IN THE MATTER OF
the Utilities Commission Act, R.S.B.C. 1996, Chapter 473
and
An Application by Terasen Gas Inc. -
Fort Nelson Service Area
for Approval to Amend its Schedule of Rates
BEFORE: D.A. Cote, Commissioner
C. Brown, Commissioner February 24, 2011
D. Morton, Commissioner
N.E. MacMurchy, Commissioner
O R D E R
WHEREAS:
A. On September 8, 2010, Terasen Gas Inc.-Fort Nelson Service Area (TG Fort Nelson) submitted its 2011 Revenue Requirements Application to the British Columbia Utilities Commission (Commission) seeking approval to recover a revenue deficiency of $295 thousand through a permanent increase in its delivery rates, and to decrease the RSAM rate rider, effective January 1, 2011, from $0.037/GJ by $0.004/GJ for a total rate rider of $0.033/GJ effective January 1, 2011;
B. On September 30, 2010, the Commission issued Order G-149-10 establishing a Written Public Hearing Process and a Regulatory Timetable for review of the Application;
C. On November 15, 2010, by Letter L-92-10, the Commission issued an amended Regulatory Timetable to include an Evidentiary Update;
D. On November 19, 2010, TG Fort Nelson filed with the Commission an Evidentiary Update and, based on the Evidentiary Update requested approval of interim rates to recover a revenue deficiency of $315,000;
E. On November 25, 2010, the Commission approved interim rates and the creation of the revenue requirement application deferral account by Order G-173-10;
F. On December 1, 2010, by letter, TGI requested amendments to the Regulatory Timetable; on December 3, 2010, by Letter L-98-10, the Commission approved the requested changes to the Regulatory Timetable;
G. The Commission has reviewed the Application, as amended by the Evidentiary Update and concludes that the requested changes as outlined in the Application should be approved as being the public interest.
NOW THEREFORE pursuant to section 44.2, 58, 60 and 61 of the Utilities Commission Act, the Commission orders as follows:
1. The Commission approves TG Fort Nelson to recover a revenue deficiency of $315,000 through a permanent increase in its delivery rates, effective January 1, 2011, resulting in a margin increase of 21.74 per cent, a decrease in the RSAM rate rider from $0.037/GJ to $0.033/GJ, and revised rates as set out in the Evidentiary Update, Table 3.
2. Continuation of existing deferral accounts and of the Revenue Requirement Application rate base deferral account for 2011 RRA Costs as described in Section 7.6 of the Application and previously approved by Commission Order G-173-10.
3. Adoption of Accounting and Other Policy Changes consistent with the TGI 2010-2011 Negotiated Settlement Agreement as set out in Section 7 and 9 of the Application.
4. Approval of the proposed 2011 capital expenditures including $3,015,650 of capital costs (excluding AFUDC) related to the Muskwa River Crossing Project (Project) as requested by TG Fort Nelson in the Evidentiary Update subject to conditions described in the Reasons for Decisions accompanying this Order. Further, the Commission approves the inclusion of Project costs, as presented in the Evidentiary update, in 2011 ratebase. All Project costs may be subject to prudency review by the Commission upon completion of the Project. However, the total amortization/depreciation projected in this Application shall be recorded as a reduction to the carrying amount of the Project Assets in 2012. The Project assets shall not attract AFUDC after the projected in-service date included in this Application.
5. TGI is to notify its customers in the Fort Nelson Service Area about the delivery rate and rate rider changes by a bill message to be reviewed in advance by Commission Staff to confirm compliance with this Order.
6. TGI is to file amended Gas Tariff Rate Schedules for the Fort Nelson Service Area in accordance with this Order in a timely manner.
7. TGI will comply with all other directives in the Reasons for Decision accompanying this Order.
DATED at the City of Vancouver, in the Province of British Columbia, this 25th day of February, 2011.
BY ORDER
Original signed by:
D.A. Cote
Commissioner
Attachment
In The Matter Of
An Application by Terasen Gas Inc. - Fort Nelson Service Area
2011 Revenue Requirements Application for Changes
to the Revenue Stabilization Adjustment Mechanism Rate Rider
and Delivery Rates effective January 1, 2011
REASONS FOR DECISION
February 24, 2011
Before:
D.A. Cote, Commissioner
D. Morton, Commissioner
C. Brown, Commissioner
N.E. MacMurchy, Commissioner
TABLE OF CONTENTS
Page No.
1.3 The Written Hearing Process
3.3 Operating & Maintenance Expenses
3.6.1 Plant in Service and Capital Additions
3.6.5 Financial and Capital Structure
1.0 INTRODUCTION
1.1 Background
Terasen Gas Inc. - Fort Nelson Service Area (TGFN or Utility) is part of Terasen Gas Inc. (Terasen or TGI) which is the largest natural gas distribution utility in British Columbia. Terasen provides sales and transportation services to more than 765,000 residential, commercial and industrial customers in over 100 communities throughout the Province. Terasen’s distribution network delivers gas to approximately 90 percent of the natural gas customers in British Columbia.
TGFN’s service area consists of the Fort Nelson and Prophet River areas of north-eastern BC where TGFN provides sales and transportation service to approximately 2,100 customers. TGFN was acquired in 1985 as Fort Nelson Gas Ltd. by Inland Natural Gas Ltd., a predecessor company now part of Terasen. Fort Nelson Gas Ltd. was amalgamated in 1989 with Inland Natural Gas Ltd., Columbia Natural Gas Ltd. and the Lower Mainland Gas Division of British Columbia Hydro and Power Authority to form BC Gas Inc. (later BC Gas Utility Ltd.) and ceased to be a separate legal entity at that time.
Rates have been set separately for TGFN from the date of acquisition to the present. Terasen (as BC Gas) sought regulatory consolidation of TGFN with the remainder of Terasen in its 1992 Revenue Requirement Application but this was denied by the British Columbia Utilities Commission (BCUC or Commission) in its Decision dated August 5, 1992. Since then, TGFN has been excluded from Terasen’s general revenue requirement applications and Performance Based Ratemaking plans. The most recent revenue requirement change approved by the Commission was on November 20, 2008 by Order G-172-08. In that Order, the Commission approved an increase in rates for TGFN effective January 1, 2009 to recover a revenue deficiency of $372 thousand primarily due to a decline in industrial demand and use rates per customer.
In addition, on December 3, 2009 by Order G‐147‐09, the Commission approved the creation of two new deferral accounts along with the continuation of existing deferral accounts, changes to the Revenue Stabilization Adjustment Mechanism RSAM rate rider, and continuation in 2010 of the approved 2009 rates effective January 1, 2010. These requests were driven primarily by changes to TGI’s return on equity and capital structure, and the proposed adoption by Terasen Gas Inc. of updated depreciation expenses and overheads capitalized rate. This Order made no change to rates set in 2010.
1.2 The Application
Original Application
On September 6, 2010, TGFN submitted to the Commission an application for revenue requirements for the 2011 test period (Application). This Application sought to recover from ratepayers $295,000 in revenue deficiencies in 2011 (Application, Section 2.2, p. 7).
In the Application, TGFN estimates that approximately 40 percent of revenue deficiencies in 2011 result from changes in return on equity and equity ratios as approved by the Commission in Order G-78-09, approximately 25 percent results from changes in depreciation rates consistent to those changes made by TGI as approved by Commission Order G-141-09 and the remainder are a result of rate base growth primarily related to the replacement of the existing transmission pipeline underwater crossing of the Muskwa River (Application, Section 1.2, p. 1).
In the Application, TGFN seeks approval to create the 2011 RRA Costs Deferral Account, a rate base deferral account, for the purposes of deferring costs related to the regulatory application for future recovery. TGFN indicates that this treatment is consistent with other Terasen entities (Application, Section 7.6.5, p. 43).
Finally, TGFN seeks Commission approval to include in ratebase costs to replace the Muskwa River Pipeline crossing (the Muskwa Project). TGFN indicates that a study of the current Muskwa underwater pipeline crossing (installed in 1974) revealed that a portion of this transmission pipeline was exposed and subject to potential damage. In the Application, TGFN describes its consideration of a number of alternatives and indicates that TGFN’s preferred alternative is to install a new river crossing by means of horizontal directional drilling from the top of the river bank on either side of the river (HDD Peak to Peak Option). This alternative is projected to cost $2.45 million based on the upper bound of preliminary Class 4 cost estimates. At the time the Application was filed, there were a number of uncertainties regarding the seven alternatives considered by TGFN including but not limited to costs.
TGFN indicates that it would file an evidentiary update following completion of site surveys, geotechnical evaluations and other related alternative evaluation studies (Application, Section 1.2, p. 2).
Evidentiary Update
Originally, TGFN indicated intent to file an evidentiary update in November which would provide further details on the Muskwa Project alternatives and cost estimate. On November 12, 2010, TGFN filed a request to extend the regulatory schedule to allow for information requests, if needed on the evidentiary update to be filed with the Commission. The Commission approved this request and amended the Regulatory Timetable by way of Letter L-92-10.
On November 19, 2010, TGI filed the evidentiary update (Evidentiary Update) with the results of the evaluation of alternatives and updated cost estimates to complete the Muskwa Project. In the Evidentiary Update, TGFN indicates that preliminary estimates of cost made in the Application were no longer accurate due to new information on geotechnical conditions and that the HDD Peak to Peak Option would cost substantially more at approximately $4.087 million. As a result, TGFN undertook further investigative work and concludes that the alternative of attaching an intermediate pressure pipeline to the Muskwa River highway crossing (IP Bridge Option) is now the preferred alternative. However, this alternative requires approval from third parties to proceed. TGFN forecasts the in-service date to be October 1, 2011. Taking into account project development costs, and site remediation and completion costs, TGFN estimates cost for the IP Bridge Option of $3.015 million, before AFUDC, and the revenue deficiency for the test period is now forecast to be $315,000, $20,000 greater than the deficiency noted in the original Application (Evidentiary Update, p. 4).
Interim Rates
As the new information presented in the evidentiary update required review and deliberation into 2011, TGFN requested that Commission approve interim rates allowing for the recovery of the forecasted revenue deficiency in 2011 and to approve the 2011 RRA deferral account mechanism requested in the Application (Evidentiary Update, p. 5). This request was approved on November 26, 2010 by Commission Order G-173-10.
1.3 The Written Hearing Process
On September 30, 2010, the Commission issued Order G-149-10 establishing a Written Public Hearing Process and a Regulatory Timetable for review of the Application. The latter allowed for Information Requests and Responses, Written Submissions from Interveners and Final Argument from TGFN. British Columbia Old Age Pensioners’ Organization (BCOAPO) registered as an intervener to the Application and issued Intervener Information Requests on the Application on October 21, 2010. On November 12, 2010, TGFN responded to first information requests from both the Commission and BCOAPO and TGFN also requested that the regulatory timetable be amended to allow for further time to prepare the Evidentiary Update. On November 15, 2010, the Commission issued L-92-10 amending the regulatory timetable as requested by the Utility.
On November 19, 2010, TGFN submitted the evidentiary update and the Commission and BCOAPO issued their second round of Information Requests on November 26, 2010. By letter dated December 1, 2010, TGFN requested that the Commission amend the regulatory timetable by extending submission deadlines. The Commission extended the regulatory timetable on December 3, 2010 in letter L-98-10.
On December 16, 2010, TGFN submitted its final submission (TGFN Submission). On January 5, 2011, BCOAPO submitted its final submission (BCOAPO Submission). In that document, BCOAPO confined its submission to the issue of most concern to BCOAPO, the Muskwa Project. However, the BCOAPO noted in their Submission that its silence on any issues is not an indication that BCOAPO wholeheartedly supports TGFN’s proposals without reservation, but only that they are prepared to accept the end result if those concerns are adequately addressed in the Commission's determinations (BCOAPO Submission, p. 1). On January 12, 2010, TGFN submitted its reply submission (TGFN Reply).
In keeping with this, the Commission will consider the issue of the Revenue Requirements Application and the issue of the Muskwa Project as two separate components.
2.0 MUSKWA PROJECT
In the Application, as amended by the evidentiary update, TGFN is requesting acceptance of the Muskwa Project pursuant to section 44.2 of the Utilities Commission Act (Act), based on its revised cost estimate of $3.016 million (TGFN Final Submission, p. 5). TGFN submits that the project meets the requirements of section 44.2(5) of the Act which specifies certain factors that the Commission must consider when considering whether to accept an expenditure schedule (TGFN Final Submission, p. 9). TGFN intends to complete the Muskwa Project before the end of 2011, and also seeks permission for inclusion of project costs into ratebase effective October, 2011 which is the expected date this Project will go into service (TGFN Final Submission, p. 9).
Project Need
The Utility submits that the town of Fort Nelson receives natural gas by way of a single transmission pipeline that crosses the Muskwa River and this pipeline river crossing was installed in-stream using an open-cut method in 1974. TGFN indicates that surveys in 2008 and 2010 show that approximately 12 metres of pipeline has become exposed and is now at risk of damage from river action. Due to river hydrology, TGFN expects that the section of exposed and unsupported pipe will continue to expand over time further adding to the risk to the Pipeline and eventually the exposed pipe will reach an unsupportable length and the pipe will yield with possible rupture. As the pipeline crossing is integral to the delivery of natural gas supply to TGFN customers, a pipeline loss would completely disable TGFN’s ability to supply natural gas to its customers. As a result, it is TGFN’s position that the project risk is high and a “do nothing” option is unacceptable (TGFN Final Submission, p. 5).
Project Evaluation
TGFN indicates that in evaluating the project, the Utility has considered eight alternatives to remediate or replace the Muskwa Crossing including two horizontal directional drilling (HDD) options, four in-stream options (Open Cut Crossing, Live Line Lowering, Concrete Mats and Rip Rap Placement), attaching the pipeline to the existing Alaska Highway bridge (IP Bridge Option) and constructing a new aerial crossing (Aerial Pipeline Option). Various risk factors were considered. TGFN indicates that it first evaluates alternatives using Class 4 cost estimates and then develops a Class 3 cost estimate for the preferred alternative consistent with the Commission’s Certificate of Public Convenience and Necessity Guidelines (TGFN Final Submission, p. 5).
Evaluation Results and Cost Estimates
In the Application, TGFN initially indicated a preference for the HDD Peak-to-Peak alternative, due its relatively low Class 4 cost estimate and non-financial reasons. TGFN estimated that the cost for this alternative would be approximately $2.45 million (Application, Section 7.3.2.12, pp. 38, 40). Based on the results of that evaluation, TGFN submits that it completed a Class 3 cost estimate for the preferred HDD Peak-to-Peak alternative and the results of that exercise were submitted to the Commission as the Evidentiary Update. In preparing the Class 3 cost estimate, TGFN indicates that further site investigations were conducted. This exercise detected unexpected surficial gravels to significant depths resulting in increased project costs due to the need for greater lengths of wash-over casing to conduct the drilling. TGFN indicates that the resulting new information indicated the HDD Peak to Peak alternative would cost significantly more than the Class 4 cost estimate, with a Class 3 cost estimate of approximately $4.087 million. TGFN also notes that there are significant risks associated with this option and it is estimated to have only a 50% chance of success (TGFN Final Submission, p. 6).
Due to this information, TGFN indicates that the HDD Peak to Peak Option is no longer the preferred alternative and the HDD options were effectively ruled out. TGFN then selected the IP Bridge Option as its new preferred alternative and undertook to complete a Class 3 cost estimate which was also included in the Evidentiary Update. TGFN’s Class 3 cost estimate of the IP Bridge Option is $3,015,650. TGFN submits that the IP Bridge Option is preferable over all four of the in-stream alternatives due to high environmental risk and potential for higher costs. TGFN also indicates that the Aerial Pipeline Option is the least preferable option from a non-financial perspective and would also result in high installation and maintenance costs (TGFN Final Submission, pp. 6-7).
BCOAPO agrees with TGFN that the HDD Peak-to-Peak appears to be too risky to pursue at this time both on a cost and a technical basis. BCOAPO also notes the lack of quantitative estimates of the environmental risks associated with the generally lower cost in-stream alternatives but, at the same time, BCOAPO submits that it is not certain that any meaningful statistical estimates are possible (BCOAPO Final Submission, pp. 4-5).
Risk of IP Bridge Option
TGFN has identified two significant risks that could impact planned project completion for the IP Bridge Option. The first indentified risk to the IP Bridge Crossing is the necessity to obtain a permit from Public Works and Government Services Canada (PWGSC) to hang the pipe on the underside of the Alaska Highway Bridge over the Muskwa River. TGFN notes that TGI have successfully installed gas lines on dozens of bridges owned by the BC Ministry of Transportation (MOTI) and other bridges in BC, and that it is possible in most bridge applications to engineer a safe and economical gas pipeline installation that meets Canadian Highway Bridge Design Guidelines. TGFN submits that it will continue to communicate with PWGSC and will provide an information package that meets MOTI requirements and that includes a description of the bridges that have gas lines installed on them. TGFN will make a formal application to install a new crossing on the bridge in early 2011 with a request for approval by January 28, 2011 (TGFN Final Submission, p. 8).
A second risk of the IP Bridge Option identified by TGFN is that a delay in receiving a permit could pose a risk to the project schedule. However, the engineering firm which provided TGFN with the Class 3 cost estimate for the IP Bridge Option estimated the likelihood of completing the IP Bridge in by the end of the 2011 fiscal year is 80 percent with a P50 confidence interval (TGFN Final Submission, p. 8).
In its submission, BCOAPO notes that there is permit uncertainty associated with the IP Bridge Crossing and is concerned, given that TGFN has stated the existing pipe may fail at any time. But BCOAPO questions how critical the replacement is noting that the failure to secure the permit by January 28, 2011 appears to mean that TGFN's customers may be exposed to possible pipe failure in 2011. BCOAPO submits it would prefer that TGFN get more and higher quality cost, technical, and environmental information in order to determine the optimal course. However the result of such an undertaking may be further costs and risky delays that may well not be in its ratepayers' interests (BCOAPO Final Submission, pp. 4-5).
TGFN acknowledges that the primary risk related to the IP Bridge Option is obtaining a permit from PWGSC to proceed. However, TGFN notes that it is addressing that risk and submits that the Commission should accept the Muskwa Project as being in the public interest and include the estimated cost of $3,015,650 for the IP Bridge Option in the rate base for the purpose of F2011 rates as the process of analysing and selecting the Project was appropriate and followed Commission guidelines and since TGFN is working towards obtaining the required permit (TGFN Reply Submission, p. 1-2).
Regulatory Process if IP Bridge Option is Unachievable
In response to information requests, TGFN has proposed a regulatory process in the event that the IP Bridge Option is not achievable. TGFN has indicated a willingness to advise the Commission if the Utility fails to obtain the necessary permit to proceed with the IP Bridge. If that event occurs, TGFN proposes to reconsider all of the remaining crossing options and investigate any of the remaining options more closely to determine feasibility and preference. When TGFN determines a new recommendation based on the then available information, that recommendation along with the supporting documentation will be provided to the Commission for review and approval on an expedited basis (Exhibit B-7, BCUC IR 2.1.4, TGFN Reply Submission, p. 2).
BCOAPO submits it is prepared to accept such a regulatory process based on the implicit suggestion by BCUC Staff as given in BCUC IR 2.1.4 which indicates as follows:
“Would TGIFN accept a Commission decision that approved for inclusion into rate base, based on TGI's accepted practices, the Muskwa River IP Bridge Crossing up to an amount of $3,000,000 and if the IP Bridge Crossing is not achievable, would TGIFN accept an additional regulatory process if the Commission believes the process is warranted?”
BCOAPO submit that such a process would be a sensible way to address the lingering uncertainties associated with this matter (BCOAPO Final Submission, pp. 4-5).
The Commission accepts the Muskwa Project using the IP Bridge Option alternative as being in the public interest as TGFN has presented sufficient evidence to justify project need, cost and alternative selection. The Commission accepts that the IP Bridge Option is a more desirable alternative than the HDD options due to the high risk of project failure, the in-stream alternatives which pose potential cost and environmental risk and an Aerial Pipeline Option which is undesirable due to high installation and high maintenance costs. The Commission also accepts TGFN’s estimated IP Bridge Option project cost of $3,015,650.
If TGFN determines that the IP Bridge Option alternative is no longer the desired alternative due to permitting or other matters or if the cost estimate of the IP Bridge Option exceeds the estimated costs included in the Evidentiary Update, TGFN is directed to advise the Commission, reconsider and investigate all of the remaining crossing options more closely with regard to cost, feasibility, risk assessment and appropriateness. TGFN will then provide a recommendation for the Muskwa Project along with the supporting documentation to the Commission for review and approval on an expedited basis. Further, if TGFN’s best internal estimate of cost for the IP Bridge Option is expected to exceed $3,015,650, TGFN is to report such findings to the Commission within 30 days of such knowledge.
The Commission also approves, for inclusion in rate base in 2011, forecasted costs of the IP Bridge Crossing of $3,015,650 as presented in the Evidentiary Update. However, all Muskwa Project costs may be subject to prudency review by the Commission upon completion of the Project. However, as the Muskwa Project may not be in service by the forecasted completion date included in the Application, TGFN is directed to record the full amount of the 2011 forecasted amortization on the Muskwa Project such that income and rate base are reduced by the forecasted amortization for regulatory purposes. This treatment should prevent the Utility from recovering more that the Muskwa Project’s total cost from ratepayers. Further, the Muskwa Project assets shall not attract AFUDC after the projected in-service date included in this Application to ensure that ratepayers are not charged AFUDC on assets which are forecast to be in use.
3.0 REVENUE REQUIREMENTS
In the Original Application made to the Commission, TGFN projected a revenue deficiency of $295,000 (Application, Section 2.2, p. 7). In the Evidentiary Update, TGFN revised the estimated revenue deficiency based on revised project estimates of the Muskwa Project. Based on this update, the revised projected revenue deficiency for 2011 is $315,000. As a result of this deficiency, TGFN is requesting approval to increase customer rates for all customer classes. The resulting residential rate sought of approximately $2.85 per gigajoule is well below TGI’s 2011 rates for the Lower Mainland which is approximately $4.70 per gigajoule (TGFN Final Submission, p. 2).
TGFN proposes to recover the revenue deficiency evenly from all customers based on the margin at the existing rates and the total deficiency using the same methodology employed since the early 1990s. Also, the Commission has approved a Rate Stabilization Adjustment Mechanism (RSAM) for TGFN, which, similar to the RSAM for other TGI service areas, captures the difference in use per customer due to factors such as colder or warmer temperatures. However, unlike other TGI service areas, the RSAM also captures industrial customers served under Rate Schedule 25 and TGI believes that this methodology remains appropriate due to the particular, undiversified industrial loads in TGFN. TGFN proposes that the RSAM rate rider, calculated as $0.033 per gigajoule which is a decrease of $0.004 per gigajoule from the 2010 rider, should be approved as filed (Application, Section 2.3, p. 12).
Subject to other Commission determinations included elsewhere in this Decision, the Commission accepts TGFN’s revised estimated revenue deficiency of $315,000 for 2011 and approves TGFN’s recovery of this amount from its customers effective January 1, 2011 as described in the Application. Further, the Commission approves TGFN’s proposed RSAM rate rider of $0.033 effective January 1, 2011.
3.1 Load Forecast
TGFN is forecasting relatively little change in Terajoule(s) (TJ) usage by customers in the residential, commercial or industrial classes. Total TJ demand forecast for TGFN in 2011 is 598 TJ as compared to expected usage in 2010 of 603 TJ. Residential usage is expected to drop by 2 TJ, commercial usage is expected to drop by 1 TJ and Industrial usage is expected to drop by 2 TJ. Overall, slightly declining customer usage rates are expected to be offset with the additional of a small number of new customers. These forecasted changes are consistent with experienced results in the past two years (Application, Section 3.6, pp. 16-17).
TGFN forecasts the addition of 12 new residential customers in 2011, similar to customer additions in the past two years. Similar results are forecast for commercial customer growth of 2 customers. Factors affecting customer growth include a modest growth in the oil and gas industry which continues to sustain the local population growth slightly offset by weaker market conditions of the local forestry industry (Application, Section 3.4, pp. 14-15). Gas usage by residential and class 2.1 customers is forecast to continue to decline at a very modest level, similar to trends experienced by TGFN since 2009 as well as those seen elsewhere in the Province. TGFN forecasts class 2.2 customer usages amounts to hold steady with the 2010 usage amounts (Application, Section 3.5, pp. 15-16).
TGFN forecasts no change in the number of industrial customers, which is currently made up of a single customer, Canfor. Industrial customer usage rates are estimated to remain relatively consistent, showing only a modest decline of 2 TJ as Canfor continues to maintain its heating load in two non-operational facilities (Application, Section 3.6, pp. 15-17).
The Commission has reviewed the determination of load forecasts and is satisfied that the methodology used and the forecasted outcomes are reasonable based on experienced load trends, locally and provincially, as well as the current economic status of the community of Fort Nelson. Therefore, the Commission accepts the forecasts submitted by TGFN. The Commission also notes that the impact of an error in the forecasts will be mitigated by the RSAM account.
3.2 Cost of Gas
The current gas cost recovery charge effective January 1, 2011 is $5.015 per gigajoule as approved by Order G-190-10 on December 9, 2010 (TGFN Submission, p. 2). As the cost of gas is a flow through item, TGFN is not requesting approval of forecast gas costs in the Application, however, forecast gas costs, including unaccounted for gas (UAF) estimates, are required in the determination of the Gas Cost Reconciliation Account (GCRA) forecasts (Application, Section 4, p. 19).
Consistent with established Commission practice, TGFN plans to continue to review and report on the gas costs and the gas cost recovery rates for TGFN on a quarterly basis and make application to the Commission for any rate changes to recover the cost of gas. TGFN indicates that British Columbia Utilities Commission – Guidelines for Setting Gas Recovery Rates and Managing the Gas Cost Reconciliation Account Balance, issued as Appendix I to Commission Letter L-5-01, dated February 5, 2001, outlines the quarterly reporting process utilized by TGFN (Application, Section 4, p. 19).
The Commission accepts TGFN’s Cost of Gas methodology as it is consistent with Commission Guidelines and historical practice of the Utility.
3.3 Operating & Maintenance Expenses
TGFN expects to experience relatively steady levels of Operating & Maintenance (O&M), with increases at or below the level of inflation. TGFN forecasts gross O&M expenses of $812,000 in 2011 as compared to $806,000 in 2010 representing an increase of $6,000 or less than 1 percent (Application, Section 5.0, pp. 23-25).
Similar to past years, TGFN operations have benefited by being able to draw upon the company-wide resources and expertise of Terasen in areas such as gas supply, transmission and distribution functions, customer billing and customer care, marketing, information technology, municipal, community and aboriginal relations, legal, risk management, environment, health and safety, regulatory, human resources, and finance/accounting. The cost of these services is allocated to TGFN based on the number of customers, consistent with a 2008 Commission Order G-27-08 (Application, Section 5.2, p. 20).
Also, TGFN is requesting to treat Training and Feasibility Study Costs as O&M expense rather than as Capital items (Application, Section 10.1, p. 82).
Based on expected expenditures, TGFN forecasts that gross O&M costs per customer will remain steady at an amount of $341 per customer (Application, Table 5-2, p. 23).
The Commission accepts TGFN’s forecast 2011 gross O&M expenses of $812,000 as the calculation methodology and forecasted results are consistent with historical results of TGFN. Further, the Commission approves TGFN’s the request to treat training and feasibility study costs as O&M expenses as this methodology is used by TGI and is consistent with current accounting standards.
3.4 Overheads Capitalized
TGFN seeks approval to change the capitalized overhead rate from 16 percent to 14 percent effective for 2010, which is consistent with the rate approved for TGI by Commission Order G-141-09 (Application, Section 5.2, p. 21). TGFN submits that the impact of this change that relates to 2010 was included in the IFRS deferral account consistent with Commission Order G-147-09 (Application, Section 7.6.7, p. 44) and the new rate of 14 percent has been applied to 2011 gross O&M expenses of $812,000, resulting in $114,000 of Overheads Capitalized and $698,000 in 2011 net O&M expenses (Application, Table 5-1, p. 22).
The Commission accepts the rate of 14 percent as an appropriate Overheads Capitalization rate for TGFN as this rate is consistent with the approved rate of TGI.
3.5 Taxes
In the Application, TGFN indicates that it is subject to a number of taxes including property taxes, income taxes, carbon taxes and other commodity taxes. Property taxes are a function of corporate revenue, property assessment and property class tax rate. Revenues used in the calculation are based on corporate revenues from 2 years ago (Application, Section 6.2, p. 24). Overall, property taxes are expected to increase in 2011 as compared to 2010 by 5 percent. Increases in billed revenues, between 2008 and 200, accounts for 32 percent of the total increase of change, while changes in property assessments and tax rates accounts for the remaining 68 percent of the increase (Application, Section 6.2, p. 27).
The Commission accepts TGFN’s submissions and methodologies used to forecast taxes in 2011 as these items are consistent with substantially enacted tax rates and methodologies utilized by TGI.
3.6 Rate Base
3.6.1 Plant in Service and Capital Additions
In the Application, TGFN forecasts a 2011 Mid-year Plant in Service of $6.571 million compared to $5.320 million in prior years. The significant increase in Plant in Service is due to forecasted additions, originally estimated at $2.672 million before considering the impact of the Evidentiary Update. Of that amount, $2.475 million represents capital expenditures originally forecasted for the Muskwa Project, which is discussed above. The remaining $197,000 in additions represent the replacement of a outbuilding for $8,000 and upgrades at the Muskwa Gate Station which will involves replacing obsolete valves, stations and regulators as well as filters at the Muskwa Gate Station in order to maintain the safety, reliability and integrity of the station. This upgrade work began in 2010 and will carry over into 2011 (Application, Section 7.3.1, p. 32).
The Commission accepts the Plant in Service projections and forecast capital expenditures to plant in service as submitted for all items in the Application excluding the Muskwa Project. The Muskwa Project has been considered elsewhere in this decision.
3.6.2 Changes in Depreciation
TGFN seeks approval to implement effective January 1, 2010 the same depreciation rate changes approved for TGI by the BCUC Order G-141-09 dated November 26, 2009 to better reflect the useful life of assets of the Utility. For 2010, the difference in previously approved depreciation rates and the rates approved for TGI’s 2010 and 2011 fiscal years by Order G-141-09 were accumulated in the IFRS deferral account as approved by Commission Order G-147-09. This amount totalled $59,000 in 2010 (Application, Section 7.6.7, p. 44). TGFN has forecasted 2011 with the updated TGI deprecation rates (Application, Section 7.3.4, pp. 41-42). As a result of this change, approximately one quarter of the forecasted revenue requirements increase of $295,000 as included in the intial Application, before amendment through the Evidentiary Update, is a result of these revised depreciation rates (Application, Section 1, p. 1).
The Commission approves the requested depreciation increases for implementation effective January 1, 2010 to align with the approved depreciation rates of TGI which are the most recent estimates of the useful life of the Utility’s assets.
3.6.3 Lead-Lag Study
As part of the TGI 2010-2011 Revenue Requirements Application, a Lead Lag Study was completed which resulted in an updated estimate of working capital requirements. The results of the Lead Lag Study were approved by Order G-141-09 as part of the Negotiated Settlement for TGI. TGFN is proposing to adopt the results of this updated Lead Lag Study in 2011. When applied to the revenues and operating expenses for 2011, this change in net days results in an increase of approximately $124 thousand in cash required for operating expenses as compared to the previously approved days (Application, Section 7.7, p. 47).
The Commission approves the adoption of the updated Lead Lag study for implementation effective January 1, 2011 to utilize TGFN’s most recent estimate of net days and also align with the Lead Lag methodology in use by TGI.
3.6.4 Deferral Accounts
The Utility seeks to continue using the existing, approved deferral accounts as follows (Application, Section 7.7, p. 4):
• Gas Cost Reconciliation Account (GCRA)
• Revenue Stabilization Adjustment Mechanism (RSAM) and RSAM Interest
• Property tax deferral
• Deferred Interest
• ROE & Capital Structure Deferral
• IFRS Transitional Deferral
Total mid-year deferral amounts forecasted by TGFN for 2011 total $154,000 as compared to $100,000 expected for 2010. The primary reason for the increase to deferral accounts results from additions to the IFRS Transitional Deferral account which have occurred due to the changes in depreciation and capitalized overhead rates made by TGI as approved by Commission Order G-141-09 and subject to deferral in 2010 as approved by Commission Order G-147-09 (Application, Table 7-4, p. 42). TGFN has not yet proposed a recovery strategy for the IFRS Transitional Deferral account as one will be proposed in the next revenue requirements application, consistent with TGI, when the accounting changeover is complete (Application, Section 7.6.7, pp. 44-45).
Further, in the Applications, TGFN requests that the 2010 additions to the deferral account ROE & Capital Structure Deferral forecasted to be $56,000 be fully amortized in 2011 (Application, Section 7.6.6, p. 44).
Also, in the Application, TGFN seeks approval for an additional deferral account entitled “Revenue Requirement Application” (RRA) deferral account. This account would allow TFGN to accumulate and defer costs related to the Application within a deferral account for recovery over the period of the Application. TGFN estimates total costs for this application will total $11,000. This treatment would result in consistent cost treatment with those of TGI (Application, Section 7.6.5, p. 43).
The Commission approves continuing with the previously approved deferral accounts and methodologies as they remain relevant to the rate-making methodology of TGFN. The Commission also approves the requested amortization of the ROE & Capital Structure deferral account to allow for the recovery of amounts previously approved by the Commission. Further, the Commission approves the creation of the RRA as this mechanism is consistent with methodology used by TGI and allows for appropriate recovery of costs from the period to which they relate.
3.6.5 Financial and Capital Structure
In the Application, TGFN indicates that it maintains the same capital structure as TGI which consists of 40 percent equity and 60 percent debt and this structure was approved by Commission Order G-158-09. The same Commission Order also approved the Utility’s Return on Equity (ROE) of 9.5 percent (Application, Section 8, p. 48). As a result of this change, approximately 40 percent of the initial increase in revenue requirements of $295,000 as included in the Application, before amendment, is a result due to these revised depreciation rates (Application, Section 1, p. 1).
TGFN forecasts the Utility’s average embedded cost of long-term debt at 6.945 percent and unfunded debt cost at 4.5 percent with total debt consisting of 13 percent unfunded debt and 47 percent long-term debt (Application, Section 8, p. 48).
The Commission accepts the TGFN capital structure, average embedded cost of long-term debt and unfunded debt cost noting that these amounts are consistent with those of TGI.