals were to be accepted by the other. Celgar also stated that it has reviewed the Six Principles and agrees with that summary.[6]
In its Stage III Decision the Panel observed that the two parties appeared to be in agreement on Operating Reserves which FortisBC seems to have, at least initially, indicated are established through the General Service Agreement (GSA). However, the Panel determined that further clarification on Operating Reserves would be necessary before it could make any determination and requested the parties make a submission answering the following seven questions in their Stage IV Submissions:
(i) Are the parties in agreement on the issue of Operating Reserves?
(ii) Are details on Operating Reserves required in order to negotiate Stand-by Billing Demand or Stand-by Demand Limit?
(iii) Are Operating Reserves bundled into the Stand-by energy or demand charges set out in FortisBC’s proposed RS 37? If not, please explain why not.
(iv) If a customer purchased energy to meet its Stand-by needs from a third party, would the third party be responsible for procuring operating reserves?
(v) Confirm, or explain otherwise, that Operating Reserves is an issue addressed through a negotiated GSA.
(vi) Explain whether or not the six principles set out in Exhibit B-39 will make up part of Celgar’s GSA.
(vii) Confirm, or explain otherwise, that the Six Principles only apply to Celgar.[7]
2.2 Parties Positions
In its Stage IV Submission, FortisBC responded to the Panel’s questions by noting that:
• FortisBC and Celgar did reach an understanding on Operating Reserves during their negotiations;
• Operating Reserves are unrelated to either Stand-by Billing Demand or Stand-by Demand Limit;
• Operating Reserves are not bundled into the Stand-by energy or demand charges set out in RS 37 because RS 37 looks only at non-power supply demand charges;
• A third party energy supplier would have to have access to Operating Reserves to supply power to its customer immediately after the generation event, and finally;
• A negotiated GSA with Celgar will address Operating Reserves and the Six Principles which only apply to Celgar; however, FortisBC would expect Operating Reserve terms with other customers to be similar.[8]
Celgar, in its Stage IV Submission, indicated that it agrees with FortisBC's responses to the seven questions posed by the Commission.[9] Celgar commented that the Six Principles referred to in the seven questions may be better described as elements of an agreement, rather than principles of an agreement. In other words, Celgar is not aware of any outstanding issues and believes that there should be very few, if any, remaining issues to be negotiated before a final GSA agreement is reached.
For that reason, Celgar indicates that it believes the Commission could assume that an agreement with FortisBC will be achieved regarding all outstanding matters in the scope of this proceeding.[10]
In consideration of the above positions, FortisBC, in its Stage IV Reply Submission, requests that the Commission require nothing further with regard to the subject of Operating Reserves until such time as a new GSA is negotiated pursuant to service under RS 37.[11]
Commission determination
The Panel observes that both FortisBC and Celgar are presently in agreement that Operating Reserves do not impact the determination of Celgar’s Stand-by Billing Demand. The Panel agrees with FortisBC and Celgar and for this reason finds that no determination is necessary with regard to Operating Reserves in this decision.
3.0 Celgar’s Stand-by billing demand
3.1 Introduction
3.1.1 Founding Principles of the Stand-by Rate
As mentioned in the introduction, RS 37 Stand-by Service describes the terms and conditions under which a customer with self-generation will be able to call upon FortisBC service to replace its self-generation output during times when its generation is unavailable or operating at less than normal capacity. The final approved rate includes the following Three RS 37 Components:
• RS 31 Contract Demand: the maximum level of full service that a customer is eligible under RS 31;
• Stand-by Demand Limit (SBDL): the maximum capacity, in excess of the RS 31 Contract Demand, that FortisBC is required to supply under RS 37 (not a billing determinant); and
• Stand-by Billing Demand (SBBD): a billing determinant used for billing the Stand-by Wires Demand Charges under RS 31 (set between zero and 100 percent of the SBDL).
The Three RS 37 Components are intended to be negotiated and agreed to between FortisBC and its customers, and expected to be specified in the customer’s GSA. RS 37 establishes that in the event an agreement cannot be reached, the Commission will set them.
Given that the parties could not come to an agreement, the Commission, in the Stage III Decision, set Celgar’s RS 31 Contract Demand and SBDL as follows:
RS 31 Contract Demand: The Panel sets Celgar’s RS 31 Contract Demand at 3 MVA as it is the highest amount that Celgar requested and FortisBC agreed to provide. If further negotiated, any RS 31 Contract Demand proposed by Celgar must be agreed to by FortisBC, but cannot be any higher than what Celgar may request.
SBDL: Both Celgar and FortisBC agree that Celgar’s load is 45 MVA. Given the Panel determination that Celgar’s Contract Demand is 3 MVA, the Stand-by Demand Limit is therefore set at 42 MVA unless the parties negotiate a different RS 31 Contract Demand which would require the Stand-by Demand Limit to be adjusted equally.
SBBD: In the Stage III Decision the Panel urged the parties to negotiate the last outstanding component, the SBBD. Given that to date FortisBC and Celgar have not been able to come to an agreement on an appropriate SBBD, the Panel is left without a choice but to set it.
3.2 Framework and considerations for the evaluation of an appropriate SBBD
In its deliberations the Panel is guided by the following framework and considerations. Several have already been identified in previous stages of the proceeding but are provided again for context.
3.2.1 Legislative and regulatory framework
As stated in the Stage II Decision, the Stand-by Rate has been filed for approval under sections 59 through 61 of the Utilities Commission Act (UCA). While complying with the UCA, particular attention has been given by the Panel to the following parts of sections 59 and 60 in making a determination on Celgar’s SBBD.
Specifically, subsection 59(1) provides that a public utility must not make, demand or receive:
(a) an unjust, unreasonable, unduly discriminatory, or unduly preferential rate for service provided by it in British Columbia, or
(b) a rate that otherwise contravenes the UCA, the regulations, orders of the commission or any other law.
Subsection 59(4) provides it is a question of fact, of which the Commission 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.
In accordance with subsection 59(5) 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.
Subsection 60(1) provides that in setting a rate under the UCA:
(a) The Commission must consider all matters that it considers proper and relevant affecting the rate,
(b)(iii) The Commission must have due regard to the setting of a rate that encourages the public utility to increase efficiency, reduce costs and enhance performance,
(b.1) The Commission may use any mechanism, formula or other method of setting the rate that it considers advisable.
3.2.2 Framework for the evaluation of Wires Demand Charges
The Panel noted in the Stage I Decision that consideration should be given to the following:
(i) Principles:
1. Economic efficiency: Stand-by Wires Charges should not discourage on-site generation that is fully economical and cost-effective but for the inclusion of Stand-by charges. Specifically, Stand-by charges should not be (i) so low as to promote uneconomic bypass of the grid or inefficient maintenance of customer owned generation assets, or (ii) so high as to discourage the growth of cost effective self-generation.
2. Fairness: cost-causation principles should be applied in assigning costs to differently situated customers. However, diametrically opposed interpretations of the user pay principle could make it difficult to justify a high or low Stand-by Rate design solely based on the fairness principle.
3. Consideration of BC Energy Policy: the Stand-by Wires Charge should take into consideration whether Stand-by Rates should be adjusted higher or lower to support BC energy objectives.
4. Simplicity and transparency: Stand-by Wires Charges should be easy to understand and administer, and designed so that prospective users can estimate what their charges will be, based on a few known cost determinants.
5. Stability: optimal Stand-by Wires Charges can vary between customers and over time. However, once set, Stand-by Wires Charges for a particular customer should not be subject to material changes (other than, for example, where there is a material change to the corresponding retail rate design) during the term of financing a generator project, usually 15-20 years.
(ii) Last contract demand of 16 MVA that the parties agreed to in the 2000 GSA.[12]
The Panel continues to find that the first three principles and the last contract demand in the 2000 GSA remain relevant considerations in determining an appropriate SBBD for Celgar. However the Panel considers that principle three is better categorized as a substantial consideration as discussed further in section 3.2.3.1.
With regard to principle four, the Panel agrees with FortisBC that RS 37 as approved by the Commission meets the test of simplicity and transparency because the rate is easy to understand and administer and is designed so that prospective users can estimate what their charges will be based on a few known cost determinants.[13] The actual determination of Celgar’s SBBD does not necessarily have to be simple as long as the use it will be put to is simple. Once set, Celgar’s SBBD will be applied to compute a simple and transparent rate in every billing period and therefore by definition this criteria has already been satisfied and it is not necessary to consider it in determining Celgar’s SBBD.
With regard to principle five, the Panel also agrees with FortisBC that the test of stability, like simplicity and transparency, is satisfied by RS 37 because the Panel has already determined in the Stage II Decision that the SBBD would ideally remain unchanged over the life of the investment in self-generation and therefore does not add to the determination of SBBD.[14]
3.2.3 Other Substantial Considerations
In section 3.8.1 of the Stage I Decision, the Panel established a framework for the evaluation of the Stand-by Rate design as it relates to the Wires Demand Charges. The Panel will continue to take these components into consideration in determining an appropriate SBBD for Celgar:
• Relevance of BC Hydro Stand-by Rate: The Panel maintains the view that “discrimination, when applied to rates for utility service, can only be of an ‘intra-utility’ nature and not ‘inter-utility’.” FortisBC’s Stand-by Rate cannot therefore be considered unfair or discriminatory solely on the basis of a comparison with the Stand-by Rate offered by BC Hydro.
• Single customer concern: The Panel maintains that the rate must be designed for all current and potential customers with self-generation but is aware that currently there is only one eligible customer for the proposed RS 37.
• Government policy (Clean Energy Act and the BC Energy Plan): In the Stage I Decision the Panel acknowledges the Government’s objective to promote energy conservation and efficiency, including self-generation throughout the entire Province. Therefore, the Panel considered that the Stand-by Rate should result in efficient customer investment and consumption decisions – specifically, efficient investment in, and operation of, distributed generation by utility customers and efficient investment in, and operation of, assets required to support the stand-by service by the utility. The Panel also found that the Stand-by Rate should promote innovation over time.
Divergent views in the design of Wires Charges: Advocates for self-generation seek minimal Stand-by Rates based on the premise that self-generation provides benefits in the form of deferred or permanent reduction in the need for utility provided generation, transmission, and distribution capacity.
3.2.3.1
Clean Energy Act and the BC Energy Plan and
their relevance
to a SBBD for Celgar
The question arises in this Stage IV Decision as to the degree of emphasis the Panel should place upon the BC Energy Plan and the Clean Energy Act (CEA) in its current deliberations on an appropriate Stand-by Billing Demand for Celgar.
The CEA, instituted in 2010, advances 16 specific energy objectives to help achieve British Columbia’s energy vision, including new measures to promote electricity efficiency and conservation by “foster[ing] the development in British Columbia of innovative technologies that support energy conservation and efficiency and the use of clean and renewable resources” and “to reduce waste by encouraging the use of waste heat, biogas, and biomass.”
Prior to the introduction of the CEA, the provincial government’s emphasis on the promotion of energy efficiency was articulated in both the 2002 and 2007 Energy Plans. Within the 2007 Energy Plan are two relevant policies: Policy Action #4: Explore with BC utilities new rate structures that encourage energy efficiency and conservation, and Policy Action #21: Ensure clean or renewable electricity generation continues to account for at least 90 percent of total generation.
The 2007 Energy Plan also states: “Government’s goal is to encourage a diverse mix of resources that represent a variety of technologies;” and “To close [the] electricity gap will require an innovative electricity industry and the real commitment of all British Columbian’s to conservation and energy efficiency.”[15]
FortisBC, in addressing the role of the BC Energy Plan, in its Stage IV Submission, observes that this criterion infers a benefit to self-generation on a provincial level and that it is difficult to put a value on it. In spite of FortisBC’s observation, FortisBC contends that the Stand-by Rate approved by the Commission has this policy consideration inherent in its design and no further reduction in costs is necessary in order to fulfill this objective.
Celgar, in its Stage IV Submission, observes that FortisBC argues the BC Energy Plan ought to be given little or no weight in the current decision. In effect, Celgar notes, FortisBC now argues that, since government policies were considered in the rate design process, no further consideration of government policies and the BC Energy Objectives should be undertaken. However, in the Stage II Decision, the Commission clearly stated that government policy was relevant to the determination of the Wires Charge.
It is Celgar’s position that:
There should be no doubt at this stage that the most significant of the Three Components for a self-generation customer is the SBBD. While government policies may have been considered in the design of RS37, given the significance to self-generation customers of the SBBD, and given the benefits of self-generation that the government has recognized in its policies and legislation, it should go without saying that such policies must continue to have application in establishing Celgar's SBBD.[16]
Celgar also indicates that in no prior instance of which it is aware has the Commission determined that once government policy has been considered in setting a rate design that such government policy should then be ignored in assessing the billing determinants under that rate design.[17]
In Its Stage IV Reply Submission, FortisBC makes no further comment with regard to the role of the BC Energy Plan and the determination of the SBBD.
While the Panel recognises, and agrees with FortisBC, that the BC Energy Plan was an inherent consideration in its earlier determination concerning RS 37, the Panel is also mindful that, as Celgar notes, in the Stage II Decision, the Commission clearly stated that government policy was relevant to the determination of the Wires Charge. For this reason, the BC Energy Plan and the Clean Energy Act remain live issues and will be considered in this ruling concerning the SBBD for Celgar.
3.2.3.2 Consideration of the divergent views in the design of Wires Charges
In the Stage I Decision the Panel noted that Stand-by Rates have often been contentious and offered the following concise overview of the long standing Stand-by Rate debate.
The installation of DG [distributed generation or self-generation] reduces utility power sales revenue, may cause the utility to incur costs for power purchases or losses on power sales for power expected to be used by DG customer, and reduces rate revenue from non-power related charges in rates (such as “wires” charges…), and so on. These costs would shift to other non-DC customers if the utility did not recover them specifically from the self-generating customer. This constitutes a subsidy of DC customers by other ratepayers. By the same token, DG systems provide potential benefits to the utility and, by extension other ratepayers. Accordingly, DG customers feel they are subsidizing the utility and other ratepayers…
Most parties agree that there should be a standby rate structure based on cost causation principles, meaning the rate should allow the utilities to recover all costs that the distributed generation [self-generation] customers impose on the system but nothing more. There is considerable disagreement, however, as to what costs and benefits the distributed generation project actually imposes on the system. Also, the parties dispute how and to what extent such costs and benefits should be incorporated into the standby rate structure. … Utility providers and distributed generation advocates vastly disagree over the factors that should be included in the standby rates.[18]
Advocates for self-generation seek minimal Stand-by Rates based on the premise that self-generation provides benefits in the form of deferred or permanent reduction in the need for utility provided generation, transmission, and distribution capacity.
Utilities, on the other hand, argue that the theoretical benefits for self-generation are insubstantial if located in an unsuitable area or operate erratically, and low Stand-by rates can result in self-generating customers avoiding infrastructure costs associated with back-up generation and wires services.
This contentious issue was addressed by the Ontario Energy Board. Page 30 of its 2000 Decision on a rate design application by Ontario Hydro (RP‐1999‐0044) states:
“Key aspects of the debate are the positions taken on the responsibility for sunk costs and the user pay principle. The diametrically opposed interpretation of the user pay principle in this case proved of little value to the Board in resolving the issue. To the proponents of gross load billing, the user pay principle means that the sunk costs of the transmission system must continue to be shared by those for whom the transmission capacity was built. For the proponents of net load billing, the user pay principle dictates that a customer should only pay for the services that the customer uses.”
The Panel will continue to bear in mind the Stand-by Rate debate in its deliberations on an appropriate SBBD for Celgar.
3.3 Positions of FortisBC and Celgar on setting a SBBD for Celgar
3.3.1 Synopsis of the positions
FortisBC submits that there is no basis on which to set the SBBD for Celgar at anything less than 100 percent of the SBDL or 42 MVA. This position is shaped by FortisBC’s view that Celgar’s generation does not provide identifiable net benefits to FortisBC or its other customers that would provide any basis for reducing the Wires Demand Charges for stand-by service from the level that would be set for other full service RS 31 customers.[19] The focus of FortisBC’s Stage IV Submission and Reply provided a rationale for this positon.
In reference to the negotiations that took place in April 2015 after the Stage II Decision, FortisBC put forward its final revised position and agreed to a SBBD of 75 percent of SBDL; however, at that time FortisBC reiterated that if the parties do not reach agreement they “reserve the right to take different position on these matters in this and any further proceedings if agreement was not reached.”
FortisBC confirms that the parties met to negotiate on June 16, 2015 in order to discuss the setting of a SBBD for Celgar in light of the Stage III Decision but advises that no agreement was reached.[20] FortisBC submits that, given the negotiation did not succeed, advantages of a negotiated resolution were not achieved and as such there is no reason to provide the discount that FortisBC contemplated in the negotiating context.[21]
Celgar submits that a SBBD of zero percent of SBDL is supported by regulatory precedent, the cost causation evidence, past brokerage agreements and Celgar’s decreased energy needs. However, Celgar submits it is willing to support an SBBD of 10 percent of SBDL and honour its first settlement proposal (in April 2015), as it is supported by expert evidence and “would represent a reasonable and acceptable application of wires charges to stand-by service.” In Celgar’s view, the resultant charge would fall within fairness norms, though perhaps on the high side. Finally, Celgar submits that a SBBD of 10 percent of the SBDL would also result in a rate that would allow Celgar to abandon work on its bypass project.[22] The focus of Celgar’s Stage IV Submission was not on providing a rationale for a SBBD of 10 percent of SBDL but rather on reply to FortisBC’s arguments.
Because the parties have not been able to come to an agreement and their respective positions are decidedly apart, the Panel is in a position where it needs to make a determination on Celgar’s SBBD. However, it should be noted that the divergent FortisBC and Celgar positions are not uncommon when utilities and self-generators endeavor to establish appropriate Stand-by charges.
In addition, it appears that both Celgar and FortisBC agree that ideally the rate structure should be based on cost causation principles – meaning the rate should allow FortisBC to recover the costs that Celgar imposes on the system but nothing more. However, consistent with the long standing debate between utilities and self‑generators, there is considerable disagreement on what costs and benefits Celgar’s self-generation actually imposes on the system.
The Panel will analyze the issue and related submissions in the following order:
• Cost causation principles (section 3.3.2);
• Cost recovery (section 3.3.3);
• Benefits of Celgar’s self-generation to FortisBC and other ratepayers (section 3.3.5);
• Planning reserve margins (section 3.3.6);
• Availability of stand-by service (section 3.3.7);
• Significance of past brokerage agreements (section 3.3.8).
3.3.2 Cost Causation principles and fairness test
Sections 59 and 60 of the UCA provide guidance to rate setting, and require that due regard be given to ensuring that rates must not be unjust, unreasonable, unduly discriminatory, or unduly preferential. The cornerstone of fair rate setting is the comparison of revenues collected from each class of customer with the cost of providing service to them. A Cost of Service Analysis (COSA) is a means of equitably allocating the revenue requirement of the utility to the various customer classes and takes account of cost-causal factors of specific customer classes. The revenue-to-cost (R/C) ratio becomes an important measure used to assess the fairness of rates established for each customer class.
In its Original Application, FortisBC did not submit COSA based evidence to support its proposed Stand-by Rate but stated “the FortisBC proposal ensures that adequate cost recovery is maintained from self-generating customers by utilizing the demand charge provisions of the underlying rate which includes a Contract Demand provision.”[23] Only after Celgar filed expert witness evidence did FortisBC provide some cost based justification by way of a rebuttal evidence. The FortisBC proposal is assessed here with reference to the Stage II Decision which specified that the Stand-by Billing Demand is to be established between the customer and the utility at an amount somewhere between zero and 100 percent of the customer’s Stand-by Demand Limit. The reasonableness of the FortisBC proposal is addressed below.
3.3.2.1 The Stage I Proceeding
It should be noted that although the issues and positions of the parties have evolved since the review of the Original Application, the following submissions are included to provide further context.
FortisBC Submissions – February 24, 2014
Fortis submits the higher principle of cost causation is that customers should be responsible through rates for the costs they impose upon a utility system. With reference to cost allocation mechanics, FortisBC argues that the allocation of a portion of costs using a customer class’s contribution to system peak load is a mechanism used to assign costs, not the principle it supports. FortisBC explains that historically, in the COSA methodology, such an allocation is used because it produces results that are consistent with the higher principle. However, when self-generation becomes a consideration, the situation is no longer typical as the customer’s contribution to system peak may no longer represent the operation of the load, and is not reflective of the demands that the customer will place on the system, and therefore the required infrastructure and related costs.[24]
FortisBC further submits that a self-generating customer that chooses to serve a portion of load from its own resources has the opportunity to reduce its energy related costs by replacing utility supply with low cost self‑generation. It should not also, however, be able to avoid the costs associated with the provision of the infrastructure required to support the self-generator loads during periods when self-generation is unavailable.[25]
Celgar Evidence– March 7, 2014
Celgar states it is in an untenable position because under Order G-48-09 the Commission effectively directed Celgar to use its self-generation assets first to meet its own load. Celgar submits it is unfair and unjust both to require Celgar to self-supply and also to compel Celgar during periodic outages to take firm service under RS 31 intended for full service customers. Celgar submits that such a regime subjects it to the worst of two worlds and that in no circumstances should Celgar be required to both self-supply and pay for firm service.[26]
In Celgar’s submission it is “unjust, indeed punitive, to compel Celgar to self-supply and also to impose upon Celgar increased charges related to doing so.”
Relevant Expert Evidence Filed
Dennis. J. Fitzgerald for Celgar – Nature of Service
To assist the Commission in its review of the appropriate Stand-by Rate for Celgar, Mr. Fitzgerald described the nature of service that is most appropriate for pulp mills in British Columbia, including the Celgar mill as follows:
“Most pulp mills, when losing their self-generation units in scheduled or forced outages, are able to maintain pulp-making operations to a degree, and standby service that is non-firm but generally available is well-suited to supply electricity that would otherwise have come from the self-generation unit. In the rare event that standby service is not available, pulp-making can resume once the system constraint that prevented the standby power from being supplied has been removed, and production losses will be minimal.”[27]
Mr. Fitzgerald summarized his conclusion by stating that non-firm service for Stand-by supply is perfectly adequate as pulp mills with internal generation normally have some degree of flexibility in their operations in circumstances where their internal generation is not available.[28]
Joe N. Linxwiler, Jr. for Celgar – Cost causation
Mr. Linxwiler provided testimony in regard to the pricing of the stand-by service proposed by FortisBC. He stated that a proposed pricing is excessive and unjustified because:
(i) It is not based on legitimate system planning considerations,
(ii) It does not properly match capacity and energy prices,
(iii) The demand-related rates for the proposed service have not been shown to be appropriate and are likely to be quite excessive, and
(iv) Certain other aspects of the proposed rate are not cost-based or adequately justified.[29]
Rebuttal Testimony of Gary S. Saleba on behalf of FortisBC
Mr. Saleba stated that the proposed demand related provisions are necessary to protect the utility and its customers from the potential for stranded assets associated with significant risks for a large industrial customer. Mr. Saleba identified those risks as including the potential for reduced load (full or partial) associated with economic conditions or poor management of the company as well as the risk of bankruptcy and the inability to pay its bills.[30]
3.3.2.2 Stage IV Proceeding
FortisBC’ Stage IV Submissions – June 19, 2015
FortisBC submits it continues to support the well-established utility ratemaking principle that rates should be cost-based. In FortisBC’s view rates for both conventional delivery service and stand-by service must be aligned with costs to allow the Company the opportunity to recover its costs for providing utility service. In this regard, FortisBC submits the Stand-by Rate seeks to recover costs associated with serving self-generators at their full contractual obligation; but not on their peak loads. Furthermore, FortisBC points out self-generating customers that take service infrequently may not provide sufficient revenue to the Company to cover the costs to serve them, in which case they would be subsidized by the other customers. FortisBC further argues the cost to serve Stand-by and continuous-use customers [full service] is the same, but the potential for rate recovery of the cost of service is quite disparate.[31]
FortisBC refers to the discussion of Fairness, in both the Stage I Decision and the NRRI Paper, which considers making rates just and reasonable for both customers and utilities. This entails the use of sound cost-causation principles; the recognition of both costs and benefits provided by self-generation customers which the NRRI Paper suggests should include assigning benefits and costs to all the various services that together comprise the full relationship between a utility and self-generating customer.
FortisBC also notes that, in assigning benefits and costs, fairness should consider the impact to both individual partial-requirements customers and to the class of such customers if it exists. In that regard, the Commission has described the lack of a class of Stand-by customers at FortisBC as the “Single Customer Concern,” noting that Celgar is the only such customer.
From the fairness perspective, FortisBC submits the Commission must also include consideration of other customers that may have a load profile similar to that of Celgar, but for a lack of self-generation do not have an option to reduce costs in a manner provided by RS 37. For example, FortisBC explains, a customer with a low load factor due to seasonal demand, such as a fruit packing house, may take full service with a high load factor for only one to two months a year and then pay demand charges based on a ratchet for the remainder of the year. FortisBC argues the intermittent nature of the load may be indistinguishable from that of a customer with self-generation.[32]
Celgar Stage IV Submissions – July 10, 2014
Celgar submits that the above FortisBC proposition shown in italics is “the foundation for FortisBC’s 100% proposal.” Celgar argues that if this proposition fails, the 100 percent Proposal fails and that it “must fail because FortisBC has failed to file any relevant evidence in support of it.” Celgar submits the only expert evidence before the Commission is that of Mr. Linxwiler which shows that the cost to serve Stand-by customers and continuous-use customers is different.[33]
Celgar observes the last time FortisBC filed expert evidence relevant to cost causation principles was in its 2009 Rate Design and Cost of Service proceeding. Celgar points out the COSA filing did not include an analysis of the cost of service under a Stand-by Rate schedule. Celgar then refers to FortisBC comments regarding seasonal customers. Celgar submits the cost of service to seasonal customers may justify a rate design unique to seasonal customers, which is a matter for a rate design proceeding. Celgar concludes that unless FortisBC proposes that a seasonal customer and self-generation customer be in the same rate class, the reference to seasonal customers should be disregarded.[34]
Celgar also reintroduces the matter of planning criteria and notes the Commission’s earlier view that planning criteria should be based on the request for service from the customer. Further, Celgar reminds parties that in the Stage I Decision the Commission emphasized that FortisBC should not significantly alter the amount of firm service used in system planning without consulting the customer affected. Celgar submits “Now that the Commission has determined that, for both RS 31 and RS 37 service, the customer determines the level of service, the FortisBC’s planning criteria and the customer’s service under RS 31 and RS 37 will be aligned.[35]
In the planning context, Celgar also highlights the significance of the penalty provisions, nominations and curtailment of load. Celgar acknowledges that once the customer requests a level of service, FortisBC need not provide service in excess of that requested. In fact, Celgar points out, the customer will be penalized for taking service in excess of the nominated RS 31 Contract Demand and SBDL. Celgar also states it has the option to curtail load before penalty provisions are triggered and believes that load curtailment is relevant to the SBBD.[36]
Finally, Celgar submits the purpose of the Wires Charge should not be to recover sunk costs. Celgar argues that if FortisBC has overbuilt the transmission infrastructure to Celgar, FortisBC should not now be given an opportunity to recover those costs. Such sunk cost recovery would not be consistent with the current cost of service model, which forms the fundamental premise of COSA.[37]
FortisBC Stage IV Reply Submission – July 24, 2015
With regard to the issue of supporting evidence and cost causation, FortisBC argues cost causation is not the foundation for its 100 percent proposal. However, FortisBC submits cost causation is the foundation for its previously approved rates, and the Commission has further considered all the evidence before it in this review process in approving the RS 37. FortisBC further submits that it is appropriate to apply Wires Demand Charges in its service area as they have been approved by the Commission, most recently in the 2009 COSA and RDA. Specifically, FortisBC argues “there is no basis to suggest that Wires demand Charges for Celgar taking service utilizing the Stand-by Rate should be any different than those applicable under its current means of service.” Only if it were seeking to fundamentally change the manner in which it recovers wires costs from Celgar, FortisBC submits, then it might have to justify how that change is reflected in rates. Accordingly, FortisBC strongly disagrees with Celgar’s starting point for the SBBD to be set at zero. FortisBC submits all of its customers contribute to system costs and these charges have already been approved by Order G-156-10.[38]
In reply, FortisBC argues that Celgar has not substantiated the relevance of load curtailment to the SBBD. FortisBC submits that the ability to curtail load provides no benefit related to the Wires Demand Charges, although it may be of benefit from a power supply perspective.[39]
3.3.3 Cost Recovery
COSA
FortisBC explained that Celgar was originally included in the 2009 COSA within the industrial class with a coincident load of 12,000 kVA. However, by Order G-196-10, the Commission directed FortisBC to re-run the 2009 COSA using 8,000 kVA, rather than 12,000 kVA used in the original compliance filing.[40] FortisBC stated that directive led to a significantly lower allocation to the transmission class than if the full 40 MVA load of Celgar had been included. Accordingly, FortisBC stated the transmission costs allocated to all transmission customers, and the resulting demand charge is already lower as a result.[41]
FortisBC further explained that, in general, transmission infrastructure costs are allocated and corresponding rates set, in reference to the peak loads of the transmission customers. To the extent that rates are set in order to generate revenue based on the peak demands of customers, and FortisBC is only able to bill based on the 80 percent ratchet of Contract Demand, there will be an under-recovery of those costs.[42]
FortisBC has not performed a separate COSA in support of the Stand-by Rate and stated that the 2009 COSA forms the basis of the charges in the Stand-by Rate schedules, noting that the Stand-by Rates are a combination of the transmission charges from the existing Commission-approved tariff [RS 31] and energy charges that are market based.[43]
Planning purposes
In the decision attached to Order G-188-11 the Commission highlighted that FortisBC had changed its system planning criteria in 2010 to be based on Celgar’s actual historical demand, rather than on the 16 MVA that was the contract demand in the 2000 GSA. FortisBC “… commenced using 40 MW for the Celgar load in recognition of the fact that many times in previous years the actual recorded peak demand at the facility was much greater than the 16 MW value which had been used previously.” The Commission emphasized that FortisBC should not significantly alter the amount of firm service used in system planning (which in turn affects COSA) without consulting the customer affected. The Commission Panel considered that, if the two transmission lines serving Celgar are lightly loaded, the outcome of its system planning will likely be unaffected by whether 16 MVA or actual historical demand were used as the load remains below capacity.[44]
Further, Order G-188-11 also directed FortisBC to submit an application by May 31, 2012 for a Stand-by Rate designed to address Celgar’s circumstances and also to address how the Stand-by Rate takes account of its system planning criteria. [emphasis added]
Sunk and incremental costs
In regard to fixed costs (sunk costs) recovered though the Wires Demand Charges, FortisBC states that Celgar’s load led to Fortis BC building the necessary infrastructure[45] that is now included in the fixed transmission costs. FortisBC also states that it is unable to locate any record regarding who paid for the transmission lines between Castlegar and Celgar. The Company expects that these lines would have been constructed and funded similar to the current practice for other customer extension projects where the extension infrastructure is constructed by the Company with the cost of construction being fully offset by Contributions in Aid of Construction (CIAC).[46]
Celgar acknowledges that the transmission system serving its mill goes beyond Celgar’s mill and also serves other loads, including another industrial customer and is sized to serve the peak load of all loads connected to the transmission system, including Celgar’s mill. Celgar also pointed out that at the time of the mill’s original construction, the mill paid for and was the original owner of the transmission lines to the mill, and later transferred ownership to the utility.[47] Celgar further states that although it has not paid for the entire transmission infrastructure to service its load, it did pay for the upgrades to that infrastructure when the new self-generation was added.[48]
In regards to incremental system requirements necessary to provide stand-by service, FortisBC states that other than the metering requirements for determining generator output and plant load, there are no particular physical system requirements for stand-by service.
3.3.4 Overall Commission Determination on Cost Causation
Commission determination
Rate Schedule 31
First, the Panel wishes to highlight the difference between Wires Demand Charges for a RS 31 customer and those for a RS 37 customer. Wires Demand Charges for RS 31 customers are based on ‘Billing Demand’ which is the greatest of three ratchets[49] and may vary from month to month based on the actual demand the customer puts on the system. On the other hand, SBBD for RS 37 is set once and remains the same every month. These are fixed charges, regardless of how much demand a customer puts on the system and cannot be reduced regardless of any innovations a customer makes to reduce the amount of Stand-by energy it requires.
The FortisBC position which requires Celgar to pay a SBBD of 100 percent of SBDL would result in Celgar paying a Billing Demand of 42 MVA for RS 37 service plus a Billing Demand of 3 MVW for its Contract Demand under RS 31.
In Stage I Decision, FortisBC proposed Special Provision No. 2, which would have required Celgar to pay Wires Charges based on a maximum peak demand of approximately 45 MVA. This virtually represented the maximum, conceivable Wires Demand Charges that could be charged to a customer. In the Stage 1 Decision, the Panel found that the inclusion of Special Provision No. 2 was unnecessarily restrictive and would have resulted in a rate that was unjust, unreasonable and unduly discriminatory. In the Stage II Decision FortisBC proposed the concept of Adjusted Contract Demand which the Panel found to have very similar implications to the Special Provision No. 2 proposed in Stage I, and rejected it and replaced it with the Three RS 37 Components.
FortisBC proposal for a SBBD set at 100 percent of SBDL results in virtually the same outcome as proposed and rejected by the Commission in both the Stage I and Stage II Decisions.
Second, the Panel considers the FortisBC position that Celgar should only have a reduction to its SBBD if there are any benefits to FortisBC or its customers through providing service to Celgar utilizing the Stand-by Rate (RS 37) as opposed to serving Celgar fully under RS 31 alone. FortisBC argues that as there is no change in the infrastructure requirements in any of the service options for Celgar, it would be inappropriate to reduce the RS 31 Wires Demand Charges on that basis.[50]
The Panel disagrees with the manner FortisBC frames the primary question. FortisBC is simply comparing the difference between taking stand-by service under RS 37 in combination with RS 31 or taking service under RS 31 alone. FortisBC is arguing that Celgar should pay the same Wires Demand Charges (or more) as would a continuous use customer under RS 31. FortisBC was directed by the Commission to design a Stand-by Rate for Celgar to ensure that the appropriate rates would be charged for the service Celgar was receiving.
For these reasons the Panel determines that RS 37 stand-by service is different than continuous use or full service under RS 31 and rejects FortisBC’s argument that Celgar, as a Stand-by customer, should pay the same Wires Demand Charges as a full service RS 31 customer.
Benefits reflected in RS 37
With regard to the approved design of RS 37, FortisBC has argued that a self-generator should not be able to avoid the costs associated with the provision of the infrastructure required to support the self-generator loads during periods when self-generation is unavailable (SBBD should be based on 100 percent of SBDL) for the following reasons:
• The design of RS 37 provides a self-generator with the opportunity to avoid the peak-demand based billing and purchase energy at the market rate which is a departure from normal billing under other rates and is an advantage for the self-generator.[51]
• The bill reduction already afforded through the structure of the approved RS 37, without consideration of the Wires Demand Charges, appropriately balances the interest of the entire customer and any future reduction of the SBBD cannot be justified.[52]
• The provision of the Stand-by tariff that allows for the setting of the SBBD between zero and 100 percent of the SBDL recognizes the Government’s objective of the promotion of self-generation. However, the Stand-by Rate approved by the Commission has this consideration inherent in its design and no further reduction in costs is necessary in order to fulfill this objective.[53]
FortisBC further states that a self-generating customer that chooses to serve a portion of load from its own resources has the opportunity to reduce its energy related costs by replacing utility supply with low cost self‑generation.[54]
The Panel wishes to clarify an apparent misunderstanding that FortisBC is basing part of its argument on. In the Stage I Decision the Panel stated “Stand-by Contract Demand [changed to SBBD in the Stage II Decision for clarity] would then be established to reflect the benefits of self-generation…” The Panel further explained that “given the limitation of a one size fits all network services charge concept, the Panel considers it more appropriate to use a principle based approach to identify the benefits of self-generation.”[55] Clearly any benefits of self-generation were to be recognized through the SBBD and not through the design of the other components of the rate.
Furthermore, the fact that the energy charge in RS 37 is set at market rates is not, in and of itself, a benefit to the customer. Any benefit or cost is highly dependent on what the market rate is, compared to the embedded cost rate, at the time the customer required stand-by service.
Likewise the fact that a self-generating customer can choose to serve a portion of its load from its own generation, which it paid for and must maintain, is not in and of itself a benefit either.
For these reasons the Panel determines that the benefits of self-generation are to be reflected through the SBBD as they are not reflected through the other components of RS 37 as suggested by FortisBC.
Cost Causation
The Panel understands that any Celgar specific costs would have been directly allocated to Celgar and recovered from Celgar through FortisBC’s interconnection policy. The costs that are recovered through the Wires Demand Charges are the remaining sunk costs of the system that FortisBC considers are driven by peak demand rather than energy consumed.
The FortisBC COSA allocates these demand related sunk costs among the different customer classes based on peak demand. The Panel appreciates that the COSA did not allocate costs to a specific rate or for that matter a specific customer within the class, but rather to the entire class as a whole. As such, assuming that a SBBD of 8,000 kVA for Celgar would allow FortisBC to recover Celgar’s fair portion of wires costs is an over simplification. However, the Panel does find the 8,000 kVA peak demand indicative – and certainly a SBBD of 42 MVA would significantly over recover Celgar’s fair portion of Wires Demand Charges.
In regards to planning reserves – which drive costs allocated thorough the COSA - the Panel notes that FortisBC has been using 40 MVA since 2010 which could result in an increase in costs that need to be recovered. The Commission has said on more than one occasion that FortisBC should not alter a customer’s firm service used in system planning without consulting the customer affected. In the Decision attached to Order G-188-11 the Commission considered that, if the two transmission lines serving Celgar are lightly loaded, the outcome of its system planning will likely be unaffected whether Celgar’s proposed 8 MVA, the historical 16 MVA, or actual historical peak demand were used as the load remains below capacity. Further, the Panel is surprised that FortisBC did not address in any detail how the Stand-by Rate takes into account its system planning criteria.
Celgar dilemma
The Panel considers that generally costs should be allocated, through rates, to those customers that cause them; however, those rates must meet a test of reasonableness. The Panel agrees with Celgar that it has been put in a difficult situation.
First, due to net-of-load criterion Celgar must self-supply and, therefore, it requires only stand-by service for back-up and maintenance and is not entitled to receive full time service to serve its entire load. Celgar’s requirements clearly are quite different from those of full service customers. At the same time, FortisBC has proposed to charge Celgar for the Wires Demand Charges provided in accordance with pricing used for full service customers, which Celgar would like to be, but because of the net-of-load environment it is not allowed to be.
Second, Celgar’s dilemma is further complicated by the fact that at the moment it is the only self‑generating customer of FortisBC and therefore has no other customer with similar requirements to form a new customer class for self-generating customers.
Third, as a rule, the Panel would expect the utility in consultation with its customer to determine the customer service requirements. Only after the requirements have been determined, the cost of service should be estimated. In the case of Celgar, it appears that FortisBC unilaterally concluded that the service provided to Celgar was from cost point of view similar to full service. It did not consult Celgar to determine how Celgar can accommodate FortisBC system in order to minimize the burden imposed upon it.
Deficiencies in FortisBC’s Evidence
It is up to the applicant, FortisBC, to demonstrate that the proposed rate is fair in accordance with sections 59 and 60 of the UCA. The test of reasonableness allows for some discrimination in rates, but only within a range of reasonableness. The Panel notes the following weaknesses in the FortisBC evidence:
First, FortisBC has not performed a separate cost of service analysis in support of its Stand-by Rates. FortisBC stated it completed a COSA in 2009 that forms the basis of the charges in the stepped and transmission rate schedules. FortisBC further stated the Stand-by Rates are a combination of the transmission charges from the existing Commission-approved tariff and energy rates that are market based.[56] Ideally, there should be a separate customer class provided for Stand-by customers as the nature of service is different from that provided to full service customers. Since FortisBC currently has only one self-generator in need of a Stand-by Rate, and has not performed a COSA since 2000, Celgar is in the same class with the other transmission voltage customers.
Second, today (in 2015) the 2009 COSA may be somewhat out of date. For instance, the FortisBC rate design expert explained that for Celgar the average use level was based on three years of actual data prior to the 2009 test year for COSA.[57] In addition to Celgar starting to comply with the net-of-load rule resulting from Order G‑48‑09, other customers’ load profiles may also have changed since.
Celgar was included in the 2009 COSA within the industrial class with a coincident load of only 8,000 kVA based on the historic data and a specific Commission directive contained in Order G-196-10. That led to a much lower allocation to the class than if the full 40 MVA load of Celgar had been included. For that reason the transmission costs allocated to all transmission customers, and the resulting demand charge is already lower as a result.[58]
Third, FortisBC has not provided any evidence on the actual cost of providing Stand-by Service. For instance, the Panel does not have evidence on the actual cost of back-up service provided to Celgar since 2009 – either in terms of operating or capital costs. The Panel accepts that it may be difficult to do so with only one self‑generator customer. Regardless, due to lack of any specific cost based evidence the Panel has difficulty accepting FortisBC’s justification for charges proposed for Celgar. In this regard, the Panel also notes the lack of discussion on planning criteria that should reflect the request for service from the customer. Similarly, FortisBC has not addressed the treatment of sunk costs in the context of Celgar which is a long-time customer.
Other Considerations
FortisBC raised the case of a fruit packing house as a customer with similar load profile but did not provide a compelling rationale as to its relevance to the Celgar context. The Panel agrees with Celgar that unless FortisBC proposes that a seasonal customer and self-generation customer be in the same rate class, the reference to seasonal customers is not relevant.
The Panel disagrees with the FortisBC expert witness who stated that the intermittent Stand-by load is no different than an industrial customer without generation that must pay for the capacity it uses in every month regardless of whether or not it occurs at the time of the system peak. Celgar is being put in a difficult position as there are no other self-generators in the service territory allowing for diversity and laws of probabilities. The Panel finds that it is not fair and reasonable to apply the pricing approach that is used for full service customers. Intermittent service cannot put the same burden on the system. The Panel cannot accept the FortisBC Reply Submission (Exhibit B-42) that “there is no basis to suggest that Wires Demand Charges for Celgar taking service utilizing the Stand-by Rate should be any different than those applicable under its current means of service.”
Because of the significant penalties now approved for Stand-by customers, the demand charge need not act as the incentive (punishment) for the customer to provide for adequate maintenance. The Panel acknowledges the FortisBC position that “demand charges are intended to give large users strong incentives to manage their peak demand most efficiently, thus minimizing the investment in facilities that the utility must make on their behalf.”[59] However, the Panel notes that Celgar can schedule the maintenance shut-downs to accommodate FortisBC but accepts that the unscheduled back-up service cannot be managed to the same degree. The Panel also considered the nature of service as described by Mr. Fitzgerald: “Most pulp mills, when losing their self-generation units in scheduled or forced outages, are able to maintain pulp making operation to a degree…” Therefore, the Panel is not persuaded by the FortisBC’s emphasis on high demand charges in the case of Celgar.
Furthermore, based on the 2009 COSA, a Celgar peak load of 8,000 kVA was used to determine costs allocations to the transmission class. Although a direct relationship cannot be drawn between the SBBD and the peak load allocation it clearly is indicative that a SBBD of 42 MVA would significantly over recover Celgar’s fair portion of wires costs.
Based on the above considerations, the Panel determines that FortisBC has failed to justify its proposal for use of 42 MVA SBBD for Celgar as the basis for Wires Demand Charges in the Stand-by Rate. The FortisBC proposal is therefore rejected as it would result in a charge that is unjust, unreasonable, and unduly discriminatory.
The Panel regrets to find in this regard that Celgar also has failed to make a sufficiently persuasive case for its proposed SBBD based on 10 percent of SBDL.
3.3.5 Benefits of Celgar’s self-generation to FortisBC and other ratepayers
FortisBC argues that the primary question to be asked in assessing the value of Celgar’s self-generation, and whether there is a basis for discounting the SBDL in determining the SBBD, is whether or not there is any benefit to FortisBC or its customers by providing service to Celgar utilizing the Stand-by Rate (RS 37) as opposed to serving Celgar under the full service RS 31.
FortisBC argues that as there is no change in the infrastructure requirements in any of the service options for Celgar, and it would be inappropriate to reduce the Wires Charges on that basis.[60] FortisBC further argues it would be unfair to all other customers to permit self-generators to avoid paying infrastructure related demand charges on the same basis as a continuous use, or full service, customer under RS 31 simply due to the presence of self‑generation. FortisBC emphasizes that all other customers with a demand-related billing component are required to pay a demand charge regardless of how often, or even if, the maximum demand is recorded during a billing period.[61]
FortisBC also points out that Celgar has
had self-generation installed at its plant, capable of serving its entire load,
since the early 1990s and that Celgar has installed since 2010 additional
generation capability for the purpose of exporting power. FortisBC argues that
the implementation of RS 37 will not impact the installation of generation at
Celgar because the plant load is already fully covered and no further
generation can be added that
will require the availability of stand-by service. FortisBC also argues the discouragement of on-site generation that is fully economical and cost-effective cannot properly be a consideration for Celgar, where load serving generation has been in place and providing a benefit to Celgar for decades.[62]
Challenging the above submissions, Celgar argues that FortisBC’s position rests entirely on the premise that the implementation of RS 37 will not impact the installation of generation at Celgar. Celgar submits “This approach is opportunistic. It attempts to poach for FortisBC the benefits of Celgar’s self-generation based solely upon timing relating to when such generation was installed. It is unfair to Celgar as an early innovator.”[63]
With regard to the FortisBC reference to load serving generation that has been in place and “providing a benefit to Celgar for decades,” Celgar again emphasizes the importance of looking at an issue from both sides. Celgar submits that while load serving generation has admittedly benefited it for decades by way of return on its investment, the same generation has also benefited other FortisBC customers for decades, who have no investment in the assets. In support of this argument, to illustrate the value of Celgar’s self-generation to other customers, Celgar paints a scenario where it shuts its generation down while continuing to run the pulp mill. In this scenario Celgar becomes a full service customer of FortisBC for its entire load. Assuming the long run marginal cost (LRMC) for FortisBC of $114/MWh, the RS 31 Energy Charge of $46/MWh (a difference of $68/MWh) and annual load of 360,000 MWh, Celgar calculates an additional cost of $24.5 million that would have to be recovered from all ratepayers annually.[64]
FortisBC replies that the above scenario provided by Celgar misses the point of the current review process, which is not about the impact of shutting down its generation and becoming a full load customer. FortisBC submits that whether or not Celgar shuts its generation down or continues its current mode of service, or takes stand-by service, has no impact on the infrastructure required to serve it. In the view of FortisBC the scenario supports the fact that the Wires Demand Charges should remain as they are rather than being reduced.[65]
Commission determination
In its Stage I Decision the Panel discussed setting Stand-by Wires Charges at some length and concluded that determining the appropriate Wires Demand Charge for stand-by service is more of an art than science. Therefore, the Panel in this decision adopts a broader perspective than the narrow one that FortisBC has presented in its submissions.
In addition to considering the impact on current infrastructure requirements, the Panel agrees with Celgar that to be fair, one must consider two sides of the same coin and will also consider Celgar’s argument where it shuts down its generation and becomes a full service customer of FortisBC. As well, the Panel will consider another scenario where Celgar stops entirely taking any service from FortisBC.
Furthermore, the Panel adopts a longer time horizon than the one adopted by FortisBC which appears to argue its case by considering the status quo in the FortisBC service territory and projecting the current state affairs into the future. Instead, the Panel will also take a step back to consider the time when Celgar installed its self‑generation capabilities and started to self-supply some of its load. The Panel agrees with Celgar that FortisBC’s approach unfairly ignores Celgar’s prior investment as “an early innovator.” The Panel considers that overlooking the history would take unfair advantage of Celgar facilities as a captive investment. The Panel stated in the Stage I Decision that it would treat an existing customer differently than the future customer specifically for this reason.
Celgar paints a scenario where it becomes a full service customer of FortisBC. In order to quantify the benefits that have been provided to the FortisBC system and the ratepayer, Celgar compares the RS 31 embedded cost of energy to service Celgar’s entire load to the long run marginal cost of energy to FortisBC of $0.114/kWh. The Panel is aware that no evidence was provided to support the LRMC proposed by Celgar but finds it to be reasonable given the range of LRMC’s provided by FortisBC in the evidence is in the range of $0.098 to $0.1047.[66] Under the assumption that the incremental cost over the long term to supply an additional load is $0.114/kWh, FortisBC ratepayers benefit of a savings of approximately $22 million.
FortisBC has stated that every customer would be worse off even if the load were supplied at the margin.[67] However, in providing its evidence to support this position FortisBC seems to have compared service at the currently approved Stand-by Rate to service under the LRMC. This resulted in a loss to FortisBC’s customers which would be expected as the Stand-by Rate is based on a market rate. As such, the loss in revenues relates to the fixed costs only.
As an order of magnitude exercise, in order to better understand Celgar’s and FortisBC’s position, the Panel also chose to compare the Wires Demand Charges to the energy charge under Celgar’s proposed scenario. As demonstrated in the table below energy charges would be approximately $18.8 million and the recovery of Wires Demand Charges would be $2.3 million.
Under the scenario where Celgar continues to receive service strictly on a net-of-load basis, FortisBC’s total charges under RS 31 would be approximately $4.5 million and the recovery of the same Wires Demand Charges of $2.3 million.
The Panel draws two conclusions from this analysis. First, under the LRMC assumption put forward by Celgar, Celgar does provide a benefit to the FortisBC system and its ratepayers. However, the Panel also acknowledges the use of the LRMC analysis has its limitation as it has the benefit of hindsight. Further, there is the assumption that over the long term the market rates will be higher than embedded costs rates and incremental supply will have to be obtained from other sources at the LRMC. In reality that has not always been the case.
The Panel also finds that the reply analysis put forward by FortisBC is flawed as a comparison to service under RS 37 is not relevant. Celgar would not be a Stand-by RS 37 customer under a scenario where its full load was serviced by FortisBC.
Second, as an order of magnitude, the fixed costs (Wires Charges and Power Supply Charges) pale in comparison to the energy changes under the scenario where FortisBC is servicing Celgar’s full load. SBBD under 0 percent, 10 percent and 100 percent of SBDL are presented in the table below.
Under the scenario where Celgar were to discontinue taking service from FortisBC all together there would be no contribution to the fixed Wires Demand Charges at all.
In conclusion, the Panel finds that there are likely some benefits that Celgar’s self-generation has provided and continues to provide to FortisBC and other ratepayers but those benefits cannot readily or directly be translated into a formula that results in setting a SBBD for Celgar. However, it is another clear indication that FortisBC’s 42 MVA proposal is not appropriate.
To assist the Panel in reaching its final determination the Panel will now evaluate and consider what the SBBD would be on the basis of planning reserve margins, availability of stand-by service, and the last contract demand agreed to by the parties.
3.3.6 Planning reserve margins
With regard to system planning considerations, FortisBC states that in the case of self-generating customers, the load modeled in the power flow data used for system studies is the full load that the customer may impose upon the FortisBC system. For Celgar, this is the 45 MVA that has historically been recorded. FortisBC further states it must maintain infrastructure that is capable of servicing the full load, regardless of how intermittent that load may be. FortisBC also notes that as the timing of the load is unpredictable, transmission and generation capacity must be available at all times in order to ensure that backup loads are fully met.[68]
Testimony of Mr. Linxwiler on behalf of Celgar
The testimony of Celgar’s expert witness, Mr. Linxwiler, criticized this approach as highly misleading because it implies that FortisBC will dedicate 100 percent reserves for customers’ capacity. Yet, Mr. Linxwiler stated that FortisBC does not (or should not) plan reserves for its own capacity in this manner and therefore it should not plan for reserves for customer-owned generation in that manner. Mr. Linxwiler explained that FortisBC and other utilities are able to maintain less than 100 percent reserves because of diversity and the laws of probabilities and likelihoods.
Mr. Linxwiler further elaborated as follows:
Not only are industrial-grade electric generators quite reliable, but the likelihood of large amounts of capacity being unavailable simultaneously is quite low. This is because maintenance outages are, or should be, planned to largely avoid peak load periods and simultaneous outages. Besides, the risk of multiple generators experiencing so-called forced outages at the same time is quite remote. While forced outages are random by nature, the average amounts of capacity that will likely be unavailable are quite predictable. Hence, utilities are generally able to provide reliable service with reserve margins much lower than 100 percent. Actual planned reserve margins are typically in the range of 10-20 percent. Thus, a reasonable Stand-by capacity charge would reflect only the planning reserve margin applied to the load served by the self‑generation customer.[69]
Rebuttal Testimony of Gary S. Saleba on behalf of FortisBC
Mr. Saleba acknowledged that basing Stand-by charges to the reserves associated with the service provided “is not an uncommon practice and would be an alternative approach for capacity charges in a Stand-by Rate.” He notes, however, that the approach would need to reflect the actual circumstances of the utility and the customer. [70]
Mr. Saleba also pointed out that while
diversity is accounted for in calculating reserve margins, the fact is that the
Celgar generation is not included in a large mix of other self-generators that
can reduce the Stand-by requirements through diversity, as is the case for BC
Hydro and many other utilities. Celgar is the only generating unit and it
requires capacity from FortisBC in nearly every month. Mr. Saleba stated this
intermittent Stand-by load is no different than an industrial customer without
generation that must pay for the capacity it uses in every month regardless of
whether or not it occurs at the time of the system peak. Mr. Saleba finally
stated that the demand charge was designed to give the appropriate incentive for the customer to provide adequate maintenance to ensure a reliable generating unit, and to deter the customer from using the Stand-by Rate as an economic alternative in place of operating unit.[71]
Commission determination
Both parties’ expert witnesses agree that actual planned reserve margins are typically in the range of 10‑20 percent and that basing stand-by charges to the reserves associated with the service provided is not an uncommon practice and, therefore, would be an alternative approach for setting wires charges in a Stand-by Rate. The Panel finds that under this approach Celgar’s SBBD at 10 percent to 20 percent of SBDL of 42 MVA would be in the range of 4.2 MVA to 8.4 MVA. The Panel appreciates Mr. Saleba’s reservations with setting Celgar’s wire charges in this manner; nevertheless, the Panel will take this approach into consideration.
3.3.7 Availability of stand-by service
To test the order of magnitude, if the Panel assumes that in one calendar year Celgar uses the maximum maintenance power service allowed of 60 days as well as the maximum allowed back-up service of 876 hours, the total power service will translate into 2,316 hours in the calendar year (60 days x 24 hrs plus 876 hrs). The Panel finds that the maximum possible usage of the FortisBC system without significant penalties is 2,316 hours per year which represent 26.4 percent of a total 8,760 hours available in a calendar year.
Commission determination
Given that RS 37 is only available to a customer for 26.4 percent of the year and RS 31 is available for 100 percent of the year, there could be an argument that an appropriate Wires Charge for stand-by service is SBDL times the percentage of available hours of stand-by service. This would result in a SBBD for Celgar of 11 MVA (26.4 percent of SBDL of 42 MVA). The Panel only finds this approach of very limited interest but notes that it warrants some consideration in regards to order of magnitude.
3.3.8 Significance of past brokerage agreements
Celgar states that for more than a decade, service by FortisBC to Celgar had been provided based upon an “agreed to” Contract Demand of 16 MVA at embedded cost rates (RS 31 or RS 33), with stand-by service priced at the incremental cost of such service to FortisBC based on two past brokerage agreements. Celgar also states that since 2011 when it was put on RS 31, “the amounts payable by Celgar have been interim amounts that may be refundable to Celgar, in whole or in part. Accordingly the starting point should be the last final rate that was in effect up until 2011.”[72]
In discussing the significance of past brokerage agreements, FortisBC notes that Celgar now asserts that the Commission should put particular weight upon the brokerage agreements that FortisBC has had with Celgar in the past. FortisBC does not agree that these past agreements adequately reflect the current service parameters of Celgar.[73]
The question arises as to what role should past brokerage agreements (currently extinguished) related to contract demand, play in the determination of Celgar’s SBBD. The Panel now further considers this matter and the position of parties concerning it.
3.3.8.1 Background
On February 15, 2005, Celgar became party to a General Service Power Agreement with FortisBC dated December 20, 2000 (2000 GSA). The 2000 GSA had an Electricity Supply Brokerage Agreement (2000 BA) attached to, and forming part of, it.
The 2000 GSA provided for a maximum volume of service of 46.5 MVA. The agreement stipulated that charges for service would be calculated in accordance with RS 31, with a contract demand of 16 MVA. In the event of a failure of the turbo generator, any requirement in excess of the 16 MVA contract demand was to be provided by FortisBC on a reasonable efforts basis as promptly as possible. In the case where FortisBC was forced to acquire added resources, Celgar was required to pay all actual costs for supply above 16 MVA on a flow-through basis.
There was also a provision for Demand Charges if Stand-by supply occurred at the time of FortisBC’s annual system peak and increased FortisBC’s demand related charges under BC Hydro’s RS 3808.
Celgar – 2006 to January 2, 2011
In 2006 Celgar stopped taking service under RS 31 and the 2000 GSA. On October 1, 2006, Celgar started taking service under RS 33, which is a Time of Use Rate, pursuant to the terms of a new draft GSA and BA (2006 Draft GSA and BA) with FortisBC; however, the 2006 draft was never signed.[74]
In the Draft 2006 GSA the parties agree that the 2006 Draft GSA replaced the previous 2000 GSA. The 2006 Draft GSA stipulated that FortisBC would make available the firm capacity reservation of 10 MVA during the day and 25 MVA during the night. Further, it stated that the customer shall not exceed the demand limit of 40 MVA unless otherwise agreed in writing.
The Draft 2006 GSA and attached BA addressed the issue of back-up power required by Celgar due to the unavailability of its own turbo generator as follows:
“Since the pulp mill can operate independently of the turbo generator, the Customer would like a backup source of power above the firm supply levels of 10 MVA between 8:00 am and 10:00 pm and 25 MVA between 10:00 pm and 8:00 am. If FortisBC was required to provide this backup by contract purchase from B.C. Hydro, the Customer could incur excessive costs for relatively minimal power consumption as a result of capacity charges imposed under the BC Hydro rate of supply for FortisBC. The intent of this electricity supply brokerage agreement is that should the customer’s requirements exceed the Firm Capacity reservation, described above, then the customer shall pay the equivalent of Rate Schedule 33 as more fully described below.”[75]
Celgar - January 2, 2011 to present
In the decision on FortisBC’s 2009 Rate Design Application, the Commission directed FortisBC to take Celgar off of RS 33 and provide Celgar service under RS 31, effective January 2, 2011. On March 25, 2011, the Commission directed FortisBC to bill Celgar in accordance with RS 31 on an interim basis.
3.3.8.2 Nature of Service
In its Stage IV Submission FortisBC states:
It is conceivable that Celgar would react to generation upsets differently in certain situations depending on whether it was taking service solely under RS 31 or utilizing the Stand-by Rate. Fundamentally, however, it would routinely operate in the same manner in both cases – generating to serve load and relying on FBC in periods where its self-generation was insufficient. What changes is the manner in which Celgar is billed, not the characteristics of that FBC service itself.[76] (underline added)
In its Stage IV Submission Celgar states:
Nothing has changed since 2000 (when the last brokerage agreement was entered into, or 2011, when it was overridden) in the type or amount of service Celgar utilizes, or as to FortisBC's costs. Celgar has neither increased its load nor changed its load characteristics. Indeed, the only changes in load characteristics prior to the change in treatment were the result of significant investments by Celgar to increase the reliability of its self-generation output and an accompanying decrease in the volume of energy purchased from FortisBC.[77]
FortisBC has already been providing Celgar stand-by service for many years. The Panel finds that the nature of the service provided under both the 2000 GSA and the 2006 GSA, is that of stand-by service and that the nature of that service is not different from what is now available to Celgar under the combined RS 37 and RS 31.
While the agreements were reached a number of years ago, they remained in effect until 2011. Given that the rates in these past agreements were not considered unjust, unreasonable, unduly discriminatory or unduly preferential, the Panel finds that consideration of the Wires Demand Charges recovered under these past agreements, is of value to the Panel in determining an appropriate SBBD for Celgar, and will therefore consider each of them in more detail.
3.3.8.3 Service between 2006 and 2011 (RS 33)
Commencing in 2006 Celgar was billed under RS 33.[78] Although RS 33 only has an energy component, the transmission costs were built into the pricing of the energy component during Winter ‘On Peak’ and Summer ‘On Peak’ periods.[79]
For Celgar, this rate allowed it to avoid the ‘on-peak’ energy periods most of the time, and therefore avoid most of the transmission costs which was not the intent of the rate. As this led to an under recovery of costs and very low revenue to cost ratio of RS 33, the Commission, as part of its decision on FortisBC’s 2009 Rate Design and Cost of Service Application (2009 RDA), ordered that Celgar be moved off RS 33 effective January 2, 2011.[80]
Commission determination
The Panel does not consider that RS 33 provides any further clarity on what an appropriate SBBD for Celgar should be, given that the Commission determined that Celgar was ineligible to continue taking service under RS 33 due to the under recovery of costs.
3.3.8.4 Service between 2000 and 2006
The Wires Demand Charges for service under the 2000 GSA were as follows:
a. Full service: Demand charges under RS 31 for 16 MVA.
b. Stand-by: Demand chargers for service in excess of 16 MVA (up to 42.6 MVA) – actual cost for supply including any additional demand charges incurred by FortisBC where the supply of power came from BC Hydro’s RS 3808.
In its Stage IV Submission Celgar provided a table (paragraph 66), and an explanation (paragraph 67) depicting nil annual Stand-by Wires Demand Charges under the 2000 GSA[81] meaning that there were no additional incremental wires costs incurred by FortisBC and passed along to Celgar during this time period.
FortisBC in its Stage IV Reply Submission states:
In paragraph 66, Celgar provides a table intended to show annual costs under a number of scenarios of Celgar’s conjuring. The table…indicates that there are no Wires Demand Charges to Celgar for either the 2000 GSA or for the BC Hydro 1880. This is inaccurate in both cases. Also missing from the table is the amount that Celgar is paying under RS 31 in a manner consistent with what all other customers are expected to pay.[82]
It further states:
It is difficult to comment on Celgar’s paragraph 67. Among other issues, the 2000 GSA had a Contract Demand of 16 MVA, not 24 MVA, and Celgar paid full demand charges each month on the entire amount [16 MVA]. It also paid for energy consumed at the full RS 31 rate which included a portion of the fixed cost recovery.[83]
Commission determination
First, the Panel disagrees with FortisBC’s interpretation of Celgar’s table provided in paragraph 66 of Exhibit C2‑36. The second column titled Stand-by Billing Demand denotes the amount of stand-by service that was available to Celgar in excess of its RS 31 Contract Demand and was not meant to relate to the 16 MVA RS 31 Contract Demand as suggested by FortisBC.
Second, FortisBC confirmed that during the 2000 GSA period Celgar was assessed a flat demand related charge based on a 16 MVA, and incremental demand charges for service in excess of the 16 MVA. Celgar went on to submit that during the 2000 GSA period there were no such incremental charges passed on to Celgar, leaving one to conclude that no such costs were incurred by FortisBC. Given that FortisBC has not provided any evidence or invoices to rebut this assertion the Panel concludes that during the 2000 GSA period Celgar paid demand charges of 16 MVA for the service it was provided, which included both full service and stand-by service.
Third, FortisBC has also stated that Celgar paid energy charges for the full amount of energy taken under RS 31 and this is not disputed; however, FortisBC has stated that the energy charge recovered a significant portion of the fixed costs but failed to show any evidence as to how much or whether the fixed costs related to transmission or generation. On this issue, the Panel finds that it would seem more likely that any fixed costs recovered through an energy charge would likely relate to fixed generation costs and not fixed transmission costs. Therefore, the Panel has given little weight to this argument.
Finally, the parties have identified certain changes since 2000. The Panel finds the following four to be of significance, and will address each separately. First FortisBC notes that demand charges were unbundled as part of the 2009 RDA. Celgar states that there have been three significant changes implemented since 2000 that support Wires Charges less than 16 MVA: (i) installation of a load management system, and (ii) communications and control system investments, (iii) reliability upgrades.[84]
The Panel also notes that the issue of RS 37 being a firm rate has been raised; however, the Panel finds that this was fully addressed in the Stage I Decision,[85] and if for planning purposes, the costs are the same for offering firm or non-firm service, as asserted by FortisBC, then it would not be expected to impact this analysis and will therefore not be addressed further.
3.3.8.4.1 Unbundled Rates
As part of FortisBC’s 2009 RDA demand charges were split into power supply‐related demand charges and wires‐based demand charges for Large General Service – Transmission and Wholesale customers in order to send better price signals.
FortisBC stated “that even if one assumes that the historical Contract Demand of 16 MVA adequately recovered costs in the past, using the same figure in conjunction with a Stand-By Rate and no Power-Supply Charge would not be appropriate because the rate is now unbundled.”[86] FortisBC was able to calculate a normalized figure designed to produce an equivalent amount of fixed revenue based on a 16 MVA Contract Demand in 2000 given today’s rate structure and that amount is 25 MVA calculated as follows:[87]
Celgar does not agree with FortisBC’s analysis because, as FortisBC explains, today’s equivalent charge includes both a Wires Charge and Power Supply Charge, and it is not reasonable to assume the Power Supply Charge would be zero in every month. Celgar proposes that a more reasonable assumption would be a Power Supply Charge based on a monthly actual metered demand of 75 percent of the Contract Demand in which case the equivalent demand to arrive at the same bill would be 17,548 kVA.[88]
Commission determination
The Panel acknowledges that the Demand Charge was broken out into components as a result of the 2009 RDA. The Panel also understands that the Power Supply Charges were meant to recover demand costs related to FortisBC’s power supply related costs and the Wired Demand Charge was meant to recover transmission infrastructure costs.[89] On that basis there is an argument that because the Panel approved a RS 37 rate design that set the price for energy supplied with a market proxy that no adjustment to the 16 MVA is necessary as the Power Supply (demand) Charge relates to FortisBC’s generation and not its network.
However, the Panel agrees with FortisBC that in order to fairly compare the demand charges paid for similar service under the 2000 GSA, a normalization adjustment is required. The Panel considered both the Celgar and FortisBC proposed adjustments and finds that FortisBC’s adjusted demand of 25 MVA to be a better reflection of normalizing the demand charges agreed to in 2000 to today’s rate structure.
3.3.8.4.2 Installation of load management system
Celgar submits that it has made a $2 million investment in its load shedding system which enabled Celgar to reduce its load requirements from 16 MVA to 8 MVA. In addition, Celgar notes the FortisBC System Control Centre has the ability to monitor, in real time, purchases by Celgar.[90]
FBC submits: “… it is unclear to FBC why Celgar believes that the installation of communications and control equipment for the protection of the FBC system and customers is any justification of a particular level of Contract Demand. Celgar claims a benefit to FortisBC from this system that was installed only as a result of the Celgar generation.”[91]
Commission determination
The Panel considers that Celgar’s load shedding system has the following benefits to Celgar:
(i) reduced Celgar’s exposure to additional incremental network costs under the 2000 BA;
(ii) improvement in reliability (to protect the mill from tripping offline due to lightning storms); and
(iii) increasing Celgar’s potential to participate in demand-side rate designs should they be developed by FortisBC in the future.
The Panel considers that all of the above improvements are all benefits to Celgar and should not result in a reduction in the Stand-by Billing Demand.
3.3.8.4.3 Communications and control system investments
The Commission Panel considers that the issue regarding FortisBC’s requirement for Celgar to install a communications and control system to allow FortisBC to trip Celgar’s generators, is a generator interconnection policy issue and, accordingly, out of scope of this proceeding. This decision is focussed on Stand-by rate issues only.
3.3.8.4.4 Reliability upgrades
Celgar stated that it spent $28 million in 2006 making reliability upgrades to its industrial facility that reduced its demands on the FortisBC system.[92]
FortisBC submits that Celgar continues to rely intermittently on the FortisBC infrastructure to serve the full peak load in excess of 40 MVA. FortisBC further submits that, to the extent that Celgar has reduced the frequency of its requirement for the accommodation of its full load, and reduced the amount of energy that flows across the FortisBC system, the avoidance of the Power Supply related demand charges is a direct recognition of this fact.[93]
Commission determination
The Panel considers that the nature of the service provided in 2000 was stand-by service, and that this has not changed as a result of the Celgar reliability upgrades. The Panel agrees with FortisBC that, to the extent this has resulted in a decrease in energy purchases from FortisBC, this will be reflected in the lower energy charges and not Wires Demand Charges. In summary, the nature of the service has not changed due to the reliability upgrades.
The Panel does not consider that the changes in reliability of Celgar’s self-generating plant are sufficient to indicate any adjustment to the last agreed to contract demand as these do not translate into any Wires Demand Charge savings.
Overall Commission determination on the 2000 GSA Contract Demand
The Panel stated that it is in no way bound by the past 2000 GSA, but finds the 16 MVA to be compelling evidence given the lack of any other cost causation evidence. The Panel then considered any changes that have occurred since 2000 and concluded that adjustment for the unbundling of RS 31 was necessary and normalized the last contract demand to 25 MVA.
FortisBC’s position is that given no party pursued the last contract demand as a desired outcome, and the SBBD is to be arrived at primarily through consideration of the principles contained in the Stage II Decision, FortisBC asserts that it is no longer, “…still of relevance to the parties and issues to be resolved.” The Panel has indicated that previous approvals are informative, but that it is not bound by any precedent to rely upon them.[94]
The Panel disagrees with FortisBC that because no parties have pursued the last contract demand that it is no longer of relevance. In fact it finds that FortisBC has missed the point. The Panel has already determined that the nature of the service provided to Celgar under the 2000 GSA and service under the Stand-by Rate (RS 37) in combination with RS 31 are essentially the same as the last time the parties agreed to demand charges. The Panel further finds that any benefits that Celgar brought to the system were reflected in the agreed upon demand charges at that time.
Therefore, the Panel concludes the normalized 2000 GSA demand charges of 25 MVA is indicative of demand charges that recover costs for service which the Panel has determined are essentially the same. This translates into a SBBD of 52 percent of SBDL or 22 MWA plus a RS 31 Contract Demand of 3 MVA for a total Wires Demand Charge of 25 MVA.
4.0 PANEL Determination on Celgar’s Stand-by Billing Demand
The Panel previously stated that with regard to economic efficiency, Stand-by Wires Demand Charges should be set such that they do not inadvertently either restrict the growth of cost-effective distributed generation, or promote uneconomic bypass. In regards to fairness the Panel stated that Wires Demand Charges should also result in a fair contribution to the sunk costs of the utility's network, although the Panel noted the difficulty in determining the fairness of a Wires Demand Charge from a cost causation perspective.
The Panel also found that determining the appropriate Wires Demand Charge for self-generating customers was more of an art than a science and concluded that the one-size-fits-all approach could result in sub-optimal Province-wide outcomes over the long term.[95]
The Final Stage IV Submissions of the parties clearly indicate that no agreement on the SBBD was reached. In fact, the positions of FortisBC and Celgar have hardened since the earlier April 2015 negotiations. Consequently, this unfortunate situation requires the Panel to make its own determination.
In coming to a final determination, the Panel notes that it has already determined the following:
• The benefits for self-generation are to be reflected through the SBBD as they are not reflected through the other components of RS 37 as suggested by FortisBC.
• Intermittent stand-by service (RS 37) is different than continuous use full service (RS 31) and it is not fair or reasonable to charge Celgar as a Stand-by customer the same Wires Demand Charges as a full service RS 31 customer especially when Celgar is not entitled, under the net-of-load environment, to be a full service customer.
• Assuming that a SBBD of 8 MVA for Celgar, which was the basis for the final refiled 2009 COSA, would allow FortisBC to recover Celgar’s fair portion of wires costs is an over simplification. However, it is indicative that a SBBD of 42 MVA would significantly over recover Celgar’s fair portion of wires costs.
• FortisBC’s 42 MVA proposal is rejected as it would result in a charge that is unjust, unreasonable and unduly discriminatory on the basis that FortisBC failed to justify its proposed SBBD of 42 MVA as its evidence was deficient and it did not provide any costs-based evidence for stand-by service to Celgar.
• Celgar failed to make a sufficiently persuasive case for its proposed SBBD based on 10 percent of SBDL and it was rejected.
• There may be benefits that Celgar’s self-generation has provided, and continues to provide, to FortisBC and other ratepayers but those benefits cannot readily or directly be translated into a formula that results in a specific SBBD for Celgar.
• A Wires Demand Charge under the Planning Reserve Margins method would result in a SBBD for Celgar in the range of 4.2 to 8.4 MVA; however this approach’s value is limited because Celgar is currently the only self-generator customer on the system.
• A Wires Demand Charge based on the Availability of Stand-by Service consideration would lead to a SBBD for Celgar of 11 MVA and, although simplistic, warrants some consideration in regards to order of magnitude.
• A normalized Wires Demand Charge on the basis of the 2000 GSA (last agreed to contract demand for similar service) would lead to a total Wires Demand Charge for Celgar of 25 MWA. This would result in a SBBD on 52 percent of SBDL or 22 MWA plus a RS 31 Contract Demand of 3 MWA for a total Wires Demand Charge of 25 MWA.
Based on the above, it is evident that there is no mathematically perfect or correct answer to setting the SBBD for Celgar. Given the circumstances, the Panel endeavours to set a SBBD such that it does not inadvertently either restrict the growth of cost-effective distributed generation, or promote uneconomic bypass while resulting in a fair contribution to the sunk costs of the utility's network.
The following table assesses the magnitude of the Wires Demand Charges under various alternatives. As indicated in the table both Celgar and FortisBC’s proposals were rejected by the Panel.
The normalized 2000 GSA indicates that the SBBD could be set as high as 52 percent of the SBDL or 22 MWA. However, all the other findings indicate that directionally the SBBD should be below that level. For instance, the Planning Reserve Margin method would result in a SBBD in the range of 10 to 20 percent of the SBDL. The Panel notes the reservations of FortisBC’s expert, which relate to the fact that Celgar is the only self-generator customer. Yet, at the same time the Panel finds that Celgar should not be unfairly penalized because of this predicament. Similarly, the Panel acknowledges the BC Energy Plan and the CEA which clearly promote self-generation and finds that because Celgar's investment supports the objectives of the BC Energy Plan, its SBBD should be lowered to reflect this positive initiative. Previously, the Panel found that the benefits of self generation are to be reflected through the SBBD as they are not reflected through the other components of RS 37. In summary, in the spirit of the notion that setting a SBBD is more of an art than a science, the Panel has considered the range of possible answers that could be deemed reasonable and fair and finds that the SBBD should be set at 40 percent of Celgar’s SBDL.
Accordingly, the Panel determines that Celgar’s SBBD will be based on 40 percent of SBDL and that this does not lead to a rate that is unjust, unreasonable, unduly discriminatory or unduly preferential. On this basis Celgar’s SBBD is set at 16.8 MVA.
5.0 OTHER OUTSTANDING MATTERS
5.1 NECP Rate Rider
In the Original Application, FortisBC filed for approval for the Non-Embedded Cost Power (NECP) Rate Rider which is a provision for charging self-generating customers that intend to sell any portion of its generation that is not in excess of load.
FortisBC made the application for the NECP Rate Rider in compliance with Order G-188-11 which states: “FortisBC is directed to develop a rate for Celgar and other self-generators by…based on RS 31 but excluding BC Hydro PPA Power from its resource stack.” The review of the NECP Rate Rider was suspended pursuant to Order G-12-14 pending a final determination on an application by BC Hydro for a new power purchase agreement under RS 3808 (RS 3808 Proceeding).
On May 6, 2014, the Commission made a final determination on the RS 3808 Proceeding by Order G-60-14. In light of that determination the Commission issued a letter requesting submissions from the parties on how to proceed with FortisBC’s request for approval for the NECP Rate Rider. The Commission considered the submissions and determined, among other things, the following on July 30, 2014 by Order G-107-14:
1. The review of the NECP Rate Rider remains suspended until such time as the review by the Commission of both the FortisBC Self-Generation Policy Application (SGPA) and the BC Hydro Application for Approval of Section 2.5 Guidelines for Tariff Supplement No. 3 to Rate Schedule 3808 (Section 2.5 Guidelines Application) are completed.
2. The resolution of the retroactive application of rates to Zellstoff Celgar Limited Partnership (Celgar) is not related to, or dependent on, the NECP Rate Rider.
Subsequently, on January 13, 2015, the Commission suspended the regulatory timetable for the review of the Section 2.5 Guidelines Application until further notice. Furthermore, Phase I of the FortisBC SGPA is currently underway but at this point the timeline for a final resolution on the application is unknown.
Given that there is no defined date as to when the suspension on the Section 2.5 Guidelines Application will be lifted, or when the review of the FortisBC SGPA will be completed, the Panel is concerned with holding this Application open any further after the Retroactive Billing issues have been resolved.
Therefore, in accordance with the timetable established in Order G-149-15, Directive 2, the Panel seeks further submission from the parties on how best to proceed with FortisBC’s request for approval of the NECP Rate Rider as set out in the Original Application, and the evidence on the record in this proceeding in relation to that request.
5.2 General Service Agreement (GSA)
Celgar in its Stage IV Submission states:
“FortisBC appears to be proposing another condition to completing a new general service agreement (a "GSA") with Celgar, by suggesting that a new Joint Operating Order is required as part of the process. Celgar has a current Joint Operating Order in place and wishes to avoid any further delay in finalizing its GSA. It should not be a difficult matter to come to terms regarding the form of a GSA. To assist the process, Celgar has attached hereto as Schedule "A" a draft GSA for FortisBC to comment upon in its reply. Celgar believes it possible to complete, in principle, a form of GSA with FortisBC (subject to finalization of the SBBD) before FortisBC files its reply in this proceeding. Celgar suggests that negotiations ensue and that the parties' positions on the GSA be reported to the Commission at the same time that FortisBC files its reply submission. If agreement has not been reached on all terms (excluding the SBBD), Celgar would hope that the Commission would make a determination as to the terms in issue and direct FortisBC to offer a GSA to Celgar on such terms, without further process, inserting the SBBD value that it arrives at.”[96]
FortisBC in its Stage IV Reply Submission states:
“With respect to a GSA, the Company notes that in addition to being outside of the scope of the current submissions [GSA], it is premature to even discuss a GSA for Stand-By Service, let alone “…to complete, in principle, a form of GSA with FortisBC (subject to finalization of the SBBD) before FortisBC files its reply in this proceeding.
It makes no sense, and would be a waste of resources, for FortisBC to engage in negotiations for a GSA necessitated by Celgar taking service on RS37, prior to Celgar deciding if it intends to take Stand-by Service and has notified FortisBC of such an intent. In addition, the question of whether or not Celgar will have access to a form of “bypass” rate has not been settled before the Commission.
Should, after the determination of a SBBD, Celgar request Stand-by Service from FortisBC, the Company will set about negotiating a GSA with Celgar. The Commission should decline to make any determinations on this portion of the Celgar submission. Further, the issue of whether the Commission can or should impose an agreement between Celgar and FortisBC would need to be addressed if it arises.”[97]
Commission determination
The Panel has not considered, nor will it make any determination on, Celgar’s draft GSA attached as Schedule “A” to its Stage IV Submission. As such, the Panel denies Celgar’s request that the Commission both make a determination as to the terms at issue and direct FortisBC to offer a GSA to Celgar on such terms.
Now that a Stand-by Rate has been approved by the Commission and the Three RS 37 Components, which are integral to the GSA, have been set, the Panel is optimistic that the parties can successfully negotiate a GSA without the assistance of the Commission.
5.3 Retroactive Billing
5.3.1 Background
Order G-188-10
Directive 5
• FortisBC is directed to bill Celgar in accordance with RS 31 on an interim and refundable basis beginning March 25, 2011, and ending when the Commission approves the new rate for Celgar that excludes PPA Power from its resource stack, and/or an Agreement is forwarded by the parties.
• Any differences between the interim rate and the rate ultimately approved by the Commission are subject to refund/recovery, with interest at the average prime rate of FortisBC’s principal bank for its most recent year.
Order G-202-12
Celgar requested confirmation from the Commission Panel that the amounts invoiced by FortisBC beginning March 25, 2011, will be recalculated on the basis of the charges associated with a Stand-by Rate once it becomes available.
Order G-202-12 Decision, p. 17 stated:
“In Order G‐188‐11, the Commission Panel directed FortisBC to design a standby rate following the review of FortisBC’s Entitlement Guidelines and Matching Methodology. As this Decision concludes the review of those Guidelines and Methodology, there are no approved terms and conditions associated with a standby rate in effect today against which the Commission Panel, or FortisBC for that matter, to make a determination of whether such a rate would have applicability to Celgar during the Interim Period. However, the Commission Panel accepts FortisBC’s assessment that, based on the load behaviour filed by Celgar, standby service during the period between March 25, 2011 and July 31, 2012 (the period for which load data was made available to FortisBC and to the Commission Panel) may be appropriate. Without information on Celgar’s load behaviour after this period, the Commission Panel cannot make any further determination.”
Directive 7
• FortisBC’s assessment that it is appropriate to charge Celgar for stand-by service from March 25, 2011 to July 31, 2012, is accepted.
Order G-12-14
Directive 4
• The retroactive application of rates to Celgar will be addressed once the Commission approves either a new rate for Celgar which complies with the final rate approved in the RS 3808 Proceeding, and/or an Agreement is made by the parties.
Order G-67-14 (Stage I Decision)
• The Panel makes no determination at this time whether or not a final approved Stand-by Rate will be appropriate for service between March 25, 2011 and the effective date of Rate Schedule 37.[98]
• The Panel will not be seeking submissions on how to move forward with the retroactive billing for Celgar until a final determination is made on the Stand-by Rate.[99]
Order G-107-14
Directive 1
• The resolution of the retroactive application of rates to Zellstoff Celgar Limited Partnership (Celgar) is not related to, or dependent on, the Non-Embedded Cost Power (NECP) Rate Rider.
Directive 3
• The interim billing period for Celgar, as established by directive 5 of Order G-188-11, will end on the initial effective date of FortisBC Inc.’s Stand-by Service Rate Schedule 37 (RS 37) as established by the Commission.
Directive 4
• The retroactive application of rates to Celgar will be addressed once a final determination has been made on both RS 37 and the Celgar specific issues as identified in directive 6 of Order G-67-14.
Letter dated November 21, 2014, marked as Exhibit A-35
• Therefore, the Commission does not confirm that the interim period will continue until a potential bypass rate is approved for Celgar. The interim billing period for Celgar ends on the initial effective date of the Stand-by Rate as established by Order G-107-14.
5.3.2 Celgar’s retroactive billing requests
Celgar, in its Stage IV Submission states:
“Celgar remains hopeful that the retroactive billing issues related to the interim period will be resolved by agreement in a timely manner and will not require further Commission directions. However, subject to the SBBD determinations, the retroactive billing issue may need to be resolved after consideration of the final terms of service [GSA].”[100]
Celgar also made the following requests to the Commission:
Request 1
Celgar requests that the order following this proceeding include a direction to FortisBC to submit a compliance filing to the Commission, within 20 business days from the date of the Decision, which would include a calculation of the first retroactive billing adjustment reflecting the various directives contained in the decision.
In response to this request FortisBC’s reply states:
“In this context, consistent with the Commission’s determination, a further process may be needed for the Commission to decide the retroactive billing issue as any retroactive payment would impact all FortisBC customers.
This view is shared and made clear by the previous submission of the BCOAPO in Exhibit C4-18, in which it noted:
‘… that the Stand-By Rate has not yet been finalized, and the Commission has not yet approved the Stand-By Rate as being retroactive to March 25, 2011.Rather, the Commission stated in its May 26, 2014 Decision in FortisBC 's Application for Stepped and Stand-by Rates for Transmission Voltage Customers that the Commission will determine "whether it is appropriate to apply the Stand-by Rate retroactively to Celgar when it reviews the retroactive application of rates for Celgar…’
Clearly, the BCOAPO expects further process on the matter and is likely to participate. Any Commission determination at this point would not allow for such participation and would deny due process to other potential participants as well.”[101]
Request 2
Celgar asks that the decision also contemplate a second compliance filing so as to calculate a further retroactive billing adjustment following consideration of the Bypass Options in a subsequent process, if there is such a further process.
In response to this request FortisBC states, in its Stage IV Reply, that this request disregards the closing paragraph of Exhibit A-35, which states plainly:
‘Therefore, the Commission does not confirm that the interim period will continue until a potential bypass rate is approved for Celgar. The interim billing period for Celgar ends on the initial effective date of the Stand-by Rate as established by Order G-107-14.’[102]
Request 3
Celgar requests that the retroactive billing adjustment be based on carrying costs at FortisBC’s weighted average cost of capital in each year of the interim period.
FortisBC did not comment on this request in its Reply Submission.
Commission determination
In regards to Celgar’s requests the Commission determines the following:
Request 1
The Panel directs FortisBC and Celgar to attempt to negotiate an agreement on the retroactive application of rates. Within 30 days of the date of this order, FortisBC is directed to either file with the Commission for approval a retroactive billing agreement or, in the event that an agreement cannot be reached, its proposal for the retroactive application of rates to Celgar.
Request 2
The Panel wishes to remind Celgar that FortisBC was correct in noting that the Commission letter dated November 20, 2014, marked as Exhibit A-35, clearly stated that the interim period would not extend beyond the date of the initial effective date of the Stand-by Rate which was June 19, 2015. Therefore, Celgar’s request for consideration for the Bypass Option regarding retroactive billing is denied.
Request 3
The Panel finds that it is premature to make a determination on the appropriate carrying costs at this time. The Panel urges the parties to address it in their negotiations and include it in either the negotiated settlement or address it in the proposed retroactive billing adjustment filing.
Dated at the City of Vancouver, in the Province of British Columbia, this 22nd day of September 2015.
Original signed by:
___________________ _________
L. A. O’Hara
Commissioner
Original signed by:
___________________ _________
R. D. Revel
Commissioner
IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
FortisBC Inc.
Application for Stepped and Stand-by Rates for Transmission Voltage Customers
BEFORE: L. A. O’Hara, Panel Chair/Commissioner
R. D. Revel, Commissioner September 22, 2015
O R D E R
WHEREAS:
A. On March 28, 2013, FortisBC Inc. (FortisBC) filed an application with the British Columbia Utilities Commission (Commission) for approval of new rates for transmission voltage customers (Original Application) under sections 58‑61 of the Utilities Commission Act;
B. The Original Application requested, among other things, approval for a Non-Embedded Cost Power Rate Rider Rate, a Stand-by Service Rate (RS 37) and a determination of the retroactive application of rates to Zellstoff Celgar Limited Partnership (Celgar);
C. The following participants registered as interveners in the proceeding: British Columbia Hydro and Power Authority, Celgar, International Forest Products Limited, British Columbia Old Age Pensioners’ and Seniors’ Organization et al., BC Municipal Electric Utilities, and the Minister of Energy and Mines. Tolko Industries Ltd. registered as an interested party;
D. Effective May, 29, 2015, the Commission approved RS 37 in stages by way of: Order G-67-14 (Stage I) dated May 26, 2014; Order G-46-15 (Stage II) dated March 24, 2015; and Order G-93-15 (Stage III) dated May 29, 2015; and
E. By Order G-93-15, the Commission also sought further submissions from FortisBC and Celgar on an appropriate Stand-by Billing Demand for Celgar, and to respond to certain Panel questions regarding operating reserves.
NOW THEREFORE for the reasons articulated in the Decision issued concurrently with this order, the British Columbia Utilities Commission orders:
1. Zellstoff Celgar Limited Partnership’s (Celgar) Stand-by Billing Demand is to be set at 40 percent of the Stand-by Demand Limit. On the basis of a Stand-by Demand Limit of 42 MVA, Celgar’s Stand-by Billing Demand is 16.8 MVA.
2. In accordance with the following timetable, the Commission seeks further submissions from FortisBC Inc. (FortisBC), and registered interveners on how best to proceed with FortisBC’s request for approval of the Non-Embedded Cost Power Rate Rider and the related evidence on the record in this proceeding:
|
FortisBC Submission |
Tuesday, September 29, 2015 |
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Intervener Submissions |
Tuesday, October 6, 2015 |
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FortisBC Reply Submission |
Wednesday, October 14, 2015 |
3. FortisBC and Celgar are directed to attempt to negotiate an agreement on the retroactive application of rates.
4. Within 30 days of the date of this order FortisBC is directed to either file with the Commission for approval a retroactive billing agreement or, in the event that an agreement cannot be reached, its proposal for the retroactive application of rates to Celgar.
DATED at the City of Vancouver, in the Province of British Columbia, this 22nd day of September 2015.
BY ORDER
Original signed by:
L. A. O’Hara
Panel Chair/Commissioner
List of Acronyms
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CEA |
Clean Energy Act |
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Celgar |
Zellstoff Celgar Limited Partnership |
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CIAC |
Contributions In Aid of Construction |
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COSA |
Cost of Service Analysis |
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FortisBC or the Company |
FortisBC Inc. |
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GBL |
Generation Baseline |
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GSA |
General Service Agreement |
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Language Submissions |
Language directed by the Panel in the Stage II Decision |
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NECP |
Non-Embedded Cost Power |
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Original Application |
Rate Schedule 37 Stand-by Service |
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Penalty Submissions |
Submissions from the parties on an appropriate penalty |
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R/C |
Revenue-to-cost |
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Revised RS 37 |
Revised Rate Schedule 37 incorporating the findings in the Stage I Decision |
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RS 31 |
Rate Schedule 31 |
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RS 37 |
Rate Schedule 37 |
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SBBD |
Stand-by Billing Demand |
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SBDL |
Stand-by Demand Limit |
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Six Principles |
FortisBC set out six principles |
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Stage II Decision |
Order G-46-15 and attached Reasons |
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Stage III Decision |
Order G-93-15 and attached Reasons approving the final form of RS 37 |
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Stage IV Decision |
This Decision |
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Stage IV Submissions |
Specific list of issues relating to Operating Reserves |
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the Mill |
pulp mill at Castlegar, BC |
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Three RS 37 Components |
(i) RS 31 Contract Demand; (ii) Stand-by Billing Demand; and (iii) Stand-by Demand Limit |
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UCA |
Utilities Commission Act |
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|
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IN THE MATTER OF
the Utilities Commission Act, R.S.B.C. 1996, Chapter 473
and
FortisBC Inc.
Stepped and Stand-By Rates for Transmission Customers Application
EXHIBIT LIST
Exhibit No. Description
Commission Documents
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A-1 |
Letter Dated April 10, 2013 - Order G‐55‐13 establishing a Preliminary Regulatory Timetable
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A-2 |
Letter Dated April 15, 2013 – Appointment of Commission Panel |
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A-3 |
Letter Dated April 19, 2013 – Order G‐61‐13 Inviting Comments and Suspending Preliminary Regulatory Timetable
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A-4 |
Letter Dated May 24, 2013 – Order G-85-13 Establishing a Revised Preliminary Regulatory Timetable with Reasons for Decision
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A-5 |
Letter Dated June 3, 2013 – Commission Information Request No. 1 |
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A-6 |
Letter Dated June 12, 2013 – Commission Order G-90-13 issuing Further Amended Preliminary Regulatory Timetable |
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A-7 |
Letter Dated August 1, 2013 – Commission Information Request No. 2 |
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A-8 |
Letter Dated September 6, 2013 – Commission Information Request No. 1 on Intervener Evidence
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A-9 |
Confidential Letter Dated September 6, 2013 – Confidential Commission Information Request No. 1 on Intervener Evidence
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A-10 |
Letter Dated September 9, 2013 – Commission Response to Comments on Further Process
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A-11 |
Confidential Letter Dated September 13, 2013 – Confidential Request Response regarding Confidential Information Request
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A-12 |
Letter Dated September 25, 2013 – Commission Order G-155-13 issuing Updated Preliminary Regulatory Timetable
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A-13 |
Letter Dated October 29, 2013 – Commission Information Request No. 1 on FortisBC Rebuttal Evidence
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A-14 |
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A-15 |
Letter Dated February 3, 2014 – Commission Order G-12-14 issuing Final Regulatory Timetable
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A-16 |
Letter Dated February 13, 2014 – Commission Order G-18-14 issuing and Amended Final Regulatory Timetable
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A-17 |
Letter Dated March 3, 2014 – Panel Chair Appointment |
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A-18 |
Letter Dated March 13, 2014 – Commission Order G-42-14 issuing Reasons regarding Celgar Submission
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A-19 |
Letter Dated May 27, 2014 – Issuing Regulatory Timetable NECP Rate Rider |
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A-20 |
Letter Dated June 30, 2014 – Commission Request for further submissions on NECP Rate Rider
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A-21 |
Letter Dated June 30, 2014 – Commission Order G-81-14 issuing Regulatory Timetable
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A-22 |
Letter Dated July 2, 2014 – Amended Regulatory Timetable
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A-23 |
Letter Dated July 18, 2014 – Commission Information Request No. 3 to FortisBC
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A-24 |
Letter Dated July 30, 2014 – Commission Order G-107-14 regarding the NECP Rate Rider |
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A-25 |
Letter Dated August 20, 2014 – Commission Order G-118-14 Issuing Regulatory Timetable |
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A-26 |
Letter Dated September 18, 2014 – Commission Order G-141-14 Temporarily Suspending Timetable
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A-27 |
Letter Dated September 23, 2014 – Commission Order G-149-14 Suspending Timetable |
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A-28 |
Letter Dated October 7, 2014 – Commission Order G-154-14 issuing Amended Regulatory Timetable |
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A-29 |
Letter Dated October 15, 2014 - Commission Information Request No. 1 to Celgar |
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A-30 |
Letter Dated October 16, 2014 – Commission Response to BCOAPO Request for Extension of Time to File Intervener Evidence |
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A-31 |
Letter Dated October 27, 2014 – Request for Submissions regarding Clarification of Implications of Order G-153-14 |
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A-32 |
Letter Dated October 27, 2014 – Commission Order G-166-14 with Reasons and the Regulatory Timetable |
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A-33 |
Letter Dated October 31, 2014 – Commission Order G-168-14 and Regulatory Timetable |
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A-34 |
Letter Dated November 17, 2014 – Commission Order G-179-14 with Reasons for Decision |
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A-35 |
Letter Dated November 20, 2014 – Commission Response to Celgar Request for Clarification of Implications of Order G-153-14 |
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A-36 |
Letter dated January 30, 2015 – Notice of member extension |
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A-37 |
Letter dated March 26, 2015 – Commission Response to FBC Extension Request |
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A-38 |
Letter dated March 27, 2015 – Commission Response to FBC Extension Request regarding Directive 2 |
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A-39 |
Letter dated June 22, 2015 – Commission Response to Celgar Extension Request |
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Applicant Documents
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B-1 |
FortisBC Inc. (fbc) Letter Dated March 28, 2013 - Stepped and Stand-By Rates for Transmission Customers Application
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B-1-1 |
Letter Dated April 8, 2013 - Errata 1 to the Application |
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B-1-2 |
Confidential Letter Dated March 28, 2013 – Confidential attachment to the application
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B-1-3 |
Letter Dated July 4, 2013 - Errata 2 to the Application |
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B-1-4 |
Confidential Letter Dated July 4, 2013 – Confidential Errata 2 to the Application
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B-1-5 |
Letter Dated August 9, 2013 - Errata 3 to the Application |
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B-2 |
Letter dated April 30, 2013 – FBC Submitting Response to Celgar (Exhibit C2-2) |
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B-3 |
Letter dated June 11, 2013 – FBC Submitting Extension Request |
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B-4 |
Letter dated July 4, 2013 – FBC Responses to Information Request No. 1 to BCUC |
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B-5 |
Letter dated July 4, 2013 – FBC Responses to Information Request No. 1 to BCPSO |
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B-6 |
Letter dated July 4, 2013 – FBC Responses to Information Request No. 1 to Celgar |
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B-6-1 |
Confidential Letter dated July 4, 2013 – FBC Responses to Information Request No. 1 to Celgar |
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B-7 |
Letter Dated August 15, 2013 – FBC Submitting Response to BCUC IR No. 2 |
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B-7-1 |
Confidential Letter Dated August 15, 2013 – FBC Submitting Confidential Response to BCUC IR No. 2 |
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B-8 |
Letter Dated August 15, 2013 – FBC Submitting Response to BCMEU IR No. 2 |
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B-9 |
Letter Dated August 15, 2013 – FBC Submitting Response to BCPSO IR No. 2 |
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B-10 |
Letter Dated August 15, 2013 – FBC Submitting Response to Celgar IR No. 2 |
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B-11 |
Letter Dated August 27, 2013 – FBC Submitting Comment regarding Further Process |
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B-12 |
Letter dated September 6, 2013 – FBC Submitting Information Request No. 1 to Celgar |
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B-13 |
Letter dated October 10, 2013 - FBC Submitting Rebuttal Evidence |
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B-14 |
Letter dated November 14, 2013 - FBC Submitting Response to BCPSO IR1 Rebuttal Evidence |
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B-15 |
Letter dated November 14, 2013 - FBC Submitting Response to BCUC IR1 Rebuttal Evidence |
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B-16 |
Letter dated November 14, 2013 - FBC Submitting Response to Celgar IR1 Rebuttal Evidence |
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B-17 |
Letter Dated February 7, 2014 - FBC Filing comments regarding Final Submission |
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B-18 |
Letter Dated February 12, 2014 - FBC Request to Withdraw February 7 Request Exhibit B-17 |
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B-19 |
Letter Dated March 11, 2014 – FBC Submitting comments regarding Celgar Final Submission dated March 7, 2014 |
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B-20 |
Letter Dated June 4, 2014 – FBC Submitting NECP Rate Rider Submission |
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B-21 |
Letter Dated June 17, 2014 – FBC Submitting NECP Rate Rider Reply |
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B-22 |
Letter dated June 26, 2014 – FBC Compliance Filing for Order G-67-14 |
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B-23 |
Letter dated July 4, 2014 - FBC Submitting Extension Request |
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B-24 |
Letter dated July 4, 2014 - FBC Submission on NECP Rate Rider |
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B-25 |
Letter dated July 24, 2014 - FBC Reply Submission on NECP Rate Rider |
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B-26 |
Letter dated July 24, 2014 – FBC Submission on Further Process |
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B-27 |
Letter dated August 7, 2014 – FBC Submitting Responses to BCUC IR-3 |
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B-28 |
Letter dated August 7, 2014 – FBC Submitting Responses to BCOAPO IR-3 |
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B-29 |
Letter dated August 7, 2014 – FBC Submitting Responses to BCMEU IR-3 |
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B-30 |
Letter dated August 7, 2014 – FBC Submitting Responses to Celgar IR-3 |
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B-30-1 |
Letter dated August 27, 2014 – FBC Response to Celgar IR No. 3 Outstanding Responses |
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B-31 |
Letter dated September 17, 2014 - FBC Reply to Celgar Confidentiality Request |
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B-32 |
Letter Dated October 15, 2014 - FBC Information Request No. 1 to Celgar |
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B-33 |
Letter Dated October 23, 2014 - FBC Submission Regarding Exhibit A-30 |
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B-34 |
Letter Dated October 31, 2014 - FBC Request for Clarification of Implications of Order G-153-14 |
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B-35 |
Letter Dated November 5, 2014 – FBC Submission regarding C2-30 |
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B-36 |
Letter Dated March 26, 2015 – FBC Request for Extension |
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B-37 |
Letter Dated April 9, 2015 - FBC Submissions on Proposed Penalty |
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B-38 |
Letter Dated April 14, 2015 - FBC Comment on the Commission’s Draft Rate Schedule 37 |
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B-39 |
Letter Dated April 24, 2015 – FBC Comment regarding Celgar Specific Issues Submission |
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B-40 |
Letter Dated April 24, 2015 – FBC Reply on Proposed Penalty |
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B-41 |
Letter Dated June 19, 2015 - FBC Submission on Stand-by Billing Demand for Celgar and Commission Panel Issues List
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B-42 |
Letter Dated July 24, 2015 - FBC Reply Submission on Stand-by Billing Demand |
Intervenor Documents
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C1-1 |
British Columbia Hydro and Power Authority (BCH) Online Registration Dated April 16, 2013 – Request for Intervener Status by Janet Fraser |
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C1-2 |
Letter dated May 3, 2013 – BCH Submitting Comments |
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C1-3 |
Letter Dated October 23, 2014 - BCH Submission Regarding Exhibit A-30 |
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C1-4 |
Letter Dated November 5, 2014 – BCH Submission regarding C2-30 |
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C2-1 |
Zellstoff Celgar Partnership Limited (Celgar) Letter Dated April 17, 2013 – Request for Intervener Status by Kim Moller, Elroy Switlishoff, Brian Merwin, Robert Hobbs |
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C2-2 |
Letter received April 18, 2013 – Celgar Submitting Comments |
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C2-3 |
Letter dated May 15, 2013 – Celgar Submitting Response Comments |
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C2-4 |
Letter dated June 7, 2013 – Celgar Submitting Information Request No. 1 |
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C2-5 |
Letter Dated August 1, 2013 – Celgar Submitting Information Request No. 2 |
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C2-6 |
Letter Dated August 22, 2013 – Celgar Submitting Evidence |
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C2-6-1 |
Confidential - Letter Dated August 22, 2013 – Celgar Submitting Confidential Evidence |
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C2-7 |
Letter Dated August 22, 2013 – Celgar Request for Confidentiality |
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C2-8 |
Letter Dated August 27, 2013 – Celgar Submitting Comment regarding Further Process |
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C2-9 |
Letter Dated September 20, 2013 – Celgar Submitting Response to BCUC IR No. 1 |
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C2-10 |
Confidential Letter Dated September 20, 2013 – Celgar Submitting Response to Confidential BCUC IR No. 1 |
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C2-11 |
Letter Dated September 20, 2013 – Celgar Submitting Response to BCPSO IR No. 1 |
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C2-12 |
Letter Dated September 20, 2013 – Celgar Submitting Response to FBC IR No. 1 |
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C2-13 |
Letter Dated September 20, 2013 – Celgar Submitting Comments regarding Confidential Information Requests |
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C2-14 |
Letter Dated October 29, 2013 – Celgar Submitting Information Request No. 3 to FBC |
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C2-15 |
Letter Dated February 11, 2014 - Celgar Submitting comments on FBC Request |
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C2-16 |
Letter Dated February 13, 2014 - Celgar Submitting Extension Request |
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C2-17 |
Letter Dated March 12, 2014 – Celgar Submitting Response to FBC Request (Exhibit B-19) |
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C2-18 |
Letter Dated June 10, 2014 – Celgar Submitting NECP Rate Rider Submission |
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C2-19 |
Letter Dated July 18, 2014 - Celgar Submitting Information Request No. 3 |
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C2-20 |
Letter Dated July 18, 2014 - Celgar Submitting NECP Rate Rider Comments |
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C2-21 |
Letter Dated August 13, 2014 – Celgar Submission on Further Process |
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C2-22 |
Letter Dated September 8, 2014 – Celgar Submitting Evidence |
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C2-22-1 |
Confidential Letter Dated September 8, 2014 – Celgar Submitting Confidential Evidence |
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C2-22-2 |
Letter Dated September 8, 2014 – Celgar Submitting Request for Treatment of Confidential Evidence |
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C2-23 |
Letter Dated September 18, 2014 – Celgar Submitting Request for Reconsideration of Order G-141-14 (Exhibit A-26) |
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C2-24 |
Letter Dated October 15, 2014 - Celgar Submitting Comments regarding BCOAPO Extension Request (Exhibit C4-14) |
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C2-25 |
Letter Dated October 20, 2014 - Celgar Submitting Comments |
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C2-26 |
Letter Dated October 22, 2014 - Celgar Submitting Further Comments regarding BCOAPO Extension Request (Exhibit C4-14) |
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C2-27 |
Letter Dated October 27, 2014 - Celgar Submitting Response to BCUC Information Request |
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C2-28 |
Letter Dated October 27, 2014 - Celgar Submitting Response to BCOAPO Information Request |
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C2-29 |
Letter Dated October 27, 2014 - Celgar Submitting Response to FBC Information Request |
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C2-29-1 |
Letter Dated November 7, 2014 – Celgar Submitting Errata Response to FBC Information Request |
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C2-30 |
Letter Dated October 29, 2014 - Celgar Submitting Comments regarding Ministerial Order |
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C2-31 |
Letter Dated November 6, 2014 – Celgar Submission regarding C2-25 |
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C2-32 |
Letter Dated November 12, 2014 – Celgar Reply Submission regarding C2-30 |
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C2-33 |
Letter Dated April 17, 2015 - Celgar Submission on Proposed Penalty |
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C2-34 |
Letter Dated April 24, 2015 – Celgar Submission on Negotiations |
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C2-35 |
Letter Dated June 22, 2015 – Celgar Request for Extension |
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C2-36 |
Letter Dated July 10, 2015 – Celgar Submission |
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C3-1 |
International Forest Products Limited (Interfor) Letter and Online Registration Dated April 19, 2013 – Request for Late Intervener Status by Andrew Horahan |
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C4-1 |
British Columbia Pensioners’ and Seniors’ Organization (BCPSO et al) Letter dated April 19, 2013– Request for Late Intervener Status by Leigha Worth, Eugene Kung and Bill Harper |
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C4-2 |
Letter dated May 3, 2013 – BCPSO Submitting Comments |
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C4-3 |
Letter dated June 7, 2013 – BCPSO Submitting Information Request No. 1 |
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C4-4 |
Letter Dated August 1, 2013 – BCPSO Submitting Information Request No. 2 |
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C4-5 |
Letter Dated August 27, 2013 – BCPSO Submitting Comment regarding Further Process |
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C4-6 |
Letter Dated September 6, 2013 - BCPSO Submitting Information Request No. 1 to Celgar |
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C4-7 |
Letter Dated October 29, 2013 - BCPSO Submitting Information Request No. 3 to FBC |
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C4-8 |
Letter Dated February 3, 2014 – BCPSO Submitting Updated Distribution List |
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C4-9 |
Letter Dated June 11, 2014 – BCPSO Submitting NECP Rate Rider Submission |
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C4-10 |
Letter Dated July 4, 2014 - BCPSO Submitting Comments regarding FBC Extension Request |
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C4-11 |
Letter Dated July 16, 2014 – BCPSO Submitting Information Request No. 3 to FBC |
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C4-12 |
Letter Dated July 18, 2014 – BCPSO Submitting Comments on the NECP Rate Rider |
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C4-13 |
Letter Dated August 13, 2014 – BCOAPO Submission on Further Process |
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C4-14 |
Letter Dated October 14, 2014 – BCOAPO Submitting Request for Extension |
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C4-15 |
Letter Dated October 15, 2014 - BCOAPO Information Request to Celgar |
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C4-16 |
Letter Dated October 20, 2014 – BCOAPO Submitting Comments Regarding Justification of Relevance |
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C4-17 |
Letter Dated October 27, 2014 – BCOAPO Submitting Minister’s Order dated May 23, 1991 |
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C4-18 |
Letter Dated November 3, 2014 – BCOAPO Submitting Comments on Exhibit A-31 |
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C4-19 |
Letter Dated November 5, 2014 – BCOAPO Submission regarding C2-30 |
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C4-20 |
Letter Dated April 17, 2015 - BCOAPO Submission on Proposed Penalty |
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C5-1 |
British Columbia Municipal Electrical Utilities (bcmeu) Letter dated June 24, 2013 – Request for Late Intervener Status by Alex Love and Marg Craig |
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C5-2 |
Letter Dated August 1, 2013 – BCMEU Submitting Information Request No. 2 |
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C5-3 |
Letter Dated June 11, 2014 – BCMEU Submitting NECP Rate Rider Submission |
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C5-4 |
Letter Dated July 18, 2014 – BCMEU Submitting Information Request No. 3 |
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C6-1 |
Minister of Energy and Mines (mem) Letter Dated October 10, 2014 - Request for Late Intervener Status by Joshua Walters |
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C6-2 |
Letter Dated November 5, 2014 – MEM Submission regarding C2-30 |
Interested Party Documents
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D-1 |
Tolko Industries Ltd (Tolko) Online Registration Dated April 16, 2013 – Request for Interested Party Status by Michael Towers |
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D-1-1 |
Letter Dated August 30, 2013 – Tolko Submitting Comment on BCPSO Determinations Request |
Letters of Comment
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E-1 |
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[1] The full background and context regarding the service provided by FortisBC to Celgar is provided in Section 3.1 of the Stage I Decision.
[2] Zellstoff Celgar 2011 Complaint Against FortisBC Inc., Exhibit B1-2, Appendix A.
[3] RS 31 and RS 37 attached as Appendix A.
[4] Stage III Decision, p. 24.
[5] Exhibit B-39, pp. 1-2.
[6] Exhibit C2-34, p. 1.
[7] Stage III Decision, p. 27.
[8] Exhibit B-41, pp. 11-12.
[9] Exhibit C2-35, p. 30.
[10] Exhibit C2-36, p. 30.
[11] Exhibit B-42, p. 11.
[12] Stage I Decision, pp. 56, 59.
[13] Exhibit B-41, p. 10.
[14] Exhibit B-41, p. 10.
[15] 2007 Energy Plan, pp. 9, 26.
[16] Exhibit C2-36, p. 16.
[17] Ibid., p. 15.
[18] http://www.michigan.gov/documents/energy/NRRI_Electric_Standby_Rates_419831_7.pdf.
[19] Exhibit B-41, pp. 11, 13.
[20] Ibid., p. 2.
[21] Ibid., p. 11.
[22] Exhibit C2-36, p. 33.
[23] Exhibit B-1, p. 36.
[24] FortisBC Final Submission, February 24, 2014, pp. 9-10.
[25] FortisBC Final Submission, February 24, 2014, pp. 9-10.
[26] Celgar Submitting Evidence, Exhibit C2-6, pp. 6-7.
[27] Ibid., p. 6.
[28] Ibid., p. 8.
[29] Exhibit C2-6, p. 10.
[30] Ibid., p. 6.
[31] Exhibit B-41, p. 8.
[32] Ibid., pp. 9-10.
[33] Exhibit C2-36, p. 10.
[34] Ibid., pp. 13-14.
[35] Ibid., pp. 21-22.
[36] Ibid., pp. 22-23.
[37] Ibid., p. 22.
[38] Exhibit B-42, p. 3-4.
[39] Ibid., p. 6.
[40] G-196-10, 2009 RDA and COSA re-filing pursuant to Order G-156-10, December 17, 2010.
[41] Exhibit B-15, BCUC IR 6.3.1.
[42] Exhibit B-27, BCUC IR 3.5.4.
[43] Exhibit B-6, Celgar IR 1.27.1
[44] Order G-188-11, Decision, p. 46
[45] There are two transmission lines serving the Celgar facility;
however, in normal operations one line is dedicated to Celgar.
The other line is used to supply four area substations, which combined supply
approximately 6,500 customers in the Castlegar region.
[46] Exhibit B-15, Rebuttal Evidence, BCUC IR 1.5.3.
[47] Exhibit C2-9, BCUC IR to Celgar 1.14.1.
[48] Exhibit C2-28, Celgar response to BCOAPO IR 1.2.1.
[49] RS 31 Attached as Appendix A.
[50] Exhibit B-41, p. 4.
[51] Ibid., p. 8.
[52] Exhibit B-41, p. 10.
[53] Ibid., pp. 8-10.
[54] Exhibit B-47, pp. 9-10.
[55] Stage I Decision, p. 55.
[56] Exhibit B-6, Celgar IR 1.27.1.
[57] Exhibit B-13, Rebuttal Testimony of Gary S. Saleba, EES Consulting, p. 5.
[58] Exhibit B-15, FortisBC Rebuttal Evidence, BCUC IR 6.3.1.
[59] FortisBC Reply Submission, March 19, 2014, p. 27.
[60] Exhibit B-41, p. 4.
[61] Ibid., pp. 9-10.
[62] Exhibit B-41, p. 7.
[63] Exhibit C2-36, pp. 7-8.
[64] Ibid., pp. 8-9.
[65] Exhibit B-42, p. 5.
[66] Exhibit B-7, BCUC IR 2.10.2.
[67] Exhibit B-6, Celgar IR 1.34.2.
[68] Exhibit B-1, pp. 37, 40.
[69] Exhibit C2-6, p. 13.
[70] Exhibit B-13, FortisBC Rebuttal Evidence, p. 2.
[71] Exhibit B-13, FortisBC Rebuttal Evidence, pp. 2-3.
[72] Exhibit C2-36, p. 17.
[73] FortisBC Reply, p. 6.
[74] 2009 RDA, FortisBC Final Argument dated June 30, 2010.
[75] Agreement dated October 1, 2006 between Zellstoff Celgar Limited Partnership (the Customer) and FortisBC Inc. (FortisBC);
[76] Exhibit B-41, pp. 3-4.
[77] Exhibit C2-36, p. 26.
[78] RS 33 Attached as Appendix A.
[79] G-156-10 Decision, p. 61.
[80] Exhibit B-15, FortisBC Rebuttal Evidence, BCUC IR 6.3.3.
[81] Exhibit C2-36, pp. 27-28.
[82] Exhibit B-42, p. 7.
[83] Ibid., p. 8.
[84] Exhibit C2-27, BCUC IR 1.10.5.
[85] Stage I Decision, p. 47.
[86] Exhibit B-22, p. 29.
[87] Exhibit B-27, BCUC IR 3.8.2.
[88] Exhibit C2-27, BCUC IR 1.10.1.
[89] Ibid, p. 59.
[90] Celgar Final Submission, December 4, 2014, p. 40.
[91] FortisBC Final Submission, November 24, 2014, p. 17.
[92] Exhibit C2-27, BCUC IR 10.5.
[93] FortisBC Final Submission, February 24, 2014, p. 17.
[94] FortisBC Reply B-41, p. 2.
[95] Stage II Decision, p. 17.
[96] Exhibit C2-26, pp. 30-31.
[97] Exhibit B-42, p. 9-10.
[98] Stage I Decision, p. 26.
[99] Ibid., p. 65.
[100] Exhibit C2-36, p. 31.
[101] Exhibit B-42, p. 9.
[102] Ibid., pp. 9-10.