BRITISH COL UMBIA UTILITIES COM MISSION
SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA web site: http://www.bcuc.com IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473
and Application by Pacific Northern Gas Ltd. (PNG-West and Granisle) for Approval of 2006 Rates
BEFORE: L.A. Boychuk, Panel Chair and Commissioner August 16, 2006 O R D E R WHEREAS: A. On November 30, 2005, Pacific Northern Gas Ltd. (“PNG”, “PNG-West” and “Granisle”) filed for approval of its 2006 Revenue Requirements Application (the “Application”) to amend its rates on an interim and final basis, effective January 1, 2006, pursuant to sections 89 and 58 of the Utilities Commission Act (the “Act”); and
B. The Application proposes to increase delivery rates to all customers, except Methanex Corporation (“Methanex”) and West Fraser-Kitimat (“West Fraser”), as a result of decreases in cost of service and decreased deliveries to most customer classes. Methanex and West Fraser have contracts in place that provide for fixed demand charges over the term of the contracts; and
C. Methanex closed its methanol/ammonia complex in Kitimat in November 2005 and the Methanex contract terminated effective March 1, 2006 (“Methanex closure”). PNG’s 2006 margin forecast includes fixed demand charges for January and February 2006 under the terms of the Methanex contract; and
D. In its Application PNG forecasts a 2006 revenue deficiency of approximately $5.2 million, which is mainly due to a reduction in revenues of approximately $10.4 million resulting from the Methanex closure. This revenue reduction is partly offset by PNG crediting to its cost of service $5.6 million from the contract termination payment of $23.3 million that Methanex paid to PNG on February 28, 2006; and
E. Following consideration of submissions on the review process for the Application the Commission, by Order No. G-134-05 dated December 16, 2005, scheduled an Negotiated Settlement Process (“NSP”) for the review of the PNG Application and established a Regulatory Timetable as proposed by PNG and supported by the BC Old Age Pensioners Organization et al. (“BCOAPO”); and
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ORDER NUMBER G -99-06 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102
BRITISH COLUMBIA UTILITIES COMMISSION
ORDER NUMBER G-99-06 2 F. Order No. G-134-05 also approved for PNG an interim refundable rate increase in the delivery rates for all classes of customers as filed in the Application effective January 1, 2006, except Methanex and West Fraser. That Order also approved permanent Gas Supply Cost Recovery Rates for sales service customers effective January 1, 2006. The Order also approved the PNG-West company use rate of $0.305/GJ as an interim rate effective January 1, 2006; and
G. The Negotiated Settlement discussions were held in Vancouver on March 13 to 15, 2006 and a proposed Settlement Agreement that would reduce PNG’s revenue deficiency to $4.091 million was circulated on March 31, 2006 to the Intervenors and PNG for comments; and
H. Following a review of the comments on the proposed Settlement Agreement, the Commission Panel considered that a further process should be established to review and consider Item 1, “Methanex Termination Payment” of the proposed Settlement Agreement. Accordingly, by Order No. G-40-06 dated April 7, 2006, the Commission approved a BCOAPO request for an additional round of information requests and established a timetable for information requests, information responses, submissions by PNG, Intervenor submissions and a PNG reply; and
I. By Letter No. L-19-06 dated May 17, 2006, the Commission Panel sought further specific written submissions from those parties who had submitted written argument based on the evidentiary record established in this proceeding. Letter No. L-19-06 contained Commission Panel questions and established a timetable for written responses by PNG and BCOAPO to questions relating to their submissions, the filing of a response by BCOAPO and Mr. Childs and a reply by PNG. The Commission Panel indicated that it would consider the additional submissions based on the evidentiary record for this proceeding prior to making a decision on PNG’s Revenue Requirements Application and the proposed Settlement Agreement; and
J. The Commission Panel reviewed the submissions made by PNG, BCOAPO and Mr. Childs, the proposed Settlement Agreement for PNG-West and the letters of comment received from the Intervenors. The Commission Panel determined that in view of the position of BCOAPO, the Commission Panel did not have a proposed Settlement Agreement before it for approval and it therefore was not in a position, as outlined in Order No. G-66-06 dated June 9, 2006 and the attached Reasons for Decision, to render a decision without further process, including a decision in relation to Item 1 of the proposed Settlement Agreement; and
K. By Order No. G-66-06 the Commission Panel also concluded that before establishing a further process, the views of parties must be obtained in an effort to establish the most effective and efficient process possible at that stage. Order No. G-66-06 established a timetable for the filing of comments by BCOAPO and other registered intervenors and PNG reply comments, including submissions on appropriate steps and timing for either an oral and/or written hearing process, the issues to be considered, confirmation of the issues that may have been resolved during the NSP, and the nature of any evidence to be filed and justification therefore; and
L. The Commission Panel reviewed the submissions made by PNG, BCOAPO and Mr. Childs and, by Order No. G-77-06 dated June 28, 2006, closed the evidentiary record and established a timetable for the filing of Argument with PNG’s Argument required by July 7, 2006, Intervenor Argument by July 17, 2006 and PNG Reply Argument by July 24, 2006; and
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BRITISH COLUMBIA UTILITIES COMMISSION
3 M. The Commission Panel has considered the Application, the evidence adduced in relation thereto, the submissions and Written Argument, all as set forth in the Reasons for Decision attached as Appendix A and issued concurrently with this Order.
NOW THEREFORE pursuant to Sections 58, 60 and 61 of the Act the Commission orders as follows: 1. The Commission approves for PNG its Application subject to the required adjustments set out in the attached Reasons for Decision.
2. Since the approved rates are less than the interim rates that have been in effect since January 1, 2006, PNG is to inform its customers of the final rates by way of a Customer Notice and provide a method for refunding excess payments back to customers.
3. PNG is to file permanent Gas Tariff Rate Schedules that are in accordance with the terms of this Order and Reasons for Decision.
4. PNG is to file a complete set of detailed schedules contained under Tab Rates and Tabs 1 to 5 of the Application that reflects the adjustments required by this Order and Reasons for Decision, by September, 8, 2006.
DATED at the City of Vancouver, in the Province of British Columbia, this 21 st day of August 2006. BY ORDER Original signed by: L.A. Boychuk Panel Chair and Commissioner
Attachment
Orders/PNGW_2006RR Reasons for Decision
ORDER NUMBER G-99-06
APPENDIX A to Order No. G-99-06 Page 1 of 33
An Application by Pacific Northern Gas Ltd. (PNG-West and Granisle) for Approval of 2006 Rates
REASONS FOR DECISION 1.0 THE APPLICATION On November 30, 2005, Pacific Northern Gas Ltd. (“PNG”, “PNG-West” and “Granisle”) filed for approval of its 2006 Revenue Requirements Application (the “Application”) to amend its rates on an interim and final basis, effective January 1, 2006, pursuant to sections 89 and 58 of the Utilities Commission Act (the “Act”). The Application proposed to increase delivery rates to all customers, except Methanex Corporation (“Methanex”) and West Fraser-Kitimat (“West Fraser”), as a result of decreases in cost of service and decreased deliveries to most customer classes. Methanex and West Fraser have contracts in place that provide for fixed demand charges over the term of the contracts.
Methanex closed its methanol/ammonia complex in Kitimat in November 2005 and the Methanex contract terminated effective March 1, 2006 (“Methanex closure”). PNG’s 2006 margin forecast includes fixed demand charges for January and February 2006 under the terms of the Methanex contract. In its Application, PNG forecast a 2006 revenue deficiency of approximately $5.2 million, which is mainly due to a reduction in revenues of approximately $10.4 million resulting from the Methanex closure. This revenue reduction is partly offset by PNG crediting to its cost of service $5.6 million from the contract termination payment of $23.3 million that Methanex paid to PNG on February 28, 2006.
On February 17, 2006 PNG revised the Application to reflect 2005 year-end actual results and to include updates to customer counts, use per account and reclassification of customers, which reduced the 2006 revenue deficiency to $4.034 million (Exhibit B-10). On March 9, 2006, PNG advised the Commission and Registered Intervenors that the Commission’s decision to increase the 2006 benchmark low-risk utility return on equity to 8.80 percent by Order No. G-14-06 dated March 2, 2006, would increase PNG’s allowed return on common equity under the Commission’s automatic adjustment formula from 8.94 percent to 9.45 percent and increase PNG’s 2006 revenue deficiency to $4.435 million (Exhibit B-13).
APPENDIX A to Order No. G-99-06 Page 2 of 33
2.0 THE REGULATORY PROCESS PNG had discussions regarding the review process for the Application with the BC Old Age Pensioners Organization et al. (“BCOAPO”) and staff of the Ministry of Energy, Mines and Petroleum Resources, who were the active intervenors in the review of the PNG 2004 and 2005 revenue requirements applications (the “Parties”). By letter dated December 13, 2005, PNG advised the Commission that the Parties were of the view that the Application should be subject to a Negotiated Settlement Process (“NSP”) and provided a draft Regulatory Timetable for information requests, information responses, a 2005 year-end update to the Application and NSP discussions commencing the week of March 13, 2006 (Exhibit B-2). The draft Regulatory Timetable did not include a provision for Intervenor evidence and related information requests and responses. On December 14, 2005 BCOAPO filed a letter of support for a NSP and PNG’s proposed Regulatory Timetable (Exhibit E-1).
By Order No. G-134-05 dated December 16, 2005 (Exhibit A-1), the Commission approved for PNG an interim refundable rate increase in the delivery rates for all classes of customers as filed in the Application effective January 1, 2006, except Methanex and West Fraser. Order No. G-134-05 also scheduled an NSP for the review of the PNG Application and established a Regulatory Timetable for information requests and information responses with NSP discussions to commence on March 13, 2006 as proposed by PNG and supported by BCOAPO.
During the course of this process, the Commission also received numerous letters of comments and form letters expressing concern about the proposed rate increase and a petition containing over 4,000 signatures (Exhibit C11-4) that also opposed the Application.
3.0 THE PROPOSED SETTLEMENT AGREEMENT The NSP discussions were held in Vancouver on March 13 to 15, 2006. The following Intervenors participated: BCOAPO, Robin Austin, MLA-Skeena, Mayor Talstra of Terrace, Neil Helland and counsel for the Haisla Nation. Following the conclusion of the negotiations, a proposed Settlement Agreement that would reduce PNG’s revenue deficiency to $4.091 million was circulated to those who participated in the settlement discussions. By letter dated March 28, 2006, PNG advised the Commission that the final copies of the proposed Settlement Agreement and letters of comment would be forwarded to the Commission for review and made public on March 31, 2006. PNG’s letter asked the Commission to issue an order approving the proposed Settlement Agreement on an interim or permanent basis by April 7, 2006 to coincide with the Gas Supply Cost Recovery Rates that were approved effective April 1, 2006. The letter also advised that “one of the parties may
APPENDIX A to Order No. G-99-06 Page 3 of 33
be making a request to have one matter dealt with by the Commission that would not change the overall 2006 cost of service agreed to for the PNG-West division”. The proposed Settlement Agreement included Bill Comparison Tables for residential and small commercial customers, which indicated that the proposed rates for delivery charges and gas supply cost recovery rates effective April 1, 2006, would be less than the rates that prevailed at the end of 2005.
Letters of comment on the proposed Settlement Agreement were received from the BCOAPO, the Haisla Nation, Robert W. Childs, Mayor Talstra of Terrace, Robin Austin, MLA-Skeena and the Kitimat Chamber of Commerce. In its letter of comment dated March 29, 2006, BCOAPO advised that it did not accept the proposed Settlement Agreement and in particular Item 1 which “represents the fundamental gist of the agreement in that it purports to transfer the entire shortfall arising from Methanex leaving the PNG-West system to the residential and small commercial customers”. BCOAPO stated that it did not have any objection to the remainder of the proposed Settlement Agreement and had no objection to PNG’s request to have the rates that would arise from the proposed Settlement Agreement approved on an interim basis, pending resolution of the allocation of the Methanex revenue shortfall. In the letter, BCOAPO expressed its position as follows: “[It] is BCOAPO’s position that the question of the proper allocation of the revenue shortfall arising from Methanex leaving the PNG-West system should properly be addressed by a Commission panel and should not be the subject of a negotiated settlement.” BCOAPO also expressed the view that an oral hearing and a full 2006 Revenue Requirements proceeding was not necessary. It suggested that the issue could be resolved in a written hearing process with an additional round of information requests to PNG-West to ensure that all necessary and appropriate evidence is before the Commission.
Robert Childs’ comments were similar to those of BCOAPO, except that he recommended that “the 06/01/01 Interim Rates remain in effect until a Final Commission Ruling is made”. The Haisla Nation accepted PNG’s commitment to work with the Haisla Nation and took no position on the remainder of the proposed Settlement Agreement. Mayor Talstra in his letter of comment dated April 5, 2006, found the proposed Settlement Agreement to be acceptable provided that the new rates, including gas supply costs charges remain in effect throughout 2006. In his letter dated April 6, 2006, Robin Austin did not agree with PNG’s proposal that the lost revenue from the Methanex contract should be downloaded to residential and commercial customers and requested a written hearing to resolve this issue. The Kitimat Chamber of Commerce in its email dated April 6, 2006 protested PNG’s increased delivery charges and asked for the review process to continue.
APPENDIX A to Order No. G-99-06 Page 4 of 33
By letter dated April 3, 2006, PNG requested that the Commission approve rates arising from the proposed Settlement Agreement on either a permanent basis or on an interim basis pending review of the issue raised in BCOAPO’s letter of comment dated March 29, 2006. In support of its request that the Commission approve the 2006 NSP rates on a permanent basis, PNG cited previous Commission decisions on the allocation of revenue reductions to PNG’s customers and suggested that by allocating the revenue reduction to the remaining customers, the Commission would carry out its statutory duty consistent with past practice. PNG further submitted that allocating any of the remaining revenue deficiency to PNG’s shareholders would contravene section 59(5)(b) of the Act. PNG recommended that the Commission issue an Order on April 7, 2006 reconfirming its past practice and approving the NSP 2006 rates on a permanent basis. In the alternative, PNG submitted that should the Commission decide to conduct a hearing as requested by BCOAPO, then the BCOAPO “has effectively become the applicant in this situation” and should be directed to file evidence upon which all parties should be given an opportunity to issue information requests to BCOAPO.
By letter dated April 4, 2006, BCOAPO commented on PNG-West’s brief review of past Commission decisions and submitted that the question of how section 59 of the Act should be applied in PNG-West’s current situation is a matter that requires determination by the Commission after hearing submissions from appropriate parties. BCOAPO agreed that the record was “essentially complete”. While it did not propose to adduce further evidence, BCOAPO did request further Commission process on the main issue, including a round of information requests to ensure that relevant information, which was not included in the formal record but referred to in the course of the NSP by PNG, became part of the public record.
The BCOAPO letter concluded with the comment: “In BCOAPO’s submission, its suggested process would result in a more focused and efficient consideration of the main issue than that proposed by PNG-West in its April 13, 2006 letter”.
The Commission reviewed the proposed Settlement Agreement for PNG-West and the letters of comment received. It accepted the BCOAPO request for a further process. By Order No. G-40-06, the Commission established a process to review and consider Item 1, “Methanex Termination Payment”, of the proposed Settlement Agreement. Order No. G-40-06 provided for an additional round of Intervenor information requests to PNG-West and set a filing deadline for Intervenor requests of April 18, 2006 with a PNG information response deadline of April 24, 2006. The Commission did not agree with PNG-West’s characterization of BCOAPO as an effective applicant in this situation and, accordingly, the Commission did not direct BCOAPO to file evidence. Order No. G-40-06 also set a timetable for submissions related to Issue 1 with a PNG filing deadline of April 28, 2006, followed by Intervenor submissions of May 4, 2006 and a PNG Reply of May 9, 2006.
APPENDIX A to Order No. G-99-06 Page 5 of 33
4.0 SUBMISSIONS ON ITEM 1 OF THE PROPOSED SETTLEMENT AGREEMENT PNG filed its submission on April 28, 2006. PNG stated in its April 28, 2006 submission that: “…there is a statutory obligation upon the Commission to fix rates that permit PNG the opportunity to recover all of its costs of providing service, including the fair rate of return on common equity approved for PNG by the Commission. Rates that are insufficient to enable a utility to recover its cost, including a fair and reasonable return, are unjust and unreasonable under the Utilities Commission Act”. PNG cited as the leading case authority Hemlock Valley Electrical Services v. British Columbia (Utilities Commission) (1992), 66 B.C.L.R (2d) 1 (C.A.) which, in turn, is based on the Supreme Court of Canada’s decision in British Columbia Electric Railway Co. Ltd. v. Public Utilities Commission of BC, [1960] S.C.R. 837 (“Hemlock Valley” and “B.C. Electric”, respectively). In PNG’s view these decisions focus on what are now substantially the provisions found in subsections 59(1), (4), (5) and 60(1) of the Act (PNG April 28, 2006 submission, paragraphs 4-12).
PNG also referred to the Commission’s findings in the 2002 PNG Revenue Requirements Decision with respect to a 2002 revenue reduction from the methanol plant shutdown in 2001 and a new negotiated agreement with Methanex (the “2002 Decision”). The 2002 Decision noted that the allocation of the revenue deficiency from Methanex to the other customers is consistent with previous actions of the Commission. The 2002 Decision also found that rates to all customer classes remained affordable at that time (PNG April 28, 2006 submission, paragraph 17).
The BCOAPO filed its Reply Argument on May 4, 2006. BCOAPO agreed that Hemlock Valley and B.C. Electric are applicable to the regulation of utilities in British Columbia; however, it submitted that the Commission must consider how these decisions should be applied to a utility in PNG’s situation. BCOAPO quotes from the judgment of Mr. Justice Martland in B.C. Electric which states in part, “The rate to be imposed [under what is now section 60 of the Act having regard to what are now subsections 59(5)(a) and (b) of the Act] shall be neither excessive for this service nor insufficient to provide a fair return on rate base. There must be a balancing of interests.” BCOAPO further submitted that Hemlock Valley and B.C. Electric must be considered in the light of ATCO Gas & Pipelines Ltd. v. Alberta (Energy & Utilities Board), 2006 SCC 4 (“ATCO”). BCOAPO argues that the Supreme Court in Canada in ATCO “…has appropriately set out a balance between shareholders and ratepayers in the allocation of the revenue requirement shortfall that the utility faces” and urges the Commission to follow the approach in ATCO (BCOAPO May 4, 2006 submission, paragraphs 27-38).
APPENDIX A to Order No. G-99-06 Page 6 of 33
BCOAPO concluded its submission as follows: 45. For all these reasons BCOAPO submits that approval of Item 1 of the Settlement Agreement would result in rates to residential customers which are not just and reasonable.
46. The Commission should not approve Item 1 of the Settlement Agreement. Mr. Childs also filed a submission on Item 1. He expressed the view that the remaining customers should not be solely responsible for the revenue shortfall arising from the Methanex closure. At the end of his submission, he made the following suggestions:
(1) PNG recover 100% of their audited costs to physically supply gas to customers. (2) The rest of the Methanex closure shortfall should be shared equally between the PNG shareholders and the remaining customers, provided that the gas delivery charge does not exceed:
(i) the existing proposed average increases in Hydro, ICBC insurance rates or property taxes. (ii) the cost of inflation by more than 100%. PNG filed its Reply Submission on May 9, 2006. It noted that with the exception of Item 1, all other aspects of the proposed Settlement Agreement had been agreed to by the Parties. PNG took issue with a number of the factual assertions made by the BCOAPO, distinguished ATCO on the basis that ATCO did not involve the setting of just and reasonable rates and submitted that Hemlock Valley and B.C. Electric remain the governing law, noting that Hemlock Valley was cited with approval recently in TransCanada Pipelines Ltd. v. Canada (National Energy Board), [2004] FCA 149.
PNG also took issue with Mr. Childs’ submissions relating to the interpretation of sections 59 and 60 of the Act and submitted that a number of Mr. Childs’ submissions were inaccurate or irrelevant. PNG concluded its Reply as follows:
25. To allocate any of the net revenue deficiency resulting from the termination of the Methanex contract to PNG’s shareholders, as advocated by BCOAPO and Mr. Childs, would result in rates that do not permit PNG to recover its costs of providing service and would therefore contravene sections 59 and 60 of the Utilities Commission Act.
26. PNG reiterates its request that the Commission approve the March 15, 2006 Settlement Agreement in its entirety, including Item 1.
APPENDIX A to Order No. G-99-06 Page 7 of 33
By Letter No. L-19-06, the Commission Panel sought further specific written submissions from those parties who had submitted written argument based on the evidentiary record established in the proceeding. Letter No. L-19-06 contained Commission Panel questions and requested that PNG and BCOAPO, as appropriate, file further written responses that relate to their written submissions, by Monday, May 29, 2006 and that BCOAPO and Mr. Childs, if he so wished, file a response by Friday, June 2, 2006, followed by a PNG reply by Wednesday, June 7, 2006. The Commission Panel indicated that it would consider these additional submissions based on the evidentiary record for the proceeding prior to making a decision on PNG’s Revenue Requirements Application and the proposed Settlement Agreement.
5.0 RESPONSES TO LETTER NO. L-19-06 AND SUBMISSIONS PNG, BCOAPO, and Mr. Childs all responded to the questions in Letter No. L-19-06 within the times provided. The Commission Panel only intends to refer here to certain answers of BCOAPO and the PNG reply to those answers. In response to Question 1 [“Is it the fact that parties have agreed to all aspects of the proposed Settlement Agreement, but for Item 1, that brings Hemlock Valley into operation?”], BCOAPO’s response was “No”. It stated that Item 1 was “clearly the major [d]river of the proposed revenue requirement increase” that other items were secondary and that by agreeing to those other items the Parties could avoid a full hearing into all aspects of the Application and focus on the major issue. Significantly, BCOAPO stated that “…the evidentiary record in this proceeding is not sufficient to allow the Commission to make an appropriate apportionment between the remaining ratepayers and PNG’s shareholders of the revenue deficiency resulting from Item 1”. It submitted that evidence with respect to the appropriate return on equity risk premium for PNG post-Methanex and on the methodology for determining an appropriate allocation of the revenue deficiency is now required (BCOAPO Response, May 29, 2006, pp. 1 and 2).
In partial response to Question 5 in Letter No. L-19-06 [“…the Commission remains unclear and seeks clarification related to the level of apportionment that BCOAPO suggests would be appropriate, the principles or methodology BCOAPO suggested should be applied, and the evidentiary basis on the record of this proceeding upon which BCOAPO relies to allow the Commission to do so.”], after stating its position that there is no proposed Settlement Agreement before the Commission for approval, BCOAPO submitted that once the Commission has made its decision on Item 1, the NSP should reconvene and:
If a Settlement Agreement is reached it would then be presented to the Commission for approval. If no Settlement Agreement is reached the matter would then proceed to an appropriate hearing or, alternatively, it would be open to PNG to amend its application.
APPENDIX A to Order No. G-99-06 Page 8 of 33
The BCOAPO once again submitted in its response to Question 5 that there is an insufficient evidentiary record before the Commission to make a decision (BCOAPO Response May 29, 2006, p. 2) and in paragraph 1 of its response dated June 2, 2006, BCOAPO reiterated its position that there is no proposed Settlement Agreement before the Commission at this time.
In its Reply Submission dated June 6, 2006, PNG addresses BCOAPO’s most recent submissions on the absence of a settlement and the need for further evidence and process. In paragraph 7 of its Reply under the heading “BCOAPO’s Shifting Position”, PNG provides the following summary of the BCOAPO position prior to May 29, 2006:
7. Prior to its May 29, 2006 filing, BCOAPO’s position can be summarized in its own words as follows:
(a) BCOAPO “does not accept Item 1 of the Negotiated Settlement Agreement”, but “does not have any objection to the remainder of the proposed Negotiated Settlement Agreement.” (March 29, 2006 letter, page 1) (b) “it is BCOAPO’s position that the question of the proper allocation of the revenue shortfall arising from Methanex leaving the PNG-West system should properly be addressed by a Commission panel.” (supra, page 2) (c) “BCOAPO is prepared to cooperate in expediting the resolution of this issue. It does not believe that an oral hearing is necessary; certainly a full 2006 Revenue Requirement proceeding is not necessary.” (supra, page 2) (d) “BCOAPO submits that this issue can appropriately be resolved in a written hearing process, provided that parties are given an opportunity to address an additional round of information requests to PNG-West to ensure that all necessary and appropriate evidence is before the Commission.” (supra, page 2) (e) “BCOAPO agrees that the record in this proceeding is essentially complete. It would not propose to adduce further evidence. However, it is requesting a limited round of information requests, simply for the purpose of ensuring that relevant information, which is not included in the formal record but which was referred to in the course of settlement negotiations by PNG is a part of the record.” (April 4, 2006 letter, page 2)”
At paragraph 9 of its June 6, 2006 Reply, PNG comments as follows: “It is disingenuous for BCOAPO to have asked the Commission to make a decision with respect to Item 1 pursuant to this written proceeding after telling the Commission it has no objection to the remainder of the Settlement Agreement, and to then turn around and say it is not in a position to make “meaningful submissions” to the Commission with respect to Item 1, that the Commission now needs to embark on some further process to determine this issue and that after
APPENDIX A to Order No. G-99-06 Page 9 of 33
the Commission makes a decision the settlement process should “reconvene” taking into account the Commission’s decision…”.
In PNG’s submission, no further information is needed for the Commission to make a decision on Item 1 and BCOAPO’s relative risks theory to apportion the revenue deficiency has no merit (PNG’s June 6, 2006 Reply, paragraphs 10-14).
In the “Conclusion” of its June 6, 2006 Reply, PNG requests a timely decision by the Commission without additional process noting that six months have passed since PNG filed its Application and it has credit facilities that are maturing on July 24, 2006.
In its Reasons for Decision and Order No. G-66-06, the Commission Panel found that BCOAPO’s submissions made it clear that there was no agreement before the Commission Panel to approve. The Commission Panel stated that it was not prepared to impose a settlement on the parties in this proceeding, which would be the effective result if it accepted the PNG submissions on the proposed settlement.
The Commission Panel also determined that it was not in a position to decide the Application, including Item 1 of the proposed Settlement Agreement, without further process. In an effort to establish an effective and efficient process, the Commission Panel requested submissions from all Parties related to appropriate steps and timing for either an oral and/or written hearing process, the issues to be considered, confirmation of the issues that may have been resolved during the NSP, and the nature of any proposed evidence to be filed and a justification for such evidence.
On the basis of BCOAPO’s May 29 and June 2, 2006 submissions, it appeared that Item 1 and now Item 17, “Return on Equity and Capital Structure” of the proposed Settlement Agreement are the aspects of the Application which, in BCOAPO’s view, remain in dispute. In an effort to limit the issues and any additional evidence to be adduced in this proceeding, the Commission Panel sought to confirm whether any or all other aspects of the Application continue to be accepted by the NSP participants as set forth in the document styled “Negotiated Settlement Agreement” and dated March 15, 2006.
The Commission Panel noted that there had been ample opportunity for all parties to develop an evidentiary record and that it did not consider it appropriate at that late stage to embark upon a further and more extensive examination of the issues that should have been properly developed by that time. The Panel, therefore, indicated that it would require a detailed explanation of the nature of any further evidence proposed and a justification for
APPENDIX A to Order No. G-99-06 Page 10 of 33
such evidence. By Order No. G-66-06, the Commission Panel requested that BCOAPO and any other Registered Intervenors provide comments on the nature and extent of the further process by Friday, June 16, 2006 and that PNG provide reply comments by Monday, June 19, 2006.
6.0 SUBMISSIONS IN RESPONSE TO COMMISSION ORDER NO. G-66-06 BCOAPO, Mr. Childs and PNG filed submissions in response to Order No. G-66-06 and the Commission Panel’s request.
In BCOAPO’s view, there were two separate but related issues related to Item 1 of the proposed settlement agreement:
1. the proper regulatory treatment of the revenue requirement shortfall from the loss of Methanex; and 2. the appropriate application of the Commission’s decision with respect to (1). BCOAPO considered that the issue of the proper regulatory treatment of the revenue shortfall arising from the loss of Methanex is a legal question requiring a Commission decision with respect to the statutory requirements of the Act as judicially interpreted and considered in the light of PNG’s present situation. BCOAPO did not believe that it could usefully add anything further to the submissions already before the Commission on this issue. BCOAPO stated that “once the commission’s decision has been issued, the remaining issues could be easily resolved …”.
BCOAPO advocated an oral hearing to address the two separate but related issues arising with respect to Item 1. BCOAPO stated that it would be prepared to call evidence on the appropriate allocation of the Methanex revenue shortfall at such a hearing and would be prepared to respond to information requests, if the Commission so required, and that it should be open to PNG to file such further evidence as it considered appropriate on this issue. BCOAPO attempted to justify its request to file this evidence by stating that “what is presently before the Commission does not appropriately address this issue”.
With respect to any issues that may have been resolved during the NSP, BCOAPO’s position was that “final resolution of any of these issues is dependent on the Commission’s decision with respect to the appropriate regulatory treatment of the Methanex revenue shortfall”.
APPENDIX A to Order No. G-99-06 Page 11 of 33
Mr. Childs submitted that a written hearing process would be more appropriate and expedient and that it should include an initial round of written negotiating positions by PNG and participating intervenors followed by a second and final round of revised negotiating positions, as appropriate. He also proposed a number of issues to be considered in this process.
PNG also proposed a written process based on the evidentiary record established to date. PNG submitted that there is an extensive evidentiary record before the Commission on which the Commission can make a decision with respect to the Application.
In the Reasons for Decision attached to Order No. G-77-06, the Commission Panel noted that there have been three rounds of information requests to date and opportunities for submissions. The Commission Panel further noted and that BCOAPO had not previously requested that it be allowed to file evidence when given the opportunity to do so when the Commission Panel sought submissions to establish a process to consider Item 1 of the proposed settlement document. The Commission Panel also observed that while BCOAPO had requested the opportunity to file further evidence, it had not explained or provided any substantive justification for the introduction of new evidence to the extent required by Order No. G-66-06.
Having received no submissions in response to its request in Order No. G-66-06 that could assist the Commission Panel to understand the nature and extent of evidence that BCOAPO considered would be helpful in the decision-making process, the Commission Panel concluded that no further evidence was necessary and that the further process to consider the Application would be a written process consisting of Argument by PNG, Intervenor Argument and PNG Reply Argument.
In the Reasons accompanying Order No. G-77-06, the Commission Panel rejected PNG’s alternate proposal which would have allowed PNG to simply confirm that its applied-for cost of service for rate making purposes was that set out in the regulatory schedules attached to the proposed settlement document. The Commission Panel’s purpose in so doing was to avoid the possibility of improperly narrowing the scope of argument. The Commission Panel also again refused to adopt the approach advocated by BCOAPO that would result in an advance ruling on the issue of the proper regulatory treatment of the revenue requirement shortfall from the loss of Methanex (Order No. G-77-06, Appendix A, p. 5 of 6).
By Order No. G-77-06, the Commission closed the evidentiary record and established a timetable for the filing of Argument with PNG’s Argument required by July 7, 2006, Intervenor Argument by July 17, 2006 and PNG Reply Argument by July 24, 2006.
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7.0 ARGUMENT FILED IN RESPONSE TO ORDER NO. G-77-06 7.1 PNG ARGUMENT PNG filed its Argument on July 7, 2006 and requested approval of its 2006 revenue deficiency as set out in the proposed settlement document of $4.091 million, rather than the revised revenue deficiency of $4.435 million contained in the updated Application (Exhibit B-13). PNG’s Argument addressed its 2006 Revenue Requirements by topics of Cost of Service, Rate Base, Deferral Accounts, Gas Deliveries and Margin Forecasts, Customer Rates and Just and Reasonable Rates. PNG’s Argument also included summary regulatory schedules for the Cost of Service Comparison, Utility Income and Return, Utility Rate Base, Income Taxes, Common Equity and Return on Capital.
7.1.1 Cost of Service Operating, Maintenance, General and Administrative Expenses Operating, Maintenance, General and Administrative Expenses, excluding the company use gas costs, have increased to $13.997 million in 2006 from $13.539 million under the NSP 2005 settlement (“NSP 2005”). Operating expenses (net of transfers to capital and company use gas costs) are $212,000 higher than 2006 primarily due to the salary adjustment provisions of a three-year collective agreement that was effective November 1, 2004. Maintenance expenses are expected to be $39,000 higher in 2006, which PNG described as being consistent with actual costs from 2001 to 2005. Administrative and general expenses in 2006 are budgeted to be about $207,000 higher than 2005 mainly due to increased labour and employee benefits costs offset by a reduction in PNG’s share of the Commission’s administrative costs.
Other Cost of Service Items A net decrease of $159,000 has occurred in 2006 from NSP 2005 related to transfers to capital, property taxes, depreciation, amortization and other income. PNG notes that a significant increase in property taxes has been offset by lower depreciation expense, higher transfers to capital and a substantial increase in the shared service cost recoveries from Pacific Northern Gas (N.E.) Ltd. (“PNG (N.E.)”).
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Income Tax Expense and Return on Rate Base The revenue requirement for income taxes, return on common equity, short-term and long-term debt interest and preferred share dividends has decreased by $1,252,000 to $14.620 million in Test Year 2006 from $15.872 million in NSP 2005. The decrease is due to lower income tax rates, lower depreciation expense and lower return on common equity.
The return on common equity of $4,959 million for 2006 compared to $5,857 for NSP 2005 is due to increases in the allowed rate of return on common equity offset by decreases in rate base (PNG Argument, p. 18). PNG is requesting a risk premium of 65 basis points above the low risk benchmark utility and a deemed common equity component of 40 percent. For years PNG’s allowed risk premium was 75 basis points which was reduced to 65 basis points in the PNG 2004 Revenue Requirement Decision. PNG submits that a 65 basis point relative risk premium is the minimum acceptable level having regard to PNG’s risk profile. PNG anticipated it would be able to access the debt market in mid-2006 and achieve and maintain an equity component of 40 percent but with it being later in the year and its actual equity component being above 40 percent, the actual return on equity will be lower than forecast.
7.1.2 Rate Base PNG’s forecast mid-year 2006 rate base has decreased to $131.2 million from $133.5 million in NSP 2005. PNG performed a review of its transmission system to determine which facilities are required to provide safe, reliable and efficient service to its remaining customers following the closure of the Methanex plant. PNG determined that it could deactivate compressor stations R2 and R4, a 10 inch loop (52.8 miles in length), a 6 inch lateral to Kitimat (32.97 miles in length) and a Methanex meter and regulating station. These assets have in-service dates of 1968-69 and 1981-82 with an original cost of $15.581 million and a depreciated value on December 31, 2005 of $5.05 million.
PNG is seeking Commission approval to transfer the net book value of $5.05 million of these assets from plant in-service to a non-rate base interest bearing deferral account effective January 1, 2006. PNG is also requesting that the account be amortized on a monthly basis over 10 years commencing January 2006. PNG is also seeking approval that a notional account be set up as described in Exhibit B-1, Tab Application, page 7 to record the risk-weighted foregone return and if the plant is returned to service then the unamortized deferral account balance and the risk-weighted foregone return will be added back to plant in-service.
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7.1.3 Deferral Accounts Information on PNG’s deferral accounts is found in Exhibit B-10, Tab 2, pages 10 to 12 with a subsequent correction made to reduce the amortization expense from $928,000 to $901,000. The amortization expense for the deactivated facilities is forecast to be $668,000 in 2006. A depreciation adjustment credit deferral amortization of $658,000 for over-depreciated assets is described in Exhibit B-10, Tab 2, page 11 with background information provided in Exhibit B-10, pages 2 to 3.
By letter dated October 4, 2005 PNG applied to the Commission for approval to record the contract termination payment of approximately $23.3 million in an interest bearing deferral account to the benefit of customers. The amount to be amortized each year is to be proposed in the annual revenue requirements application and is subject to approval by the Commission. This treatment was accepted in the 2005 NSP.
PNG is proposing to amortize the termination payment over the 44-month period from March 2006 to October 2009 to coincide with the original expiry date of the Methanex contract. PNG is seeking Commission approval to amortize $5.553 million of the contract termination payment in 2006 rates.
PNG is also seeking Commission approval to amortize the customers’ $169,855 after tax share of the income trust application hearing costs at 20 percent per year commencing in 2006.
7.1.4 Gas Deliveries and Margin Forecasts PNG forecasts deliveries to its customers for 2006 that are lower than the volumes used in the 2005 NSP. The 2006 volumes are about 25.7 TJ lower than 2005 NSP with 25.4 TJ of the volume decrease due to the Methanex closure. The total decrease in margin of approximately $10.8 million in 2006 compared to NSP 2005 is primarily due to the decrease in the Methanex margin of about $10.4 million. The remainder of the volume and margin decrease is mainly due to declines in use per account. The use per account of residential customers has decreased to 82.4 GJ in 2006 compared to 84 GJ in NSP 2005. The small commercial use per account is forecast to decrease to 361.3 GJ in 2006 from 366.3 GJ in NSP 2005. PNG attributes the decline in residential/small commercial use per account to high gas commodity costs and the current economic conditions in PNG’s service area. The deliveries to small industrial customers are forecast to be slightly higher in 2006 by 14,000 GJ compared to NSP 2005. However, due to changes in the composition of the class, the 2006 margin is expected to decrease by $47,600 from NSP 2005. The Methanex contract terminated at the end of February 2006 and PNG recorded the Methanex margin for January and February 2006 under the small commercial class. The small
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commercial class is forecast to have a decrease in deliveries of 14,000 GJ in 2006 compared to NSP 2005 but a decline in margin of $78,000. The 2006 deliveries to West Fraser are expected to decrease by 175,000 GJ in 2006 compared to NSP 2005 but the margin is expected to increase by $42,000. Deliveries to Alcan for 2006 are expected to be at historical levels, which results in a decrease in volumes of 32,000 GJ for 2006 and a decrease in margin of $52,000 compared to NSP 2005.
7.1.5 Customer Rates PNG is seeking Commission approval to adjust its 2005 customer rates to recover the 2006 revenue deficiency of $4.091 million. PNG is also seeking Commission approval of a 2006 RSAM (Revenue Stabilization Adjustment Mechanism) rate rider of $0.301/GJ to replace the interim rate rider of $0.26/GJ effective January 1, 2006. PNG is also seeking approval of its company use gas forecast and estimated cost, which would result in a permanent Company Use Gas Cost Rate of $0.185/GJ effective January 1, 2006 in place of the $0.305/GJ interim rate.
PNG provided a rate comparison table for residential Rate Schedule (“RS”) 1 class and the small commercial class RS 2 class that shows the components of delivery charges and gas commodity charges for December 31, 2005 and the applied-for rates for January 1, 2006, April 1, 2006 and July 1, 2006. Based on the 2006 forecast use per account of 82.4 GJ for residential and 361.3 GJ for small commercial, PNG calculates the annual bill using the applied-for delivery charge and gas commodity rates. The following table reproduces the PNG rate comparison table for the total delivery charge, commodity cost and annual bill.
Customer Class Dec. 31/05 Residential (RS 1) Delivery Charge $7.355 Commodity Charge $9.608 Total Gas Rate $16.963 Annual Bill using 82.4 GJ $1,398 Small Commercial (RS 2) Delivery Charge $6.280 Commodity Charge $9.651 Total Gas Rate $15.931 Annual Bill using 361.3 GJ $5,756 PNG estimates that the termination of the Methanex contract will result in about a $100 per year increase in delivery charges for residential customers.
($/GJ) Jan. 1/06 Apr. 1/06 Jul. 1/06 $8.602 $8.602 $8.602 $9.895 $8.245 $7.475 $18.497 $16.847 $16.077 $1,524 $1,388 $1,325 $7.337 $7.337 $7.337 $9.873 $8.223 $7.458 $17.210 $15.560 $14.795 $6,218 $5,622 $5,345
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PNG is also seeking Commission approval of revised rate structures for its RS 4, RS 5 and RS 6 customer classes as shown in Exhibit B-1, Tab Application, pages 48 to 52 with the following modifications that were discussed during the NSP process in March 2006:
a) A monthly fixed charge of $125 is to apply to the RS 4 customer class instead of no monthly fixed charge as originally proposed by PNG.
b) The tariff for the RS 6 seasonal off-peak customer class would extend the off-peak period to include November and March subject to PNG adding a provision to its tariff providing PNG with the right to curtail service in November and March to meet the gas requirements of its year round firm customers.
7.1.6 Just and Reasonable Rates PNG’s submissions regarding the Commission’s obligation to fix rates that permit PNG the opportunity to recover all of its cost of providing service (including the fair rate of return on common equity approved for PNG by the Commission are based on subsections 60(1) and 59(5) of the Act and are set out in PNG’s submissions dated April 28, May 9, May 29 and June 6, 2006 concerning Item 1 (Methanex Termination Payment) of the proposed Settlement Agreement. PNG adopts and relies on those submissions for the purposes of its final argument.
PNG argues that the revenue shortfall arising from the termination of the Methanex contract does not represent any specific costs of providing service but simply is the extent to which PNG’s overall cost of providing service exceeds forecast margin recovery now that Methanex has terminated its contract. PNG submits that disallowing recovery of any portion of the revenue deficiency would be an arbitrary disallowance of PNG’s forecast 2006 costs without evidentiary or legal basis for such a disallowance.
PNG submits that it has taken all reasonable and prudent steps to reduce its costs. It points to the major internal reorganization which included closing down of over-the-counter service offices and restructuring its head office when Methanex shut down for one year starting on July 1, 2000. PNG also submits that it has reduced its 2006 costs by:
• deactivating facilities in response to the Methanex closure and earning a short-term interest rate return on the unamortized balance of those facilities rather than a rate base rate of return. The deactivation is expected to reduce property taxes by $300,000 per year starting in 2007.
• using a 40 percent deemed equity component rather than its significantly higher actual common equity component.
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• seeking and obtaining approval to reduce its share of Commission costs in 2006 from $323,000 to $70,303. • by removing employee bonuses from pensionable earnings in calculating pension benefit costs resulting in a reduction of $74,000 in the applied-for 2006 company benefits.
• a unilateral lump sum credit of $200,000 applied to 2006 cost of service. In PNG’s submission, the Application, as summarized in the schedules attached to its Argument, based on the information responses and submissions filed subsequent to the conclusion of the NSP settlement discussions, fully support a Commission finding that the 2006 rates applied for by PNG are just and reasonable.
7.2 BCOAPO ARGUMENT BCOAPO filed its Argument on July 17, 2006 and states that the key issue in this proceeding is whether the Act, particularly section 59, as interpreted by the Courts, requires the Commission to allocate all of the revenue requirement shortfall arising from the closure of the Methanex Kitimat plant to ratepayers. BCOAPO states that it is PNG’s position that it does, while BCOAPO’s submission is that it does not. BCOAPO refers to its submissions on this legal issue in its May 4, 2006 Reply Argument. BCOAPO comments that if it was possible to reach agreement on this issue that was acceptable to the Commission then other issues would likely have been resolved along the lines suggested in the proposed Settlement Agreement.
BCOAPO states that its concern is not solely with the impact on ratepayers in 2006 but the continuing impact to allocate all of the Methanex revenue requirement shortfall to ratepayers and the increased impact when the deferred Methanex termination payments end in 2009. BCOAPO submits that this issue has to be addressed now particularly in light of the impact of the Supreme Court Decision in ATCO. In BCOAPO’s view, the Commission must decide on the basis of legal arguments before it whether the responsibility for the Methanex revenue requirements shortfall should be for: a) PNG’s ratepayers; b) PNG shareholders; or c) some combination of the two. BCOAPO acknowledges that this third option involves some determination by the Commission of the appropriate allocation. In the absence of specific evidence on this issue, BCOAPO submits that a 50/50 split would not be inappropriate. BCOAPO states that once that decision is made, given Commission Order No. G-77-06 and for the purpose of establishing PNG’s 2006 revenue requirements, all aspects of the proposed Settlement Agreement other than Item 1 can consider to be accepted by BCOAPO.
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With regards to Item 17 of the proposed Settlement Agreement, BCOAPO accepts that PNG’s return on equity for 2006 has been established by the Commission. BCOAPO refers to its previous submissions and states that it takes the position that the level of return on equity, particularly with respect to the risk premium has to be taken into account in determining the proper allocation of the Methanex revenue requirement shortfall.
7.3 CHILDS ARGUMENT Mr. Childs filed his Argument on July 17, 2006 which discusses rate affordability and suggests that the Commission Decision on the Application:
i) Start with a 50/50 apportionment between PNG’s shareholders and customers of the Methanex shortfall on net margin of $4.8 million as outlined in Item 1 of the proposed Settlement Agreement.
ii) Alternatively, use a 50/50 apportionment of the net revenue deficiency of $4.091 million as outlined in the proposed Settlement Agreement. Mr. Childs considered this alternative to be more realistic, more fair and would take into account PNG’s $709,000 of cost reductions.
7.4 PNG REPLY ARGUMENT PNG filed its Reply Argument on July 24, 2006. PNG submits that apart from the issue of recovery of the revenue deficiency arising from the termination of the Methanex contract, neither BCOAPO nor Mr. Childs have taken any issue with PNG’s applied-for 2006 revenue requirements. PNG notes that both BCOAPO and Mr. Childs persist in the assertion that the revenue shortfall arising from the termination of the Methanex contract can somehow be divorced from the cost of providing service. In PNG’s view, a disallowance of any of the revenue shortfall would simply be a disallowance of an equal amount of PNG’s costs.
PNG states that the proposed 50/50 split of the Methanex revenue shortfall between customers and the shareholders advocated by BCOAPO and Mr. Childs is arbitrary, has no evidentiary basis and would have a significant adverse effect on PNG and its customers. As an example, PNG states that it is very unlikely that it would be able to comply with its financial covenants under its operating/risk management lines of credit.
PNG submits that the BCOAPO makes a contradictory argument when it acknowledges that PNG’s return on equity for 2006 has been established by the Commission but then should be effectively reduced in 2006 because the revenue shortfall arising from the termination of the Methanex contract is a risk for which the shareholders had previously been compensated. PNG argues that this assertion by BCOAPO has no merit for the reasons
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outlined in paragraphs 8 to 14 and paragraphs 12 to 14 of PNG’s May 9, 2006 and June 6, 2006 reply submissions, respectively. PNG states that BCOAPO provided no substantive response to PNG’s submissions on this matter despite multiple opportunities to do so and that PNG’s marginally higher risk premium merely acknowledges that PNG’s industrial load exposes PNG to a greater risk of being uncompetitive compared to other utilities. It says the risk premium never compensated nor did the Commission intend to compensate PNG’s shareholders for the regulatory risk that the Commission would unilaterally set rates at levels insufficient to recover PNG’s cost of service.
PNG notes that Mr. Childs accepts PNG’s 2006 return on equity but continues to submit that PNG’s rates should be set on some notion of customer “affordability” rather than in reference to PNG’s cost of service. PNG states that “affordability” is not a test under the Act or the relevant case law. PNG argues that to the contrary, in exchange for the obligation to provide safe and reliable service, the Act requires that rates be fixed to provide the utility with the opportunity to recover its reasonably incurred costs, which are necessary to provide that service. PNG notes that there is no evidence in this case that PNG’s applied-for rates are unaffordable and the applied-for April 1, 2006 rates are lower than the rates that were approved and in effect on December 31, 2005.
In conclusion, PNG submits that there is a statutory obligation upon the Commission to fix rates that permit PNG the opportunity to recover all of its costs of service including the fair rate of return on equity already approved by the Commission. PNG states that the leading case authority is Hemlock Valley which is substantially based on B.C. Electric. PNG submits that rates which are insufficient to provide a utility the opportunity to recover its costs of providing service including the fair rate of return on equity are unjust and unreasonable under the Act. PNG states that it will be impossible to recover its costs of providing service, if as BCOAPO and Mr. Childs advocate, PNG is not allowed to recover the revenue shortfall resulting from the termination of the Methanex contract in its customer rates.
8.0 COMMISSION DETERMINATION After a considerable amount of process and submissions subsequent to having established a negotiated settlement process to consider PNG’s 2006 Revenue Requirements Application (“2006 RRA”), the Commission Panel is in a position to render a decision on PNG’s Application and the issues related thereto, particularly those raised by BCOAPO and Mr. Childs in their various submissions.
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Following a review of the submissions allowed by Order No. G-40-06 related to Issue 1 (Methanex Termination Payment) of the proposed settlement document dated March 15, 2006, the Commission Panel by Letter No. L-19-06 dated May 17, 2006,endeavoured to seek further submissions on issues raised by parties This included further submissions related to the application of Hemlock Valley, the relevance of “affordability” and the authority of the Commission to reduce rates, the principles or methodology and evidence that the Commission could use to determine an appropriate allocation of the revenue deficiency as requested by intervenors, and the precedential aspect of this Decision in respect of future revenue shortfalls related to the loss of Methanex.
In view of the responses received to Letter No. L-19-06, further process, and ultimately a different process, was required to consider PNG’s 2006 RRA.
The Reasons that follow will focus on two predominant issues raised by parties which, based on the proposed settlement document, have been termed: “Item 1 - Allocation of Revenue Deficiency”; and “Item 17 - Return on Equity and Capital Structure”. Consideration of these items will be followed by the Commission Panel’s determinations related to various elements of PNG’s 2006 RRA as outlined in PNG’s July 7, 2006 Argument which, the Commission Panel notes, do not appear to be in dispute.
I. Item 1: Allocation of the Revenue Deficiency BCOAPO reiterates in its July 17, 2006 Argument that the key issue in this proceeding is the “legal question” of whether the Commission is required to allocate to ratepayers all of the revenue requirement deficiency arising from the closure of the Methanex plant.
The arguments related to this issue are most fully discussed in BCOAPO’s May 4, 2006 Reply Argument and PNG’s May 9, 2006 Reply Submission which are summarized in section 4.0 of these Reasons for Decision.
Relevant Statutory Provisions and Case Law These arguments raise the question of the proper interpretation, in the light of relevant judicial decisions, of sections 59 and 60 of the Act¸ specifically 59(5) and 60(1)(b) which establish the requirement that the Commission set just and reasonable rates. Pursuant to 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,
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(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 or unreasonable for any other reason. Paragraph 59(4)(a) states that it is a question of fact, of which the commission is the sole judge, whether a rate is unjust and unreasonable, and section 60 provides that:
60(1) In setting a rate under this Act or the regulations (a) the commission must consider all matters that it considers proper and relevant affecting the rate, (b) the commission must have due regard to the setting of a rate that (i) is not unjust or unreasonable within the meaning of section 59. PNG submits that allocating any of the remaining deficiency to PNG’s shareholders would contravene paragraph 59(5)(b) of the Act, whereas BCAOPO submits that the question of how section 59 of the Act should be applied in PNG’s unique and current situation is a matter that requires Commission determination.
The Commission Panel agrees with both BCOAPO and PNG that the decisions of Hemlock Valley and B.C. Electric, both of which have considered sections 59 and 60 or similar predecessor provisions of the Act, are applicable to the regulation of utilities in British Columbia.
The Commission Panel, however, does not consider that the ATCO decision, which dealt with the question of whether the Alberta Energy and Utilities Board had the authority to allocate to ratepayers a portion of the gain on the sale of a utility asset, is particularly germane. Although the Supreme Court of Canada in that case commented that “the rate-setting process is a speculative procedure in which both the ratepayers and the shareholders jointly carry their share of risk related to the business of the utility (see MacAvoy and Sidak, at pp. 239-39)”, the issue before the Court (as well as that considered in the text referenced at para. 37, p. 9 of BCOAPO’s May 4 filing) related to the risk associated with utility assets. The Commission Panel does not consider that the ATCO decision goes so far as to “set a balance between shareholders and ratepayers in the allocation of the revenue requirement shortfall that the utility faces”, as suggested by BCOAPO (May 4, 2006 filing, para. 39, p. 10).
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In B.C. Electric, which was considered and applied in Hemlock Valley, Mr. Justice Martland of the Supreme Court of Canada discussed (at p. 856) what are now paragraphs 59(5)(a) and (b) and commented that:
“Clearly, as between these two matters there is no priority directed by the Act, but there is a duty imposed upon the Commission to have due regard to both of them. The rate to be imposed shall be neither excessive for this service nor insufficient to provide a fair return on the rate base. There must be a balancing of interests. In my view, however, if a public utility is providing an adequate and efficient service (as it is required to do by s. 5 of the Act), without incurring unnecessary, unreasonable or excessive costs in so doing, I cannot see how a schedule of rates, which, overall, yields less revenue than would be required to provide that rate of return on its rate base which the Commission has determined to be fair and reasonable, can be considered, overall, as being excessive. …”. (emphasis added)
The issue of the appropriate balancing of the interests of the utility on one hand and its customers on the other, was also addressed by the Court in Hemlock Valley (at p. 21) when it stated that:
“the proper balancing of interests which the Commission carried out was done and completed when it settled the rate base, fixed the rate of return and determined the costs of operation allowable for rate-making purposes.”
In Hemlock Valley, the Commission had attempted to balance the interests of the utility and its customers when it allowed a rate increase for the utility, but directed that it be phased in over three years to avoid or lessen “rate shock”. The Court overturned the Commission decision’s to phase in the rate increase (which did not compensate the utility for deferring recovery of its cost of capital), reasoning that to do so would preclude the utility from earning the rate of return found by the Commission to be the fair and reasonable return on equity.
BCOAPO, however, suggests that Hemlock Valley was not intended to apply to a utility in PNG’s unique situation and essentially submits that the allocation of the revenue shortfall to ratepayers would in this instance be unjust and unreasonable. BCOAPO suggests that Hemlock Valley and B.C. Electric apply to a “normal” utility, but they do not apply where ratepayers are being asked to cover a revenue requirement shortfall arising from a risk for which shareholders had previously been compensated, nor where there was substantial risk of a utility losing customers as a result of the proposed increase in rates (BCOAPO May 4, 2006 filing, paras. 29/30, p. 7).
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Commission Panel Analysis and Findings The Commission Panel acknowledges that Hemlock Valley did not deal with a situation involving the loss of a significant customer. Nor arguably does it apply until the point where the Commission has made a finding or determination on a utility’s cost of service. The Commission Panel notes that, relying upon B.C. Electric and the utility counsel’s submissions, the Court in HemlockValley commented (p. 21) that:
“The Utilities Commission Act empowers the Commission to determine what is a fair and reasonable rate of return upon the appraised value of the property of regulated utilities, but, having done so, requires the Commission to set rates so as to allow recovery of a rate which permits an opportunity to earn that return.” (emphasis added)
In this context, therefore, the Commission Panel considers Hemlock Valley to be most useful in terms of reaffirming the principles discussed in B.C. Electric.
In any event, the Commission Panel considers that it is in this instance bound by the requirements upon the Commission established by the Act and by the manner in which PNG is and has been regulated.
The Commission Panel agrees with BCOAPO that PNG is unique, particularly in view of its heavy reliance on a small number of industrial customers, and also agrees with PNG that the utility has higher business and financial risks than a low-risk benchmark utility.
However, although PNG is unique, it is and has been regulated by the Commission under the Act on a traditional cost of service basis. What this means is that this utility, which is a virtual monopoly provider of natural gas in its service area, is permitted under the Act to recover the reasonable and prudent costs of providing its services in exchange for the obligation to provide safe and reliable service. One of the regulator’s tasks, therefore, is to balance the need for the Utility to recover its reasonable and prudent costs with the need to ensure that ratepayers are charged fair and reasonable rates. Rates charged to customers are based on costs incurred by the utility to provide service. If the Commission finds certain costs to be imprudent or unreasonable, it will disallow such expenditures and reduce proposed rates accordingly.
The statutory obligation to approve rates which will afford a fair compensation for the services rendered and provide the utility with a fair and reasonable return was articulated by Mr. Justice Locke in B.C. Electric, (at pp. 846 and 848):
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“In my opinion the true meaning of the relevant sections of the Public Utilities Act is that a utility is given a statutory right to the approval of rates which will afford to it fair compensation of the services rendered and that the quantum of that compensation is to be the fair and reasonable rate of return upon the appraised value of the property of the company referred to in s. 16(1)(b) [ss. 59(5)(a) and (b) and 60(1)(b)(i). …
The obligation to approve rates which will provide the fair return to which the utility has been found entitled is, in my opinion, absolute, which does not mean that the obligation of the Commission to have due regard to the protection of the public, as required by s. 16(1)(b) [ss. 59(5)(a) and (b) and 60(1)(b)(i)], is not to be discharged. It is not a question of considering priorities between “the matters and things referred to in Clauses (a) and (b) of subsection (1) of s. 16 [now ss. 59(5)(a) and (b)]. The Commission is directed by s. 16(1)(a) [now s. 60(1)(a)] to consider all matters which it deems proper as affecting the rate but that consideration is to be given in the light of the fact that the obligation to approve rates which will give a fair and reasonable return is absolute.” [emphasis added]
The Commission Panel considers, therefore, that it is required, by virtue of sections 59 and 60 of the Act to allow the utility to recover its reasonable and prudent cost of service, to be determined on the basis of its 2006 RRA and the evidence adduced in this proceeding.
As noted by PNG, the revenue deficiency arising from the termination of the Methanex contract does not represent any specific costs of providing service. It is simply the extent to which PNG’s overall costs of providing service exceeds forecast margin recovery from PNG’s customers now that Methanex has terminated its contract. A revenue deficiency (or surplus) simply dictates whether an increase (or decrease) in rates is required. The Commission Panel, therefore, does not consider the revenue deficiency, in the context of cost of service regulation, to be a separate line item that, in and of itself, is capable of adjustment or reduction.
The Commission Panel, therefore, finds that to allocate any of the net revenue deficiency resulting from the termination of the Methanex contract to PNG’s shareholders, as advocated by BCOAPO and Mr. Childs, would result in rates that do not permit PNG to recover its costs of providing service and would, therefore, contravene sections 59 and 60 of the Act. The Commission Panel agrees with PNG that the allocations proposed by BCOAPO and Mr. Childs would simply be an arbitrary disallowance of PNG’s forecast costs, without any evidentiary or legal basis having been established for such a disallowance.
Given the statutory obligations imposed upon the Commission, there is simply no principled basis before the Commission Panel in this proceeding to allow it to appropriately deviate from the statutory requirement to allow the utility to recover its prudent and reasonable cost of providing service, and certainly there is no evidence to support an allocation or to select a specific allocation of the revenue deficiency, other than to the utility’s customers.
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The Commission Panel finds that PNG’s proposed method of allocating a revenue deficiency resulting from the loss of the Methanex contract to be appropriate.
More specifically, the Commission Panel also accepts PNG’s proposal, discussed at pages 44 and 45 of the Application (Exhibit B-1), to allocate the revenue deficiency based on customer class gross margin and to treat small industrial sales and transportation service customers as one customer class when allocating the revenue deficiency.
Other arguments raised by BCOAPO and Mr. Childs and concerns expressed by many other intervenors and interested persons relate to affordability of rates and PNG cost control.
The Commission Panel notes BCOAPO’s comment that for some time now PNG’s residential rates have been either barely competitive or uncompetitive with electricity rates and PNG’s response that the rate impact to other customers is “modest and manageable” when comparing the rates payable effective April 1, 2006 with the rates that were in effect December 31, 2005. The Commission Panel agrees with BCOAPO that PNG’s comparison is not particularly supportive of PNG’s position given the fluctuations in commodity prices during this period.
The Commission Panel, however, agrees with PNG that “affordability” is not a test under the Act or the relevant case law and that it is a vague, relative and potentially shifting concept. The Commission Panel notes the comments of Mr. Justice Rothstein of the Federal Court of Appeal in TransCanada Pipelines Ltd. v. Canada (National Energy Board), [2004] F.C.A. 149 (at para. 43):
“While I agree with the appellant that the impact on customers or consumers cannot be a factor in the determination of the cost of equity capital, any resulting increase or decrease in tolls may be a relevant factor for the Board to consider in determining the way in which a utility should recover its costs. It may be that an increase is so significant that it would lead to “rate shock” if implemented all at once and therefore should be phased in over time. It is quite proper for the Board to take such considerations into account, provided that there is, over a reasonable period of time, no economic loss to the utility in the process. In other words, the phased in tolls would have to compensate the utility for deferring recovery of its cost of capital. In the end, where a cost of service method is used, the utility must recover its costs over a reasonable period of time, regardless of any impact those costs may have on customers or consumers” (see Hemlock Valley Electrical Services Ltd. v. British Columbia Utilities Commission et al., [1992] 12 B.C.A.C. 1 at 20-21 (C.A.)) [emphasis added].
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Furthermore, the Commission Panel finds that there is no evidence before it in this proceeding which would allow it to determine that the rates proposed by PNG are not affordable or, conversely, to determine what a more appropriate “affordable” rate would be and how that could be achieved.
It is evident though that increases in the delivered cost of gas do impact PNG’s residential and commercial customers (PNG May 9, 2006 filing, para. 24, p. 7) and the Commission Panel accepts PNG’s submissions and assurance that the Utility has responded by taking all reasonable and prudent steps to reduce its costs as a result of the loss of margin from its industrial customers. PNG states that “customer impacts” are always considered when the cost of service is established in the sense that customers have an interest in ensuring that the utility’s costs are reasonable and not overstated and that such impacts are reflected in the cost of service that was considered during the NSP and was reflected in the proposed settlement document and now PNG’s July 7, 2006 Final Argument.
The Commission Panel notes the actions and efforts which PNG has taken to reduce its costs in the past when it faced a reduction in revenue from industrial customers and the steps taken to reduce its 2006 costs as outlined in its Application and at page 9 of its April 28, 2006 filing. The Commission Panel also notes PNG’s assertion that there are no material maintenance capital expenditures which could be eliminated without endangering PNG’s obligation to provide safe and reliable service to its customers. The Commission Panel accepts that PNG has taken all prudent steps to manage and reduce its costs and that there are no unnecessary or unreasonable costs in the 2006 cost of service.
It goes without saying that it is incumbent upon a regulated gas utility, and particularly so in this era of rising natural gas prices and the potential further loss of customers, to make best efforts to control and, where possible, reduce costs and the Commission Panel accepts that PNG has and will continue to do so.
The Commission Panel nevertheless remains concerned that PNG’s rates are becoming less competitive and is mindful of the concerns expressed by a considerable number of interested parties earlier in this proceeding, including comments concerning the precarious state of the economy of the northwest and the difficulties faced by industrial commercial and residential customers alike (including Robin Austin, MLA, April 6, 2006 Submission and Exhibits C11-3 and C11-4 (Petition); Terrace & District Chamber of Commerce, Exhibit C7-1; Mayor Talstra, City of Terrace, Exhibit C8-2; Kitimat Chamber of Commerce, Exhibit C13-1).
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The Commission Panel notes that PNG conducts detailed monthly reviews of its financial and operating results. PNG suggests, therefore, that it would be in a position to determine whether lower customer rates would improve cost recovery and prevent PNG’s recoverable margin from declining (PNG May 29, 2006 Response, Question 4, p. 7) and that PNG would, in such case, make an appropriate application to the Commission to reduce customer rates.
The Commission Panel therefore anticipates that PNG will continue to carefully monitor loss of load and decreases in volumes and margin and to be in a position to take steps as it considers appropriate and as discussed in its May 29, 2006 Response to Letter No. L-19-06, Question 4, and/or to report to the Commission on this subject in its next RRA.
II. Item 17: ROE and Capital Structure PNG requests that the Commission set PNG’s return on common equity using a 65 basis points risk premium above the low risk benchmark utility and a deemed common equity ratio of 40 percent. PNG’s allowed ROE is derived from the Commission’s Automatic Adjustment Mechanism which is used to calculate the ROE for a low-risk benchmark utility and a utility-specific risk premium for each utility. The Commission’s March 2, 2006 Decision related to the application by Terasen Gas Inc. and Terasen Gas (Vancouver Island) Inc. to determine the Appropriate Return on Equity and Capital Structure and to Review and Revise the Automatic Adjustment Mechanism revised the 2006 ROE for a low-risk benchmark utility to 8.80 percent. On March 9, PNG subsequently revised its Application to include a ROE of 9.45 percent to reflect the revision in the ROE for a low-risk benchmark utility (Exhibit B-13).
The Commission Panel notes that PNG’s risk premium was reduced by 10 basis points to 65 basis points in the Commission Decision dated July 29, 2004 regarding PNG’s 2004 RRA.
The Commission Panel in this proceeding has heard no persuasive evidence that PNG’s risk premium should be further reduced and certainly no evidence or submissions to suggest a specific appropriate reduction. Therefore the Commission Panel approves an ROE for PNG for 2006 of 9.45 percent based on a 40 percent equity component.
PNG’s proposal to issue $25 million of long-term debt and to lend $8 million to PNG (N.E.) is approved for 2006 ratemaking purposes. PNG’s requested long-term effective debt rate of 6.74 percent is approved for 2006 ratemaking purposes. PNG’s proposed 6 percent short-term debt rate on the positive short-term
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debt component of the capital structure for 2006 is approved. PNG is to record the difference between the 6 percent debt rate and the actual short-term interest and expenses in the short-term interest rate deferral account.
In its response to Letter No. L-19-06, BCOAPO stated that “the evidentiary record in this proceeding is not sufficient to allow the Commission to make an appropriate apportionment of the revenue deficiency between the remaining ratepayers and PNG’s shareholders. BCOAPO submitted that evidence with respect to the appropriate return on equity risk premium for PNG post-Methanex and on the methodology for determining an appropriate allocation of the revenue deficiency is now required. However, in its 2-page response dated June 16, 2006 to Commission Order No. G-66-06, BCOAPO did not, as had been requested, provide a detailed explanation of the nature and extent of any further evidence proposed and a justification for such evidence to assist the Commission Panel to understand what was required and how it would be helpful in the decision-making process.
Although the Commission Panel closed the evidentiary record for this proceeding, this does not preclude the appropriate ROE for PNG from being subject to further review. BCOAPO, Mr. Childs or any other party is entitled to raise this issue, and any other related issues, and to present appropriate and relevant evidence for the Commission’s consideration in the review associated with PNG’s next RRA.
As well, BCOAPO had raised, in the context of Item 1, the following question: “Is what PNG is requesting a fair return on the rate base, taking into account its history and present circumstances?” (May 4, 2006, para. 33, p. 8) because in BCOAPO’s view PNG has in the past obtained an approved ROE, which included a significant equity risk premium for which the potential loss related thereto has now largely occurred. In response, PNG took issue with what it termed BCOAPO’s assertion that allocating the revenue shortfall to other customers would effectively amount to an over-recovery of costs by PNG.
The Commission Panel notes PNG’s response that its higher risk premium, which is now 65 basis points above the equity risk premium for the low risk benchmark utility, represents approximately $340,000 of additional annual return to PNG’s shareholders and that the net margin loss from the termination of the Methanex contract in 2006 would be approximately $4.8 million (PNG May 9, 2006 filing, para. 12, p. 4).
The Commission Panel does not consider that allocation of a revenue deficiency resulting from the Methanex contract at this time and in these circumstances will result in an over-recovery for PNG.
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III. Other RR Items Neither BCOAPO nor Mr. Childs has taken issue with any of PNG’s other applied-for cost of service items as presented in the proposed settlement document or PNG’s July 7, 2006 Final Argument.
1. Load Forecast (Gas Deliveries and Margin Forecasts) The load forecasts appear reasonable and the Commission Panel accepts them as filed and updated by PNG.
2. Rate Redesign PNG is proposing to redesign the rate structure for Commercial Interruptible (RS 4), Small Industrial Sales (RS 5), and Seasonal Off-Peak (RS 6) customers by eliminating a monthly charge based on minimum consumption volumes in favour of a basic monthly charge unrelated to volume for the RS 5 and RS 6 customers.
For RS 5 Small Industrial customers, PNG is proposing a monthly fixed charge of $410. For RS 6 Seasonal Off-Peak Customers it is proposing a monthly fixed charge of $125, to apply only in the off-peak months of March to November. A delivery charge equal to twice the large commercial firm sales delivery charge will apply to any deliveries to the RS 6 customers during the peak winter months of December to February.
PNG is proposing no basic monthly charge for interruptible customers (that is a basic monthly charge of zero), arguing (primarily) that fixed pipeline assets are built to serve firm customers. Moreover, there would be no minimum monthly charge for interruptible customers.
The impact of the proposed change will be quite beneficial to small volume customers (decreases of 1.2% for RS 4 customers and of 12% and 14% respectively for RS 5 and RS 6). The change will be detrimental but less noticeably so for medium and large volume customers in each class, increasing the bills by 0.1% to 2.4% depending on the class (Exhibit B-4, Response to BCUC IR 1 8.1 and Exhibit B-11, Response to BCUC IR 2 33.1 to 33.4).
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The Commission notes that there were no submissions about this issue following the proposed Negotiated Settlement, which adopted monthly fixed charges as follows:
RS 4 Commercial Interruptible - $125 per month RS 5 Small Industrial Firm - $410 per month RS 6 Seasonal Off-Peak - $125 per month during off-peak. The Commission Panel accepts PNG’s proposal to eliminate the monthly charge based on minimum consumption volumes in favour of a basic monthly charge effective January 1, 2006. The Commission Panel directs PNG to include a monthly charge of $125 for the RS 4 Commercial Interruptible customers effective January 1, 2006.
Extend Seasonal Off-Peak Period to include November and March PNG is also proposing to extend the seasonal off-peak period to include November and March (Exhibit B-1, p. 52). PNG confirmed that if the system peak day occurred in the months of November or March it would be able to meet its firm load. PNG also confirmed that, if the change is approved, the revised tariff will contain a condition allowing them to curtail seasonal customers in November and March if necessary to meet firm customer demand (Exhibit B-11, Responses to BCUC IR 2 35.2 to 35.4).
The Commission Panel finds the change proposed by PNG to be reasonable and to be one which poses no threat to the supply reliability for firm customers. The Commission Panel accepts PNG’s proposal to extend the seasonal off-peak period, subject to PNG’s commitment to include a tariff provision allowing curtailment of seasonal off-peak customers in November and March effective January 1, 2006.
3. Rate Base The Commission Panel approves the deactivation of compressor stations R2 and R4, a 10 inch loop (52.8 miles in length), a 6 inch lateral to Kitimat (32.97 miles in length) and a Methanex meter and regulating station.
The Commission Panel approves PNG’s request to transfer the net book value of $5.05 million of the facilities which it will deactivate from plant in service to a non-rate base interest bearing deferral account and to amortize that account on a monthly basis over 10 years commencing January, 2006. The Commission approves the
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accounting treatment of the deactivated facilities as proposed by PNG (Exhibit B-1, Tab Application, pp. 6-7). PNG’s foregone return proposal is not accepted at this time, however, PNG may apply for Commission approval to record the foregone return should the deactivated facilities be reactivated and the merits of that application will be considered at that time.
The Commission Panel approves PNG’s 2006 forecast capital additions as set out in the February 17, 2006 Update (Exhibit B-10). PNG is to file a report with the Commission by 2006 year-end detailing the activities taken in respect of the Arden Valley Rehabilitation project and all associated costs incurred with this project.
4. Deferral Accounts Subject to the adjustments required in these Reasons for Decision, the Commission Panel approves the applied-for Deferral Accounts.
5. Recapitalization Application Hearing Costs The Commission Panel notes that in the July 29, 2004 Decision related to PNG’s 2004 RRA, the Commission was of the view that the costs associated with the regulatory review of the associated January 30, 2004 Recapitalization Application should be shared between the ratepayers and the shareholders and allowed PNG to recover Commission and Intervenor Recapitalization Application costs billed to the Utility by the Commission. However, in its Decision dated September 9, 2005, the Commission noted, at p. 48, that one of the approvals sought by PNG, in paragraph 1 of its subsequent Recapitalization Application dated December 17, 2004, was subject to the condition “that no costs associated with this [recapitalization application] and no transactions costs, including amalgamation and securities issuance and redemption costs, related to the foregoing transactions shall be recovered through customer rates” (“PNG’s proposed condition”). In this proceeding, PNG was asked to confirm that PNG’s 2006 revenue requirements and the proposed rates do not contain any costs related to the Recapitalization Application and, if not, to explain why not (BCUC IR No. 1.25.3, p. 53). In response, PNG indicated that it had “recorded all of the 2005 income trust application hearing costs in the BCUC proceedings deferral account pending obtaining all of the approvals required for the conversion to proceed” and that “PNG’s share of the 2005 [recapitalization application] hearing costs will remain in that account until all of the approvals are obtained to enable PNG to commence the conversion process”.
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The Commission Panel notes that during the course of this proceeding PNG indicated that it was evaluating the efficiency of raising capital under an income trust structure for a proposed “KSL Project” and confirmed that it could give no assurances that the recapitalization under an income trust ownership structure will occur (PNG April 24, 2005 filing, Q. 4.2 and 4.3, pp. 5-6).
In the circumstances, the Commission Panel does not consider that it is bound, beyond the July 29, 2004 Decision related to PNG’s 2004 RRA, to allow PNG to recover or share these costs between the ratepayers and shareholders as set out in that Decision. Rather, based on PNG’s subsequent proposed condition as noted and as approved in the September 9, 2005 Decision and, given the status of the approved recapitalization under an income trust structure and the circumstances related thereto, the Commission Panel considers that the costs associated with the subsequent Recapitalization Application should perhaps more properly be to the sole account of the shareholders as reflected in PNG’s proposed condition. The Commission Panel denies PNG’s request to amortize the customers’ $169,855 after tax share of the second Recapitalization Application hearing costs at 20 percent per year commencing in 2006. For greater certainty, this amount may remain in the deferral account, subject to review of the appropriate recovery of these costs in the next RRA.
6. Cost of Service The Commission Panel finds that PNG’s 2006 operating, maintenance, general and administrative expenses, and other cost of service items to be prudent and reasonable and appropriate to ensure the safe and efficient operation of its system. The Commission Panel approves for 2006 PNG’s requested transfer to capital rate of 19.3 percent.
The Commission Panel approves the cost pools subject to allocation by PNG to PNG (N.E.) as set out in the Application. The Commission Panel accepts that PNG’s allocation of Account 728 costs to PNG (N.E.) is appropriate and that relative rate base is the appropriate allocator.
PNG’s request to revise the interim company use gas cost rate of $0.305/GJ to a permanent rate of $0.185/GJ is approved, effective January 1, 2006.
7. Customer Rates The Commission Panel approves PNG’s 2006 revenue requirement as set out in PNG’s July 7, 2006 Argument, pages 18-23, subject to the required adjustment for amortization of Recapitalization Application hearing costs. PNG’s proposal to amortize the Methanex termination payment of $23.3 million over the 44-month period from
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March 2006 to October 2009 is approved which results in a credit of approximately $5.6 million from the Methanex contract termination payment to the 2006 cost of service. PNG’s request to make the permanent RSAM rate rider $0.301/GJ effective January 1, 2006 (Exhibit B-10, p. 7) is approved.
IV. Conclusion PNG is to file regulatory schedules and an amended summary of Rates and Bill Comparison Schedules based on PNG’s Application, as revised, and the adjustments contained in these Reasons.
The Commission will accept, subject to timely filing, amended Gas Tariff Rate Schedules in accordance with these Reasons.
PNG is to comply with all directions contained in these Reasons.