IN THE MATTER OF
FortisBC Energy Inc.
Annual Review of 2015 Delivery Rates
Decision
May 27, 2015
Before:
D. A. Cote, Commissioner/Panel Chair
H. G. Harowitz, Commissioner
D. M. Morton, Commissioner
TABLE OF CONTENTS
Page No.
1.2 Approach to FEI Annual Review Decision
1.4 Application review process
2.0 DETERMINATIONS ON ISSUES ARISING
2.1.2 Average UPC – residential and commercial
2.1.2.1 Residential UPC forecast
2.1.2.2 Commercial UPC forecast
2.1.3 Residential and commercial net customer additions forecast
2.1.5 Natural Gas for Transportation and LNG demand
2.1.6 Quality of demand forecast presentation
2.2 Regionalization Initiative
2.3 Rate Schedule 46 O&M adjustment
2.4 Service Quality Indicators
2.5 Reporting of exogenous savings
2.6 Proposed compliance filing updates
3.0 DETERMINATIONS ON APPROVALS SOUGHT
3.1 Permanent
delivery rates and treatment of differences between
interim and permanent rates
3.2 Earnings sharing disbursements and process
3.3.1.1 2017 LTRP Application deferral account
3.3.2 Changes to existing deferral accounts
3.3.2.1 BFI Costs and Recoveries deferral account
3.3.2.2 FEW Revenue Surplus/Deficiency deferral account
3.3.2.3 EEC Incentives for AES/TES deferral account
4.1 Preparation of future applications and reporting on efficiency initiatives
4.2 Future annual review process
COMMISSION ORDER G-86-15
Appendices
Appendix A – List of Acronyms
Appendix B –Exhibit List
EXECUTIVE SUMMARY
By Order G-138-14 on September 15, 2014, the Commission approved a Performance Based Ratemaking (PBR) Plan for FortisBC Energy Inc. (FEI) covering a six-year period commencing in 2014. A key element of the PBR Plan is the provision of an Annual Review designed to provide stakeholders with regular updates on the performance of the plan and an opportunity for them to review and discuss the information and comment on various elements of the plan and any issues arising.
On January 14, 2015, FEI filed its Annual Review of 2015 Delivery Rates Application. FEI, among other things, seeks approval of permanent delivery rates for all non-bypass customers effective January 1, 2015, pursuant to sections 59 to 61 of the Utilities Commission Act (UCA).
FEI raised concern with the Commercial Energy Consumers Association of British Columbia’s (CEC’s) comments on the success of the PBR Plan. FEI believes that CEC has prematurely concluded that the PBR Plan is a failure in spite of positive signs pointing to the potential for success. In FEI’s view, CEC’s submissions are out of scope. The Panel agrees with FEI and considers the PBR Plan to be at a very early stage. In our view it is premature to comment on whether the PBR Plan will have a positive or negative outcome given that the review period covers only the first three months since it was put in place.
Following the Introduction, the Decision addresses the following:
• Issues which have arisen during the proceeding. Demand forecasts and other matters of importance including issues related to the regionalization initiative and an adjustment to Rate Schedule 46 operating and maintenance (O&M) expenses, among other things;
• Determinations on approvals sought by FEI; and
• A discussion of and determinations on, the annual review process.
Issues Arising
Demand Forecasts
FEI prepared demand forecasts for its residential, commercial and industrial customer groups. For residential and commercial customers these forecasts are primarily driven by separate forecasts for use per customer (UPC) rates and customer additions. Industrial demand forecasts are primarily reliant upon a survey of expected demand conducted with members of this customer group.
i) Residential Demand Forecast
The Panel raises concerns with the efficacy of FEI’s average UPC forecast as well as the methodology it has used to determine it. The Panel rejects FEI’s forecast average UPC of 81.1 gigajoules (GJ) for 2015 and directs FEI to adjust its residential UPC forecast to 83.1 GJ as part of its compliance filing. The Panel also directs FEI to review alternative methodologies and develop one that overcomes identified shortcomings and more accurately predicts actual average UPC for the next annual review.
Some concern was raised with respect to the use of Conference Board of Canada (CBOC) housing starts as a proxy for residential net customer additions. The Panel accepts the use of CBOC information pointing out it is a valuable information tool that separates single-family from multi-family dwellings each of which have significantly different capture rates. We also note the small impact on rates given the minor impact a variance on net customer additions has on total customers in a given year.
ii) Commercial Demand Forecast
An increase in average UPC is forecast for all commercial rate classes. FEI relies upon a three-year average of historical weather normalized UPC data to forecast commercial UPC. The Panel approves FEI’s commercial UPC forecasts as filed noting that they are directionally in line with past performance and any variances which do occur can be managed through the rate stabilization adjustment mechanism (RSAM).
The Panel approves FEI’s 2015 forecast for commercial net customer additions, as the 2015 forecast is reasonably close to recent actual customer additions and none of the interveners have taken issue with this forecast. However, noting concern with the level of accuracy of commercial additions forecasts, the Panel directs FEI to consider alternative methods for forecasting commercial customer additions which are more appropriately sensitive to the business cycle.
iii) Industrial Demand Forecast
There have been consistent variances in industrial demand forecasts in recent years. FEI identifies fuel switching as a major issue with these variances and has moved the timing of the Industrial survey closer to the forecast period as a way of addressing such variances. This is expected to reduce the risk of variances as there is less lag between the survey date and the forecast period. The Commission Panel approves the industrial forecast as proposed as FEI has taken steps to identify the source of the problem with industrial forecasting and made some progress in initiating measures to address it.
Regionalization Initiative
FEI has developed what it refers to as the Regionalization Initiative. This is designed to create solutions that enhance customer experience while achieving a more efficient process in the field and has involved moving parts of centralized activities into locations within the regions. One such initiative involves moving people and related costs ($267 thousand) from the FEI O&M base to FortisBC Energy (Vancouver Island) Inc. (FEVI). The question before the Panel is whether it was appropriate to leave these costs in FEI’s O&M base given its impact on earnings sharing and the fact that costs had been moved, not eliminated. The Panel has considered the O&M savings claimed by FEI to be properly applied under the terms of the PBR Plan and notes that adjustments to the base of FEVI are the subject of another proceeding. The Panel expects this issue will be thoroughly addressed in the context of that proceeding.
Rate Schedule 46 O&M Adjustment
FEI submits that in preparing its Rate Schedule 46 demand forecast, it took a conservative approach to spot purchases, and did not include spot purchases as part of the forecast revenue because they are not firm agreements. However, FEI submits it did include O&M costs related to serving these customers as part of its 2015 O&M forecast. This creates a misalignment of costs and revenues. The Panel therefore approves FEI’s proposal to reduce Rate Schedule 46 by $480 thousand resulting in a revised O&M forecast of $935 thousand.
Determinations on Approvals Sought
(a) Permanent Delivery Rates and Differences between Interim and Permanent Rates.
The requested permanent delivery rates for all non-bypass customers effective January 1, 2015, representing an increase of 2.03 percent compared to 2014 common delivery rates, are not approved as filed. Permanent delivery rates for all non-bypass customers effective January 1, 2015, as modified by the directives in the Decision, are approved.
The difference between the 2015 interim rates and permanent rates, including the Earnings Sharing rider for Mainland customers, is approved to be collected from/refunded to customers with interest at the average prime rate of FEI’s principal bank.
(b) Earnings Sharing Disbursement and Process
The Panel approves the 2014 earnings sharing amount as projected by FEI in the Application and approves the 2014 earnings sharing amount to be disbursed to Mainland customers via a rate rider effective for a twelve month period from January 1, 2015.
(c) Deferral Accounts
The Panel approves the establishment of the 2016 Cost of Capital Application deferral account and the 2017 Rate Design Application deferral account and approves a weighted average cost of capital to be earned on each of these two new deferral accounts.
The Panel rejects FEI’s request for approval of the 2017 Long Term Resource Plan Application (2017 LTRP Application) deferral account at this time pending further review at the next Annual Review. The Panel directs FEI in its next Annual Review Application to provide a more detailed budget and justification for its requested 2017 LTRP Application costs.
(d) Handling of BFI Costs and Recoveries Deferral Account
The Panel approves the transfer of the balance in the BFI Costs and Recoveries Account – All Other Recoveries deferral account to the Compressed Natural Gas (CNG) and Liquified Natural Gas (LNG) Recoveries deferral account, effective December 31, 2015. The Panel further approves the disposition and discontinuance of the BFI Costs and Recoveries Account – All Other Recoveries deferral account, effective December 31, 2015.
(e) EEC Incentives for AES/TES Deferral Account
The Panel approves the transfer of the ending balance in the Energy Efficiency and Conservation (EEC) Incentives for Alternative Energy Services/Thermal Energy Services (AES/TES) deferral account to the rate base EEC deferral account and approves the discontinuation of the EEC Incentives for AES/TES deferral account, effective January 1, 2015.
Annual Review Process
Preparation of Future Applications
The Panel considers it essential during the PBR term that certain information be gathered on efficiency initiatives, including how these initiatives impact the organizational structure of FEI and the expected savings
and/or costs resulting from these initiatives. The purpose of this is to gain an understanding of how savings are being achieved and to acquire some quantifiable data on these savings and initiatives throughout the PBR term. The Panel directs FEI to provide in each annual review application the updated tabular information on the Regionalization Initiative and Project Blue Pencil as well as any new initiatives in a format similar to that used in BCUC IR 1.2.9 and 1.3.3. In addition, the Panel directs FEI, among other things, to include in its annual review filings the total year-end number of employees and full time equivalent employees.
Future Annual Review Process
The Panel shares the view held by most parties that the process used in the current proceeding is an appropriate general framework for future annual reviews. While we understand concerns with precluding the possibility of additional regulatory process components such as a second round of information requests and ensuring a fulsome record in a given year, we are also mindful that one of the underlying principles of the PBR regime is regulatory efficiency. Therefore, the Panel sets out a default template for future annual reviews which is very similar to that employed in this proceeding.
1.0 INTRODUCTION
1.1 Background
By Order G-138-14 on September 15, 2014, the British Columbia Utilities Commission (Commission) approved a Performance Based Ratemaking (PBR) Plan for FortisBC Energy Inc. (FEI, the Company) covering a six-year period commencing in 2014. A primary purpose of the PBR Plan is to create an incentive for FEI to adopt a productivity focus and seek out sustainable operating and capital savings while maintaining service quality as measured by Service Quality Indicators (SQIs). The PBR Plan provides for an equal sharing of any PBR related savings between the customer and the Company.
A key element of the PBR Plan is the provision for an annual review. The purpose and content of the annual review was a point of considerable contention in the PBR proceeding. FEI envisioned it to be primarily an information-sharing forum similar in terms of scope and process to less formal annual reviews held for previous PBRs. A number of interveners saw the annual review process as being much broader in scope capable of dealing with a variety of issues.[1] Considering these two perspectives, the Commission determined that an extensive annual review process was necessary to build trust among the stakeholders and to ensure the PBR Plan was functioning as intended. For clarity, the Commission was prescriptive in setting out the list of activities to be undertaken in annual reviews. These activities are as follows:
1. Evaluation of the operation of the PBR Plan in the past year(s) and identification by any party of any deficiencies/concerns with the operation of the PBR Plan that have become apparent. Parties are expected to put forward recommendations with how to deal with such concerns.
2. Review of the current year projections and the upcoming year’s forecast. For further clarity, these items are listed below:
a. Customer growth, volumes and revenues;
b. Year-end and average customers, and other cost driver information including inflation;
c. Expenses (determined by the PBR formula plus flow-through items);
d. Capital expenditures (as determined by the PBR formula plus flow-through items);
e. Plant balances, deferral account balances and other rate base information and depreciation and amortization to be included in rates;
f. Projected earnings sharing for the current year and report on true-up to actual earnings sharing for the prior year; and
g. Any proposals for funding of incremental resources in support of customer service and load growth initiatives.
3. Identification of any efficiency initiatives that the Companies have undertaken, or intend to undertake, that require a payback period extending beyond the PBR Plan period and make recommendations to the Commission with respect to the treatment of such initiatives.
4. Review of any exogenous events that the Company or stakeholders have identified that should be put forward to the Commission for decision as to their exclusion from the PBR Plan. The review process should include recommendations as to how the exogenous events costs/revenues should be recovered from or credited to ratepayers.
5. Review of the Companies’ performance with respect to SQIs. Bring forward recommendations to the Commission where there has been a “sustained serious degradation” of service.
6. Assess and make recommendations with respect to any SQIs that should be reviewed in future annual reviews. For example, stakeholders are to review the usefulness of continuing with the Billing Index and Meter Reading Accuracy SQIs.
7. Assess and make recommendations to the Commission on the scope for future annual reviews.[2]
In compliance with Order G-138-14, FEI filed its first Annual Review Application (Application) on January 14, 2015. The Company states that due to its focus on productivity and its efforts to seek alternate solutions to filling staff vacancies, it proposes to distribute $3.341 million to Mainland customers in 2015 via an earnings sharing rate rider. In addition, FEI proposes a 1.96 percent increase (updated to 2.03 percent increase in Exhibit B-1-1) in delivery rates over 2014 rates flowing from approved formulas and forecasts as set out in the Application. This increase is in line with 2015 inflation forecast at 1.9 percent and is to be applied also to Vancouver Island and Whistler service area customers in 2015. After taking into consideration the earnings sharing mechanism, the effective increase to Lower Mainland customers will be 1.44 percent (updated to 1.5 percent in Exhibit B-1-1) or an increase of approximately 0.8 percent on the annual bill.[3]
1.2 Approach to FEI Annual Review Decision
The Decision has been separated into four sections.
Section 1 provides some background to the Application, a brief summary of 2014 results, requirements for 2015 and the process for review. This section also outlines the approvals and issues to be addressed in the following sections. In addition, the Panel considers it appropriate for purposes of clarity to address concerns raised during the course of this proceeding as to the PBR Plan itself and the implications of Order G-138-14 on the current and future annual review processes.
Section 2 addresses issues which have arisen over the course of the proceeding which require either clarification or a determination to be made by the Panel. Issues to be addressed are the following:
• Demand forecast accuracy and methodology;
• Transfer of costs from FEI to FortisBC Energy (Vancouver Island) Inc. (FEVI) resulting from the Regionalization Initiative;
• Rate Schedule 46 – operations and maintenance (O&M) adjustment;
• Service Quality Indicators;
• Reporting of exogenous savings;
• FEI proposed compliance filing updates.
Section 3 reviews the approvals sought by FEI as listed below in Section 1.3.
Section 4 addresses future annual review applications with respect to additional requirements for future applications and developing a review process which best addresses the needs of the parties. The Commission made specific reference to this in its letter of March 10, 2015, and requested parties to provide written submissions on this matter.
1.3 Approvals sought
FEI seeks the following approvals pursuant to sections 59 to 61 of the Utilities Commission Act (UCA):
1. Permanent delivery rates for all non-bypass customers effective January 1, 2015, resulting in an increase of 1.96 percent (updated to an increase of 2.03 percent in Exhibit B-1-1) compared to 2014 common delivery rates, with the increase to be applied to the delivery charge, holding the basic charge at existing levels.
2. The Earnings Sharing riders for Mainland customers effective January 1, 2015, in the amounts set out in Table 10-2 in Section 10 of the Application.
3. The difference between 2015 interim rates and permanent rates, including the Earnings Sharing riders for Mainland customers, to be collected from customers by way of a bill adjustment reflecting their consumption from January 1, 2015.
4. The creation of rate base deferral accounts for the following upcoming regulatory proceedings as described in Section 7.5 of the Application:
a. Cost of Capital to be filed in 2015;
b. Rate Design to be filed in 2016; and
c. Long-Term Resource Plan to be filed in 2017.
5. The transfer of the balance in the BFI Costs and Recoveries - All Other Recoveries deferral account to the Compressed Natural Gas (CNG) and Liquefied Natural Gas (LNG) Recoveries account as described in Section 7.5 of the Application.
6. The disposition of the FortisBC Energy (Whistler) Inc. (FEW) 2014 Revenue Surplus/Deficiency deferral account, by amortizing the balance of the account into delivery rates in 2015 as described in Section 7.5 of the Application.
7. The transfer of the Energy Efficiency and Conservation (EEC) Incentives for Alternative Energy Services (AES)/Thermal Energy Services (TES) deferral account to the rate base EEC Incentives deferral account as described in Section 12.4.3 of the Application.[4]
1.4 Application review process
By Order G-6-15 on January 22, 2015, the Commission established a Regulatory Timetable. This included one round of information Requests (IRs), a workshop open to all participants, an opportunity for FEI to provide undertakings for any outstanding responses from the workshop, final submissions from interveners and a reply submission from FEI.
There were four interveners that registered for the proceeding:
• British Columbia Pensioners’ and Seniors’ Organization, et al.(BCOAPO);
• Commercial Energy Consumers Association of British Columbia (CEC);
• BC Sustainable Energy Association and The Sierra Club of British Columbia (BCSEA); and
• Canadian Office and Professional Employees Union, Local 378 (COPE).
1.5 Order G-138-14 in context
FEI raises a concern with comments regarding the success of the PBR Plan made by CEC during the course of this proceeding. Despite limited experience with this PBR Plan and what FEI believes to be “positive signs pointing to the potential for success,” FEI believes that CEC has concluded there is ample evidence that the PBR Plan is a failure. In FEI’s view, CEC’s written submissions “go well beyond the scope of comments intended for the purpose of evaluating PBR in the annual review” and submits that “CEC’s submissions amounts to a request for reconsideration of the Commission’s PBR Decision.”[5] FEI takes exception to a number of CEC’s submissions. These are outlined as follows:
1. CEC states that “the benefits of a PBR plan must also include preservation of cost-benefit relationships (i.e. cost efficiencies should not come at the expense of benefits)” and “PBR should include evaluation against the retention of beneficial activities and potentially the development of new beneficial programs and services.” FEI states that this would require the Commission to examine management decisions to determine whether benefits are lost or new benefits gained which would amount to micro-managing FEI.[6]
2. CEC also states that a result of PBR should be savings “that substantially exceed those that would normally be achieved through prudent management” and “pre-existing cost savings programs…[should] not be rewarded.” FEI states that this would entail distinguishing between savings that are based on performance based ratemaking from those due to prudent management. The Company submits that this distinction is not included in the PBR Plan and therefore not relevant in the determination of rates.[7]
3. With respect to savings due to the elimination of positions or not filling vacancies, CEC states: “This type of organization adjustment is an ordinary and common responsibility of management and should be delivered to the base before any PBR considerations.”[8] FEI notes in contrast to the position of CEC that “any savings achieved are valid under PBR and contribute to whether there is an earnings sharing in a given year.”[9]
As outlined in Section 1.1 above, the Commission encourages ongoing evaluation of the PBR Plan and the identification of problems with the operation of the plan and recommendations for improvement. Those recommendations which do not require change to the terms of the PBR Plan may be dealt with within this PBR period. Others, which require material change to the PBR Plan’s fundamental provisions, will require a reconsideration application or at least the agreement of all parties prior to the Commission considering a change. The Panel considers the concerns raised by FEI regarding the recommendations of CEC to fall in the latter category of requiring a material change to the terms of the existing PBR Plan and thus is not prepared to consider them at this time.
The Panel considers the PBR Plan to be at a very early stage. While CEC is free to express its views on the PBR Plan’s ultimate success or failure, the Panel agrees with FEI that it is too early to evaluate the PBR Plan as there is a limited basis on which to reach a conclusion. In the Panel’s view, it is premature to comment on whether the PBR Plan will have a positive or negative outcome as a three month period since the PBR Decision is an inadequate review period to support either conclusion.
2.0 DETERMINATIONS ON ISSUES ARISING
2.1 Demand forecasts
2.1.1 Background
A key determinant of rates is the demand forecast which must be updated at each annual review. Gas sales and transportation volumes are based on forecasts of total energy demand from three customer groups: residential, commercial and industrial. FEI relies upon a variety of methods to determine forecast demand which varies by customer type. The methodologies in the current demand forecasts are consistent with those used in prior years and, in FEI’s view, provide a reasonable estimate of 2015 natural gas demand. FEI forecasts normalized demand to be approximately 205 petajoules (PJs) in 2015 representing a decrease of approximately 4 PJs in comparison to 2014. Based on the 2014 common rates by customer class, the 2015 revenue forecast is $1,374.819 million and the 2015 gross margin forecast is $741.654 million.[10]
The demand forecasts for residential and commercial customers are driven by forecasts for net customer additions and average use per customer (UPC). To derive energy consumption, the average UPC for customers in Rate Schedules 1, 2 and 3/23 is forecast and then multiplied by the corresponding number of customers in these rate classes. Forecast industrial demand is based upon a survey of forecasts completed by members of this customer group.[11]
Residential and commercial rate classes have a Rate Stabilization Adjustment Mechanism (RSAM). Therefore, when there are variances between actual and forecast UPC volumes used to set residential and commercial rates, the resulting delivery charge differences are recorded in the RSAM account. These variances are amortized into rates over a two-year period.[12]
2.1.2 Average UPC – residential and commercial
In developing
individual regional UPC projections for each residential and commercial rate
class, FEI has relied upon the most recent three-year historical
weather-normalized UPC.[13]
These are developed for each service region and then consolidated. FEI states
that UPC is calculated using one of two methods: a three-year average of change
in UPC or, as a result of regression analysis, based on four years of
historical data.[14]
Regression analysis is only used where a trend is present (a correlation coefficient of .50 or greater).[15] Table 1 illustrates the forecast methodologies used by FEI for its service areas.
Table 1 – UPC Calculation Method – By Service Area[16]
2.1.2.1 Residential UPC forecast
Figure 1 shows the change in UPC for Residential (Rate Schedule 1) customers from 2005 through 2013 and forecasts for 2014 and 2015.
Figure 1 – UPC Rate Schedule 1[17]
The historical data presented in the above figure indicates a continued downward trend in residential weather‑normalized UPC with a 3.2 gigajoule (GJ) drop in UPC forecast between 2013 and 2015.
Table 2 is an excerpt from data presented on the Consolidated UPC in answer to BCUC IR 1.5.1.1. Corrections have been made to more accurately reflect the variance in units and the variance in percentage.
Table 2 – Consolidated UPC (Excerpt)[18]
Table 2 presents residential forecasts for 2014 which differ significantly from those in Figure 1 which accompanied the Application. Based on the information provided in response to BCUC IR 1.5.1.1, the forecast average UPC for 2014 has increased by 1.0 GJ from Actual 2013 UPC but is then forecast to decrease by 4.3 GJ in 2015. This is in contrast to the information provided in the Application, which shows a decrease from 2013 to 2014 of 1.6 GJ and then a further decrease of 1.6 GJ for the 2015 forecast UPC. FEI has provided no explanation as to why the residential UPC data provided in response to BCUC IR 1.5.1.1 is different from the residential UPC data provided in the Application. FEI has under-forecasted average UPC on a consolidated basis four out of five times from 2009 through 2013 and appears to have done so again in 2014. This has the effect of inflating rates each year despite variances being managed through the RSAM.
Intervener submissions
BCOAPO, relying on information in Figure 1, submits that FEI forecasts a decline in average UPC of 1.6 GJ. However, the average UPC for the years 2005-2014 is a decline of 1.3 GJ and if only the most recent data (2008‑2013) is considered, the average decline is only 0.82 GJ. BCOAPO recommends that the average UPC for Rate Schedule 1 customers be based on the five-year actual average decline that occurred from 2008-2013.[19]
CEC also relies on the information in Figure 1 and submits that if the average decline in GJs from 2005 is used, it would result in a 0.2 PJ increase in the Rate Schedule 1 demand forecast. CEC agrees with comments made by FEI that a forecast based over a longer term exhibits significant variation but does not agree that the declining trend forecast for 2013 through 2015 will be sustained as “there is evidence of flattening of UPC declines following periods of more significant declines.” CEC recommends the Commission consider a residential demand forecast based on an average UPC decline of 1.3 GJ per year rather than 1.6 GJ.[20]
FEI reply
FEI submits that CEC and BCOAPO have “cherry
picked” from data resulting in increased demand and have not referred to
“evidence in this proceeding that demonstrates that their changes to the
forecast would result in a more accurate demand forecast.” FEI provided
explanation as to why it considered a three-year window is an appropriate basis
for the UPC forecast pointing out that it is critical that data are not
outdated and that a
three-year window “captures an appropriate amount of data that is both relevant and current.” FEI further points out that the three years of data it proposes reflects the impact of EEC programs and eliminates data that no longer reflect recent conditions.[21]
Commission determination
The Panel has concerns with both the efficacy of FEI’s 2015 average residential UPC forecast as well as the methodology it has applied to determine this forecast.
As outlined in Table 2, FEI has under-forecasted average residential UPC on a consolidated basis four out of five times from 2009 through 2014. The residential average UPC forecast presented in the Application (and included as Figure 1 in this Decision) shows a decline of 1.6 GJs on a consolidated basis from 2013 to 2014 and a further decline of 1.6 GJs from 2014 to 2015. The forecast of consolidated UPC presented in response to BCUC IR 1.5.1.1 (see Table 2) differs significantly from the Application. Based on BCUC IR 1.5.1.1, the forecast average UPC for 2014 is 85.4 GJs which represents an increase of 1 GJ over 2013. Further, the 2015 forecast average UPC has changed to 81.1 GJs, which represents a decline of 4.3 GJs from the previous year based on the data in Table 2. This is a significant departure from the forecast shown in the Application with no explanation for this difference provided. Given FEI’s historical forecast accuracy and the difference in forecasts between the Application and the response to BCUC IR 1.5.1.1, the Panel is not persuaded that the forecast residential average UPC on a consolidated basis can be relied upon. Therefore, the Panel rejects FEI’s forecast residential average UPC of 81.5 GJ for 2015. The Panel considers that repeating the 2014 forecast provided in the Application of 83.1 GJs is more appropriate for 2015 as it reflects a more reasonable forecast given the variation in 2014 and 2015 forecast information between BCUC IR 1.5.1.1 and the Application. Therefore, the Panel directs FEI to adjust its 2015 residential UPC forecast to 83.1 GJ as part of its compliance filing.
The Panel is also concerned with the forecast methodology itself. CEC and BCOAPO submit that the number of years relied upon by FEI in preparing its forecasts are too few and recommend that the forecast period be lengthened. FEI has argued that it is most important that data is not outdated and that limiting the timespan will more accurately reflect current trends. The Panel has additional concerns. A reliance on averages whether they be over 3, 5 or 10 year periods is ineffective as a means of determining future needs when either an upward or downward trend exists. An average is just that, it will reflect a number which is too high when UPC has been declining and too low when UPC is increasing. However, relying on regression analysis with 3 years history is equally fraught with difficulties as a much longer period is generally required to provide reliable results. Moreover, FEI’s practice of breaking a 3-year forecast into monthly totals may reduce accuracy as the smoothing out of seasonal demand may introduce other errors into the regression equation. Further, a reliance on more than one method and combining them to arrive at a forecast is questionable and is a potential source of forecasting error. Given FEI’s forecasting history and the noted problems with the present methodology, the Panel considers a review of forecasting alternatives is warranted. Accordingly, the Panel directs FEI to review alternative methodologies and develop one that overcomes the identified shortcomings and more accurately predicts actual average UPC for the next annual review.
2.1.2.2 Commercial UPC forecast
Commercial customers are divided into three rate schedules: Rate Schedule 2, Small Commercial; Rate Schedule 3, Large Commercial; and Rate Schedule 23, Large Commercial Transportation. An increase in average UPC in 2015 is forecast for all rate classes. However, Large Commercial and Large Commercial Transportation show the greatest upward growth over time, a trend which is expected to continue.
Intervener submissions
CEC submits that the commercial classes are important in that they are one of the few classes where overall demand is not in decline. CEC emphasizes the importance of preserving throughput and maintaining rates and accepts that the activities FEI has undertaken to stimulate demand are reasonable.
CEC notes that FEI utilizes a three-year average of historical weather normalized UPC data to forecast commercial UPC. CEC considers the forecasted commercial UPC to be consistent with trends in prior years and recommends the Commission accept them as filed.[22]
BCOAPO notes that for Rate Schedule 2 FEI has forecasted a UPC increase of 1 GJ while the average for 2005‑2014 is 2.78 GJ and 2.68 for 2008-2013. BCOAPO recommends that the forecast increase for Rate Schedule 2 customers be tied to the average increase for the past 5 years commencing in 2008.[23]
FEI reply
FEI states that BCOAPO’s sole reason for its recommendation to base UPC on a five year average is that it results in the highest UPC compared to other averages. FEI submits that methodologies should not be chosen because they produce a particular result and the evidence does not support using a five-year average to forecast UPC.[24]
Commission determination
The Panel approves FEI’s commercial UPC forecasts as filed. The Panel notes that commercial UPC forecasts for 2015 are directionally in line with past performance and in spite of identified problems related to relying upon averages when a trend exists, the averaging methodology has produced reasonable results in the past. In addition, any variances which do occur are managed through the RSAM which mitigates ratepayer risk. However, given the identified problems, and consistent with the Panel determination in Section 2.1.2.1 above, the Panel directs FEI to include commercial customers as part of its review of alternative methodologies for forecasting UPC for the next annual review.
2.1.3 Residential and commercial net customer additions forecast
FEI states that it relies on the Conference Board of Canada (CBOC) housing starts forecast as a proxy for residential net customer additions. Commercial customer additions are based on an average of actual net customer additions for the most recently completed three-year period. FEI reports that since 2013, residential net customer additions have rebounded from recent lows and the 2015 forecast of 9,710 net additions is consistent with this. Likewise, commercial net customer additions have rebounded to pre-2009 levels bringing the three-year historical average for commercial customer additions to 1,004.[25] Based on the information provided in response to BCUC IR 1.5.1.1, there have been fairly significant variances between forecast and actual commercial customer additions in recent years.
Intervener submissions
CEC notes that there have been significant variances in residential customer additions ranging from +45 percent to -38 percent since 2009 and submits that the use of CBOC housing starts are inadequate as a proxy for residential customer additions. CEC recommends the Commission seek alternative means of forecasting residential customer additions.[26] CEC made no submissions regarding the number of new commercial customer additions.
FEI reply
FEI submits that the CBOC forecast has been approved by the Commission as recently as the FEI PBR Decision and its evidence supports the use of CBOC housing starts as a proxy for net customer additions. It explains that its methodology relies on previous year net additions and the CBOC forecast and has produced a statistically significant correlation between the CBOC housing starts forecast and residential customer additions. FEI points out that another advantage of the CBOC report is that it provides a breakdown between single and multi-family starts. This is necessary as its customer capture rates differ for single and multi-family dwellings.[27]
Commission determination
The Panel approves FEI’s 2015 forecast for residential net customer additions and accepts the use of CBOC housing starts as a proxy for these additions. Given that FEI capture rates are significantly different for single family versus multi-family dwellings, the disaggregated forecast provided by CBOC is a valuable tool for information which may not otherwise be readily available. Moreover, the impact on rates is small given the relatively minor impact a small variance on net customer additions has on total customers in a given year.
The Panel also approves FEI’s 2015 forecast for commercial net customer additions, as the 2015 forecast is in keeping with the recent actual customer additions and none of the interveners have taken issue with this forecast. However, the Panel notes that overall the historical accuracy of commercial customer additions forecasts has been poor. Accordingly, the Panel directs FEI to consider alternative methods for forecasting commercial customer additions which are appropriately sensitive to the business cycle. FEI is to provide an analysis of these alternatives in its next annual review application.
2.1.4 Industrial demand
There have been consistent variances in demand forecasts for Rate Schedule 22 in recent years. This issue was raised in the FEI PBR Decision where the Commission reduced FEI’s 2014 forecast and directed “FEI to develop a mechanism to adjust the Rate Schedule 22 demand forecast methodology to better reflect the impact of falling gas prices for review at the 2015 Annual Review.”[28]
The Industrial Survey has been the primary method of forecasting demand for the majority of industrial customers. FEI reports that to prepare for the 2015 forecast, customers completed the survey in October 2014 and that 90 percent responded. This represents a departure from past practice where the survey was conducted well in advance of the forecast period. For example, the annual survey for the 2014 filing was conducted in 2012. The major issue with variances, as explained by FEI, is fuel switching. If there is a change in gas pricing either up or down fuel switching is likely to occur, especially with large volume customers. FEI commented that if the gap between the survey and the forecast period is tightened up the opportunity for a customer to fuel switch is lessened. However, as pointed out by FEI: “[This] [i]s not to say that it still can’t happen but by doing the survey closer to the test period and only a year at a time, it does reduce the risk.”[29]
FEI forecasts the number of customers for FEVI and FEW in each rate class by relying upon rate mapping analysis presented in its Common Rates Methodology Application and approved by the Commission. This analysis allowed Whistler and Vancouver Island customers to be matched with the most appropriate FEI rate schedule following amalgamation.
FEI notes that the 2015 Industrial Survey was administered prior to amalgamation and therefore Whistler and Vancouver Island customers were not part of the survey. To determine the forecast volume for customers not included in the Industrial Survey, consumption estimates were made using 2013 actuals or using contract demand where applicable.[30]
Based on historical practice, FEI forecasts no new industrial customer rate schedule additions pointing out that none were known at the time the forecast was being prepared. Based on the Industrial Survey and other available information, industrial rate class demand is forecast to drop by 1.3 PJ to 77.5 PJ in 2015.[31]
Intervener submissions
Noting that FEI has forecast a decline in industrial demand of approximately 1.3 PJs, CEC submits that in assessing industrial demand, price sensitivity is a critical factor and falling gas prices are still relevant to this demand forecast. CEC submits that an increase in the 2015 demand forecast is appropriate noting that there has not been significant change in the methodology for Rate Schedule 22 forecasts. CEC recommends an increase of 21 percent for Rate Schedule 22.[32]
FEI reply
FEI asserts that a change in its forecast as applied for is not warranted “given FEI’s evidence with respect to the impact of the direction in 2014 and FEI’s efforts to increase the accuracy of the forecast for 2015.” FEI cited its response to BCUC IR 1.9.1 where it explained the source of the forecasting difficulty as being fuel switching and pointed out that moving the industrial survey closer to the test period allows the industrial customer to rely on the most recent natural gas and other energy cost information in its forecast thereby lowering the likelihood of unanticipated fuel switching.[33]
Commission determination
The Panel approves the FEI 2015 industrial demand forecast as filed. FEI, in our view, has taken steps to identify the source of problems with industrial demand forecasting and made some progress in initiating measures which may begin to address the problem and improve forecast accuracy. In addition, FEI has been directed to make improvements to its Rate Schedule 22 forecasting methodology and expects to address these in its upcoming annual review application to be filed later in 2015. As a further consideration, variances in industrial forecast demand are a flow-through item and by their nature are self-correcting. Therefore, the issue is one more of timing rather than risk. Given these factors, the Panel considers the FEI 2015 industrial demand forecast to be reasonable.
2.1.5 Natural Gas for Transportation and LNG demand
Figure 2 shows the 2011-2013 Actual, 2014 Projected and the 2015 Forecast covering annual demand for Rate Schedules 16/46 (LNG) and Rate Schedule 25 (CNG).
Figure 2 – Actual (A), Projected (P), and Forecast (F) for NGT[34]
Most of the liquefied natural gas (LNG) and compressed natural gas (CNG) are for Natural Gas for Transportation (NGT) but FEI points out that Rate Schedules 16/46 also include forecasts for two non-NGT customers. The 96 terajoules (TJ) reflect actual deliveries to these two customers in 2014 while the 2015 forecast of 236 TJ are based on customers’ estimates of increased requirements in 2015. FEI acknowledges that it took a conservative approach and did not include three spot purchase customers who are expected to take large volumes of LNG. These customers have no firm agreement with FEI.[35]
Intervener submissions
CEC submits that it is unacceptable to exclude spot purchases from the demand forecast as revenues and costs will not be appropriately matched resulting in the revenue requirement being unjustifiably increased. CEC has analyzed the O&M cost per PJ of LNG relationship and calculated an additional demand requirement of 0.5 PJ to cover these potential purchases.[36]
FEI reply
FEI accepts CEC’s criticism and acknowledges that the O&M expenses are built with the assumption that there will be spot purchases while the demand forecast does not include them. FEI agrees that an adjustment is reasonable but proposes that any adjustment should be made to serve a load consistent with its applied for demand forecast.[37]
Commission determination
The Panel approves the NGT and LNG demand forecasts as filed. However, CEC has raised an important issue regarding the correct matching of costs and revenues. FEI agrees with CEC but recommends addressing the issue by reducing the O&M rather than increasing the demand forecast. Given that there is no evidence as to the certainty or the size of the anticipated spot purchases, the Panel is prepared to consider the problem in the manner proposed by FEI and allow the reduction of O&M to balance the lack of inclusion of these spot purchases in the demand forecast. This will be addressed further in Section 2.3 of this Decision. However, in future annual reviews, FEI is directed to address the issue of spot purchases more fully and provide a proposal for including some or all of these purchases in the demand forecast based on an analysis of the probability of various outcomes.
2.1.6 Quality of demand forecast presentation
FEI states that in 2015 the demand forecast “is the largest single driver of the revenue deficiency.”[38] Given its significance, the Panel considers that the quality of presentation of the demand forecast could be improved upon in future filings, with specific regards to the lack of historical data and explanation of methodologies.
While Section 3 of the Application provides some information relevant to the Annual Review, much of the information was obtained through IRs. FEI states that “the number of IRs in future proceeding[s] may naturally lessen as FEI incorporates learnings from past proceedings” and “as many of the IRs in this proceeding focused on the demand forecast, FEI proposes to include in its next Annual Review application a description of its demand forecast methodology consistent with the detail provided in the response to IRs in this proceeding.”[39]
Commission determination
The Panel accepts FEI’s proposal to include in its next Annual Review application a fulsome description of its demand forecast methodology. The Panel also directs FEI to include information that in this proceeding was obtained through staff and intervener information requests as well as the analyses of alternative forecasting methodologies directed in this Decision. This information is to include:
• Historical forecast and actual data broken down by customer classes and service areas, as well as consolidated totals[40];
• The results along with an explanation of various aspects of the Industrial Survey used by FEI to forecast industrial demand;[41]
• As directed in Sections 2.1.2 and 2.1.3 of this Decision, a fulsome description of alternatives to existing forecast methodologies with recommendations to improve residential and commercial UPC forecasts and commercial net customer additions forecasts; and
• As directed in Section 2.1.5 of this Decision, a proposal for including some or all of the spot purchases in FEI’s future demand forecasts.
Furthermore, the Panel directs FEI to include the most recent ten years of historical actual data where possible.
The Panel is of the view that the inclusion of this information within the annual review applications will lead to a reduction in the number of information requests resulting in increased regulatory efficiency. In addition, inclusion of this information will allow the Panel to better understand the rationale behind FEI’s demand forecasts.
2.2 Regionalization Initiative
FEI projects O&M savings for those items covered by the PBR formula totaling $6.851 million in 2014. Much of these savings are related to labour expense where there has been a company wide effort to seek alternative solutions to filling vacancies. The Company states that most of the solutions have taken the form of resource re‑deployment and a broadening of roles and responsibilities. One result of this activity has been the Regionalization Initiative designed to enhance customer experience while achieving a more efficient process in the field. This initiative has involved moving parts of FEI’s centralized operational activities into locations within the regions.[42]
An issue which arises is the handling of costs which were included in FEI’s Base O&M at the outset of PBR but subsequently transferred to FEVI in 2014. As FEVI was not proposed to be included in the PBR until 2015 (i.e. the second year of the PBR term), the result of the transfer of costs from FEI to FEVI is that there may be a duplication of costs in the amalgamated PBR O&M Base. FEI states that this issue was addressed in response to BCUC IR 1.3.1 in the FEI Proposal to Include FEVI and FEW in the PBR Plan proceeding. In this IR response, FEI states that the “cost increase to FEVI from the regionalization of the dispatch group is $267 thousand in 2014. This is the loaded salary of four positions relocated to FEVI in May 2014.” FEI further states that from an amalgamated entity perspective, “the transfer of four positions from FEI to FEVI was neutral.”[43]
CEC submissions
CEC submits that a minimum of $267 thousand of O&M savings cannot be justified as these costs were moved to either FEVI or FEW. Under amalgamation these are cost neutral. CEC further argues that the regionalization of dispatchers resulted in a cost increase of $267 thousand to FEVI in 2014 and recommends the Commission deny the addition of these costs into the amalgamated base.[44]
CEC also argues that the Regionalization Initiative was not a direct result of PBR. CEC submits that although it was implemented in 2014, the initiative was conceived in 2013 and the scoping and planning was undertaken through 2013. Therefore, in CEC’s view, the O&M activities associated with the initiative were paid for by customers in 2013 rates and customers should receive the full benefits of those activities through an adjustment to the O&M base.[45]
FEI reply
FEI takes the position that FEVI’s base is the subject of another proceeding and is out of scope for the FEI Annual Review. FEI submits that it is not true that the O&M activities associated with the Regionalization Initiative were paid for by customers in 2013 rates because these rates were established as part of the 2012-2013 FortisBC Energy Utilities Inc. (FEU) Revenue Requirements Application (RRA) proceeding which concluded in 2012 before the Regionalization Initiative was planned. FEI continues by explaining that it has reported its O&M cost for 2014 appropriately as the costs were reduced in 2014 and properly applied in the PBR plan. FEVI was not a part of the PBR in 2014 and the additional costs were prudently incurred. Moreover, “[t]o the extent that FEVI’s O&M costs were higher than they otherwise would have been in 2014, these extra costs were properly borne by the shareholder.”[46]
Commission determination
The Panel agrees with FEI that adjustments to the base for FEVI are the subject of another proceeding and therefore, out of scope for this proceeding. We expect that this issue will be thoroughly reviewed in the context of that proceeding.
Further, the Panel rejects CEC’s recommended downward adjustment to FEI’s Base O&M to remove savings arising from the Regionalization Initiative. We agree with FEI that the O&M savings have been properly applied given the terms of the PBR Plan. The issue raised by CEC regarding removal of the $267 thousand Regionalization Initiative savings from earnings sharing is dealt with in Section 3.2 of this Decision.
2.3 Rate Schedule 46 O&M adjustment
The O&M costs to support Rate Schedule 46 customers include all incremental costs associated with the liquefaction of natural gas, the dispensing of LNG and the handling and loading of tankers to transport LNG at the Tilbury and Mt. Hayes LNG facilities. These costs are incremental to the regular O&M costs for operating the Tilbury and Mt. Hayes LNG facilities as peaking storage facilities. Specific costs include additional labour, materials, contractors, power and fuel.[47]
FEI forecasts an increase to Rate Schedule 46 O&M for 2015 of $1.309 million compared to 2014 approved amounts and an increase of $865 thousand compared to 2014 projected amounts. FEI states that the primary drivers of the increase are labour and power costs.[48] The 2015 forecast Rate Schedule 46 O&M of $1.415 million is based on an average supply of 3,040 GJ per day from the Tilbury LNG facility and an average supply of 60 GJ per day from the Mt. Hayes LNG facility.[49]
Per Appendix B of the Application, FEI forecasts 2015 Rate Schedule 46 revenue of $4.003 million, which is an increase of $638,000 from 2014 projected revenue. This equates to a 2015 forecast demand of 719,217 GJ compared to 2014 projected demand of 512,454 GJ.[50]
When asked in CEC IR 1.31.1 to explain why the forecast increase in Rate Schedule 46 O&M is substantially greater than the forecast increase in Rate Schedule 46 demand, FEI submits that in order to take a “conservative” approach to the demand forecast, FEI did not include spot purchases as part of the forecast revenue because spot purchases are not firm agreements. However, FEI submits that it did include forecast O&M costs related to serving these spot customers as part of the 2015 O&M forecast.[51]
Intervener submissions
CEC submits that not including spot purchases in the demand forecast is not acceptable because revenues and costs are not matched, and this may result in the revenue requirement being unjustifiably increased. CEC therefore submits that either O&M costs should be reduced to reflect the lower demand forecast, or the demand should be increased to reflect the increased need for O&M expenditures.
CEC quantifies each of its proposed options as follows:
(i) Reduce 2015 O&M by $624 thousand. This reduction is calculated by multiplying the 2015 forecast demand of 719,217 GJ by the 2014 projected per GJ O&M cost, which is calculated to be $1.10 per GJ.
(ii) Increase 2015 forecast demand by 500 thousand GJ. This increase is calculated based on applying the percentage increase in 2015 forecast O&M compared to 2014 projected O&M to the 2014 projected demand.[52]
Neither BCOAPO nor BCSEA commented on Rate Schedule 46 demand or O&M costs.
FEI reply
As noted in Section 2.1.5 of the Decision, FEI agrees with CEC that there should be an adjustment to O&M so that the forecast O&M is based on serving a load consistent with its demand forecast. However, FEI proposes a downwards adjustment to O&M of $480 thousand.
FEI submits that CEC’s suggested method of calculating the decrease to O&M, which uses the 2014 projected O&M on a per gigajoule basis, does not take into account that the majority of the increase in Rate Schedule 46 O&M is due to labour. FEI submits that labour does not “vary linearly” with each gigajoule of LNG. FEI therefore recommends using the embedded O&M per gigajoule rate of $1.30/GJ. This “embedded” O&M rate is calculated by dividing the 2015 forecast O&M of $1.415 million by the demand forecast provided in response to CEC IR 1.31.1 which includes spot purchases (i.e. 3,100 GJ/day * 365 days). This embedded rate of $1.30/GJ is then multiplied by the 2015 forecast demand (excluding spot purchases) of 719,217 GJ, resulting in a total 2015 forecast O&M of $935 thousand.[53]
Commission determination
The Panel approves FEI’s proposal to reduce Rate Schedule 46 O&M by $480 thousand, which results in a revised 2015 Rate Schedule 46 O&M forecast of $935 thousand. The Panel directs FEI to update its financial schedules for this adjustment as part of its compliance filing. Reducing the O&M forecast to exclude costs to serve spot purchase customers better aligns the Rate Schedule 46 forecast O&M with forecast demand. The Panel considered both CEC’s and FEI’s proposed reductions to O&M and finds FEI’s method of applying an embedded O&M rate to 2015 forecast demand to be reasonable given the potentially non-linear relationship between labour increases and per gigajoule demand.
2.4 Service Quality Indicators
FEI states:
…year-to-date September 2014 SQI results indicate that the Company’s overall performance is better than the benchmark and representative of a high level of service quality. For those SQIs with benchmarks, seven are performing better than the approved benchmarks with the remaining two performing better than the threshold and within the performance range as proposed in the Consensus Recommendation. For the four SQIs that are informational only, performance remains at a consistent level with prior years.[54]
While overall performance on Service Quality Indicators (SQIs) was positive, there was some discussion and recommendations concerning Transmission Reportable Incidents (TRI), Leaks per Kilometre (KM) of Distribution Mains, and Public Contact with Pipelines. In addition, there was a request to give consideration to future adoption of Greenhouse Gas (GHG) emissions as a new SQI.
Transmission Reportable Incidents
FEI states that the definition of TRI changed in late 2014 due to expanded reporting requirements by the BC Oil and Gas Commission (BCOGC). FEI states that the new requirements “now include 700 kilometres of what we call intermediate pressure pipelines.”[55] In addition, there are now four categories of severity where there used to be two categories.[56] As a result, the amount of pipeline subject to reporting has increased, while the threshold for reporting has been lowered.[57] Further, there is not a complete alignment between the new categories and any of the previous categories. Because the reporting criteria have changed going forward, comparisons with previous years may no longer be meaningful.[58]
FEI was asked to restate prior years’ data according to BCOGC’s new criteria so that it is comparable to the new reporting requirement. FEI did so, with the caveat that it is an estimate that’s based on its damage prevention manager’s best professional judgment. The restated results for 2012, 2013 and 2014 are 3, 11 and 4, respectively.[59]
BCSEA supports continuation of the TRI metric, but makes no comment on how the metric can be used to compare with previous years. No other interveners commented on this SQI issue.
Leaks per KM of Distribution System Mains
BCSEA supports the continuation of this metric, but recommends that the Commission direct FEI to provide the five-year rolling average in addition to the annual figure.[60] In response, FEI stated: “[i]f the Commission would find this information helpful, FEI does not oppose filing this information in its future Applications.”[61]
Public Contact with Pipelines
The Public Contact with Pipelines (PCP) SQI is a ratio of the number of line damages to the number of thousands of calls to the BC One Call service. BCSEA submits:
…it would be informative if FEI routinely reported both the numerator (number of line damages) and the denominator (thousands of BC One calls), for the current year and for historical years, on a single year and three-year average basis. This would allow participants in the review to identify whether there are any trends in the underlying measures that might warrant attention directly.[62]
FEI does not oppose filing this information in its future annual review applications.
Historical SQI Results
BCSEA suggests that SQI results for years prior to the PBR period also be included in the annual review filing as this would provide useful context.[63] FEI does not oppose filing this information in its future annual review applications.
GHG Emission Reporting
BCSEA “believe that ongoing consideration should be given to adoption in the future of a service quality indicator for GHG Emissions from Operational Activities as a component of the PBR framework” and submits that the Commission should direct FEI to include in its annual reviews, the Estimated Annual GHG Emissions (in tCO2e) reported by the Company to the Ministry of Environment.[64] FEI does not oppose filing this information in its future annual review applications.
Commission determination
The Panel agrees with BCSEA that a five-year rolling average of Leaks per KM of Distribution System Mains would be helpful information and directs FEI to provide this information in future annual reviews. The Panel also agrees that with regard to the SQI Public Contact with Pipelines, the number of line damages and the number of calls to BC One Call would be helpful and directs FEI to also provide this information in future annual reviews.
The Panel also agrees that historical results for SQIs would be useful to provide context to reported results going forward. The Panel considers that a period of five years prior to the PBR period is reasonable. Accordingly, FEI is directed to provide SQI results from 2009 onward for future annual reviews.
Regarding Transmission Reportable Incidents, the reporting change mandated by the BCOGC will limit the comparability of reported SQIs going forward. The Panel agrees that this limitation will diminish over time as data on past performance grows. However, given FEI provided an estimate of the previous results adjusted to the new criteria (i.e. IP incidents) and the Transmission Reportable Incidents SQI is an informational indicator, the Panel considers it appropriate to provide this SQI using the new BCOGC criteria. Further, reporting by level would provide more quality information than a cumulative summary of all the levels. Accordingly, for subsequent annual reviews, FEI is directed to report the number of Transmission Reportable Incidents in each of the severity levels.
The Panel is not persuaded that the case has been made for adoption of a GHG emissions SQI. If the need arises in the future, this issue can be revisited.
With regard to including the Estimated Annual GHG Emissions (in tCO2e) reported by the Company to the Ministry of Environment, the Panel has no objection, and directs FEI to provide this information in future annual reviews.
2.5 Reporting of exogenous savings
CEC submits that “stakeholders are not privy to sufficient information to adequately determine if there are savings that potentially qualify for exogenous treatment” and that “if there are exogenous savings that could approach the materiality threshold, it should be incumbent upon the utility to advise stakeholders of the possibility so that determinations can be made as to whether or not the materiality threshold is reached.”[65]
FEI replies that costs or savings that could approach the threshold are not relevant to exogenous factor treatment. In its view, it “should not have to consider hypothetical scenarios.”[66]
Commission determination
The Panel agrees with FEI that given the materiality threshold that has previously been set, only savings or costs that exceed the threshold are relevant. Accordingly, the Panel declines to direct FEI to identify any savings or costs other than those that meet the threshold criteria.
2.6 Proposed compliance filing updates
As part of its reply submission, FEI summarizes the adjustments/updates it has committed to make as part of its compliance filing subject to Commission approval. These adjustments are as follows:
(i) Update the I-Factor to reflect a 0.525 percent adjustment to Consumer Price Index (CPI) for the PST impact (as compared to the 0.530 percent adjustment used in the Application);
(ii) Update the 2015 forecast Biomethane O&M for the two projects that are delayed, which results in a $26 thousand reduction to Biomethane O&M;
(iii) Update to amortize the portion of the Biomethane Variance Account representing the application costs to be charged to all customers into the delivery cost of service in compliance with Order G-15-15;
(iv) Adjust the short-term interest rate forecast downwards from 1.75 percent to 1.0 percent to reflect a more current forecast;
(v) Update the long-term debt forecast to reflect the actual rate, timing and amounts;
(vi) Update the Allowance for Funds Used During Construction (AFUDC) rate calculation to reflect the above-mentioned changes to the debt rate.[67]
Both CEC and BCOAPO state in their final submissions that FEI should use the most up to date information available with regards to the short-term and long-term debt rates and specifically recommend that the long-term interest rate be adjusted.[68]
BCSEA makes no submissions on FEI’s proposed updates.
Commission determination
The Panel approves the updates and adjustments outlined in FEI’s Reply Submission and directs FEI to revise its financial schedules to incorporate these changes as part of its compliance filing. The updates properly reflect the commitments made by FEI in its IR responses and during the Annual Review Workshop.
3.0 DETERMINATIONS ON APPROVALS SOUGHT
3.1
Permanent delivery rates and treatment of
differences between
interim and permanent rates
FEI requests approval of a delivery rate increase of 2.03 percent for 2015 compared to the 2014 common delivery rates. The rate increase is equivalent to a revenue requirement increase, before earnings sharing, of $15.379 million. FEI proposes that the difference between 2015 interim rates and permanent rates, including the Earnings Sharing riders for Mainland customers, be collected from customers by way of a bill adjustment reflecting customers’ consumption from January 1, 2015.[69]
Commission determination
The requested permanent delivery rates for all non-bypass customers effective January 1, 2015, representing an increase of 2.03 percent compared to 2014 common delivery rates, are not approved as filed. Permanent delivery rates for all non-bypass customers effective January 1, 2015, as modified by the directives in this Decision, are approved.
The difference between the 2015 interim rates and permanent rates, including the Earnings Sharing rider for Mainland customers, is approved to be collected from/refunded to customers with interest at the average prime rate of FEI’s principal bank by way of a bill adjustment reflecting customers’ consumption from January 1, 2015.
FEI is directed to re-calculate 2015 delivery rates and file revised financial schedules with the Commission reflecting the changes outlined in the Decision by June 30, 2015.
3.2 Earnings sharing disbursements and process
FEI projects $3.341 million in earnings sharing for 2014 and proposes to distribute this amount to Mainland customers in 2015 via a rate rider. This amount is based on projected 2014 formula-driven O&M savings of $6.851 million and capital expenditures in excess of the formula by $4.095 million. These amounts are then subject to the 50/50 Earnings Sharing Mechanism, as approved by the Commission in the PBR Decision and further clarified in Order G-162-14.[70]
FEI proposes that the earnings sharing rate rider be effective for a twelve month period commencing January 1, 2015.[71] FEI states that use of a rate rider to distribute 2014 earnings sharing to customers is necessary because the 2014 earnings sharing only applies to the Mainland region since the amalgamation of FEVI and FEW into the PBR plan does not take effect until 2015. FEI further states that since the 2015 earnings sharing amount will be applicable to all customers, FEI will evaluate in its upcoming annual review filing the merits of continuing to utilize a rate rider or of switching to amortization of the earnings sharing deferral account to distribute future earnings sharing.[72]
Intervener submissions
BCSEA “generally supports” the distribution of 2014 earnings sharing to Mainland customers via a rate rider, while BCOAPO does not comment on the proposal.
CEC supports the use of the earnings sharing rider to disburse 2014 earnings sharing amounts to Mainland customers; however, CEC recommends that the amount be adjusted downwards to exclude $267 thousand of O&M savings related to the Regionalization Initiative. As discussed in Section 2.2 of the Decision, CEC does not consider the $267 thousand O&M savings to be justifiable savings because the savings are a result of a transfer of costs from FEI to FEVI and thus are cost neutral from an amalgamated perspective.[73]
CEC also takes issue with the deferral aspect of the earnings sharing mechanism and submits that an analysis of customer benefit lost to deferral should consider the cost to the customer of a one year deferral of the earnings sharing amount when considering a time value of money at ten percent, which results in a lost benefit of $332.5 thousand.[74]
FEI reply
FEI disagrees with CEC’s recommendation to adjust the earnings sharing downwards to remove the $267 thousand O&M savings. FEI submits that removing these O&M savings would be detrimental to customers because they would not benefit from any of the earnings sharing related to this item; instead, FEI’s shareholders would realize 100 percent of the benefit of these savings.
FEI disputes CEC’s calculation of lost benefits to customers from deferral of the earnings sharing and submits the following:
1. There is no “one year deferral” because the amount of savings relative to the formula is not known until the end of the year and does not exist until the year is complete. The earnings sharing amount is then paid out to customers throughout the following year.
2. CEC’s assumption of 10 percent for the time value of money is incorrect, as the earnings sharing deferral reduces rate base and thus attracts a return on FEI’s weighted average cost of capital of approximately 7 percent. Additionally, assuming the earnings sharing results in a credit balance, as it has for 2014 earnings sharing, a rate base return is advantageous for customers when compared to a debt only return.[75]
Commission determination
The Panel agrees with FEI that it would not be beneficial to ratepayers to remove the $267 thousand O&M savings from the 2014 earnings sharing calculation, as this would simply re-allocate savings from the ratepayers to FEI’s shareholder. Further, CEC’s proposal is contrary to the purpose of the 50/50 earnings sharing mechanism established in the PBR Decision, which determined that savings (or costs) resulting from actual O&M and capital expenditures being lower (or higher) than formula amounts be shared 50/50 between customers and FEI.
Regarding the earnings sharing mechanism and how these amounts are calculated and held prior to disbursement, these issues have already been established by the Commission in the PBR Decision and then further clarified in Order G-162-14. The Panel finds no evidence to suggest that this approved treatment of earnings sharing amounts is inequitable.
The Panel acknowledges that use of a rate rider to disburse 2014 earnings sharing amounts is necessary in order to stream the earnings sharing to Mainland customers only. The Panel expects that, as discussed by FEI in its responses to BCUC IRs, FEI will evaluate the options available for disbursement of future earnings sharing amounts as part of its upcoming Annual Review Application to be filed later in 2015.
Accordingly, the Panel approves the 2014 earnings sharing amount as projected by FEI in the Application and directs FEI to disburse the 2014 earnings sharing amount to Mainland customers via a rate rider effective for a twelve month period from January 1, 2015.
3.3 Deferral accounts
FEI seeks a number of approvals related to deferral accounts. These requests are addressed in the following sections.
3.3.1 New deferral accounts
FEI requests approval to establish three new rate base deferral accounts to address the costs of upcoming applications. These are as follows:
(i) 2016 Cost of Capital Application;
(ii) 2017 Rate Design Application;
(iii) 2017 Long Term Resource Plan (LTRP) Application.
FEI is not requesting an amortization period for any of the above three deferral accounts; instead FEI states that it will request an amortization period for each of the accounts in future annual review filings.[76]
In their Final Submissions, BCSEA and CEC support the establishment of all three application cost deferral accounts, while BCOAPO makes no comment.
Due to the issues identified in the proceeding related to the 2017 LTRP Application, the Panel will address this deferral account request in a separate section subsequent to the 2016 Cost of Capital Application and 2017 Rate Design Application deferral account requests.
2016 Cost of Capital Application deferral account
FEI was directed as part of Decision and Order G-75-13 related to the Generic Cost of Capital (GCOC) Stage 1 Proceeding to file an application no later than November 30, 2015 for the review of the common equity component and the Return on Equity (ROE) approved by Order G-75-13.[77]
FEI forecasts that it will incur approximately $500 thousand in application costs in 2015 related to Commission costs, Intervener Participant Assistance Cost Awards, expert/consultant costs, legal costs, and miscellaneous costs.[78]
FEI submits that it has retained an independent expert on cost of capital who will provide testimony related to topics such as ROE, business risk, capital structure, jurisdictional and industry analysis, and automatic adjustment mechanisms. FEI estimates that the expert will spend 100-150 hours on the application in 2015 for a forecast total cost of $70 thousand.[79]
When asked if FEI considered filing for approval of this deferral account at the time of filing the cost of capital application, FEI responded that its practice for general applications that are known and directed by a Commission Order is to seek, when possible, approval of deferral accounts at the earliest opportunity in order to provide transparency to the Commission and interveners. FEI further submits that its external auditors request evidence of the approval of deferral accounts, and since there will be costs incurred in 2015 for this application, FEI requires Commission approval prior to the 2015 year-end.[80]
2017 Rate Design Application deferral account
Pursuant to Directive 5 of Order G-21-14, the Commission directed FEI to file a comprehensive Rate Design Application on or before December 31, 2016. FEI states it will commence work on this application in 2015 in order to meet the filing deadline. FEI anticipates based on historical experience that the total deferred cost of the Rate Design Application will be in the range of $2.5 million to $3 million, with the largest proportion of the costs expected to be incurred in 2017 which is when the majority of the regulatory process is expected to occur.[81]
FEI forecasts that it will incur $250 thousand in Rate Design Application costs in 2015 related to consultant costs and stakeholder workshops.[82] FEI forecasts that 550 hours of consultant time will be expended on the application in 2015 and that this work is expected to commence late in the second quarter of the year.[83]
Commission determination
The Panel approves the establishment of the 2016 Cost of Capital Application deferral account and the 2017 Rate Design Application deferral account and approves a weighted average cost of capital to be earned on each of these two new deferral accounts. These applications have been directed by Commission Orders and it is reasonable that FEI will require external resources and incur associated costs in 2015.
The Panel notes that the recovery of these deferred costs, including the appropriate amortization period, will be addressed in future annual review filings.
3.3.1.1 2017 LTRP Application deferral account
FEI requests approval to create a rate base deferral account for costs associated with the preparation of the Long-Term Resource Plan to be filed in 2017.
FEI provides the following explanation for why this account is needed:
…in Order G-138-14 [FEI PBR Decision], the Commission directed FEI to reduce Base O&M by $0.600 million related to the LTRP on the basis that the next LTRP was not expected to filed for another 5 years, i.e. not until 2019. However, in Order G-189-14 [accepting the 2014 LTRP], the Commission directed FEI to submit its next LTRP by mid-2017 with specific work required to be included in the LTRP. It is not possible for FEI to complete the required work for the LTRP as directed by the Commission in Order G-189-14 without incurring the incremental expenditures that were denied by Order G-138-14.[84]
FEI further states:
The estimated amount that will be recorded in this deferral account in each year of the LTRP process is based on similar work conducted in completing the 2014 LTRP as well as additional work needed to comply with Commission directives and recommendations included in Order G‑189‑14 and related decision. FEI expects to incur $0.250 million in 2015 and a total of approximately $1.2 million on these activities up to the time of filing the 2017 LTRP.[85]
FEI was asked in BCUC IR 1.26.2 to provide details on the activities planned and resources required to prepare the 2017 LTRP and to provide a comparison of these activities and resources to the 2014 LTRP. FEI provided the following response:
FEI does not track the number of hours that all staff from across the company spend on LTRP related activity, whether they were for incremental requirements as a result of Commission directives or not. FEI outsourced substantial analyses, primarily related to end-use demand forecasting and long term energy efficiency and conservation planning for the 2014 LTRP; however, FEI has not yet determined how much of the work for the 2017 LTRP will be outsourced versus being undertaken by FEI employees. Thus FEI cannot state at this time what its staffing needs versus external consultant activity will be. [86]
FEI further describes the various elements that will comprise the anticipated LTRP, along with commentary on how these elements connect back to Order G-189-14.[87]
FEI submits that it “considers all activities related to the LTRP for which it is requesting deferral account treatment to be incremental activities related to Commission directives.”[88] FEI further submits that it considers a number of the incremental activities to be more complex than those conducted for the 2014 LTRP.[89]
As part of the FEU 2012-2013 RRA, FEI requested approval for incremental O&M spending of $1.2 million in 2012 and $1.5 million in 2013 to prepare the 2014 LTRP Application. The Commission in the 2012-2013 FEU RRA Decision did not accept that this level of incremental spending was necessary, and therefore approved incremental funding in the amounts of $400,000 in 2012 and $600,000 in 2013.[90] As FEI was operating under cost of service rate-making in 2012 and 2013, the $1 million approved LTRP spending was included as part of its approved O&M spending in the Energy Solutions & External Relations department. This differs from FEI’s proposed treatment for the 2017 LTRP spending in which the Company proposes to record all LTRP spending in the 2017 LTRP Application Cost deferral account.
Intervener submissions
CEC recommends the Commission approve the deferral account as proposed.[91]
BCOAPO takes no issue with FEI’s proposal for this deferral account.[92]
BCSEA submits that it is “satisfied that FEI’s intended spending on the LTRP in 2015 is reasonable and should be recoverable presuming it is prudently incurred.” BCSEA further submits that it sees the 2017 LTRP as an “important element of the Commission’s oversight of FEI’s long-term planning” and it accepts that it will take “significant resources for FEI to adequately address these topics.”[93]
Commission determination
The Panel agrees with FEI’s position that the directive contained in the FEU 2014 LTRP Decision to file the next LTRP in 2017 rather than in 2019, will precipitate additional costs within the PBR period that were not anticipated in the PBR Decision.
However, the Panel is not satisfied that FEI has provided adequate budget analysis in support of the planned LTRP preparation activities and expenditures. In the absence of information as to which of the many LTRP activities catalogued in FEI’s submissions do or do not attract incremental costs and in what amounts, it is not possible to arrive at a conclusion as to whether the expected costs appropriately qualify for treatment outside of Base O&M.
The Panel acknowledges that FEI has requested approval of a LTRP Application deferral account and has not requested approval of specific expenditures to be charged to this account. However, the Panel considers the proposed expenditures to be the primary issue, not the deferral account, and hence a full review and approval of these expenditures is warranted prior to considering the deferral account to which they will be charged. Therefore, the Panel rejects FEI’s request for approval of the 2017 LTRP Application deferral account at this time pending further review at the next annual review. The Panel directs FEI in its next annual review application to provide a more detailed budget and justification for its requested 2017 LTRP application costs.
To provide clarity as to what the Panel expects to see addressed in this subsequent filing of LTRP application cost information, the Panel provides the following guidance.
FEI has characterized its proposed set of LTRP activities as being a direct result of Commission directives and suggestions that came out of the 2014 LTRP Decision, and has quoted or referenced relevant parts of that decision to support its case. The Panel takes note of other parts of that same decision that FEI has not mentioned or referenced. Specifically, there are a number of comments that speak to the quality of FEI’s LTRP applications. In Section 2.5 of the 2014 LTRP Decision, dealing with the statutory adequacy of the 2014 LTRP, the Commission states: “Like the [2010 LTRP] Panel before us, we have directives respecting the quality of the plan.”[94] A number of subsequent parts of the same decision elaborate on the quality concerns, such as the section on the long range demand forecast which begins with: “As previously noted, whereas the Commission Panel accepts the LTRP as adequate from a statutory compliance perspective, we have identified concerns regarding the quality of… the annual demand forecast… the peak demand forecast… the integration between the two forecasts.”[95] Without tying the hands of future panels, the Panel is of the view that the Commission will be more easily persuaded to approve costs for activities that provide new insights/analysis (i.e. are “incremental”) than to approve costs for activities appearing to have more to do with meeting expected quality standards.
The Panel is also of the view that costs eligible for deferral account treatment are largely restricted to the use of external resources (i.e. as opposed to those aspects of the filing developed by internal staff). The Panel views the deduction of $0.600 million from Base O&M in the FEI PBR Decision as having removed allowances for incremental external resources that might be incurred in preparing an LTRP, but in no way reducing FEI’s internal resource capacity to carry out ongoing regulatory work, including the preparation from time to time of LTRP applications. Therefore, in the next filing that seeks deferral account treatment for various activities, it will be important to substantiate that the requested budgeted amounts are for work that would not typically be viewed as the responsibility of internal resources.
Accordingly, the Panel directs FEI to provide the following specific information in its upcoming annual review application:
• The total forecast spending for 2016 on preparation of the LTRP;
• A description of each key activity that FEI intends to undertake in developing the LTRP, and the reasons why these activities are deemed as “incremental” to Base O&M. For each key activity identified, provide the following:
o Budget amounts for 2016 and project totals, with comparisons to the 2014 LTRP amounts;
o Breakdowns of internal versus external resource budgets, including the estimated percentage of 2016 spending related to external consultants versus internal staff, with descriptions of the role(s) undertaken by each group, again with comparisons to 2014 experience;
o The number of hours forecast to be spent by external consultants on the LTRP in 2016 compared to the number of hours forecast to be spent by internal staff; and
• Whether FEI plans to hire additional permanent employees to perform LTRP-related work, including an estimated number of new employees to be hired for 2016.
3.3.2 Changes to existing deferral accounts
FEI requests approval to make changes to two of its rate base deferral accounts and one non-rate base deferral account. These deferral account changes are addressed in the following sections.
3.3.2.1 BFI Costs and Recoveries deferral account
In accordance with Orders C-6-12 and G-150-12, FEI has two rate base deferral accounts in place to capture incremental CNG service recoveries received from BFI for actual volumes purchased in excess of minimum take or pay commitments.[96]
FEI requests approval to discontinue and dispose of one of these deferral accounts – the BFI Costs and Recoveries Account – All Other Recoveries deferral account, effective December 31, 2015. FEI proposes to transfer the balance in this deferral account, which is forecast to be a credit of $55 thousand at the end of 2015, to the existing CNG and LNG Recoveries deferral account. FEI submits that this treatment is appropriate because pursuant to Order G-111-14, BFI is now part of the natural gas class of service; therefore these recoveries from BFI should be returned to all natural gas customers.,[97]
None of the interveners opposed FEI’s request.
Commission determination
The Panel approves the transfer of the balance in the BFI Costs and Recoveries Account – All Other Recoveries deferral account to the CNG and LNG Recoveries deferral account, effective December 31, 2015. The Panel further approves the disposition and discontinuance of the BFI Costs and Recoveries Account – All Other Recoveries deferral account, effective December 31, 2015.
In consideration of the fact that BFI is now part of the natural gas class of service, as directed by Order G-111-14, it is reasonable for these recoveries to be recorded in the CNG and LNG Recoveries deferral account and returned to all natural gas customers.
3.3.2.2 FEW Revenue Surplus/Deficiency deferral account
Pursuant to Order G-222-13, FEW was approved to capture the actual 2014 revenue surplus or deficiency in a deferral account, subject to the examination of the 2014 actual results and the determination on cost recovery in the next revenue requirements proceeding. Pursuant to Order G-74-14, FEW also received approval to capture the difference for 2013 and 2014 between the approved equity structures for both years compared to the revised approved equity structures under the GCOC 2012 Stage 2 Proceeding.[98]
FEI forecasts a surplus of $79 thousand as of December 31, 2014, in the FEW Revenue Surplus/Deficiency deferral account and requests approval to amortize this balance into rates for all natural gas customers over one year in 2015. FEI further proposes that any difference between the actual and projected ending 2014 balance will be amortized into rates in 2016 and that the deferral account will then be discontinued effective January 1, 2017.[99]
None of the interveners opposed FEI’s request.
Commission determination
The Panel approves the amortization of the balance in the FEW 2014 Revenue Surplus/Deficiency deferral account into rates for all natural gas customers in 2015. The Panel further approves any remaining balance at the end of 2015 in this deferral account to be amortized into rates in 2016. The Panel directs FEI to discontinue the FEW 2014 Revenue Surplus/Deficiency deferral account effective January 1, 2017. This proposed treatment is reasonable given the size and nature of the deferred balance.
3.3.2.3 EEC Incentives for AES/TES deferral account
FEI requests approval to discontinue the EEC Incentives for AES/TES non rate base deferral account and to transfer the 2014 ending balance in this account to the rate base EEC deferral account, effective January 1, 2015.
As part of the FEU 2012-2013 RRA Decision, the Commission directed FEI to hold all EEC incentives that are provided for AES or TES technologies for projects in which Fortis companies are a participant in a separate deferral account. The Commission further directed that the recovery of this deferral account would be dealt with in the next revenue requirements application. However, in the 2014 PBR Application, FEI proposed to continue the use of the deferral account and to delay the determination on its disposition until the first PBR annual review. By that time, FEI anticipated that it or FortisBC Alternative Energy Services Inc. (FAES) would have filed the Thermal Energy Services Deferral Account (TESDA) Disposition Report and that the Transfer Pricing/Code of Conduct (TPP/CoC) review would be complete.
FEI now submits that it does not believe that another process will determine the disposition of the EEC Incentives for AES/TES deferral account and that this issue should be dealt with in the current proceeding, particularly in light of the fact that the TPP/CoC Decision did not specifically address this topic and that the TESDA has now been transferred to FAES.
The balance in the EEC Incentives for AES/TES deferral account at the end of 2014 is $248 thousand before tax ($185 thousand after tax). The balance is made up of EEC incentives provided to the following three FAES projects: Delta School District, Glen Valley, and Helen Gorman.[100]
FEI provides the following justification for transferring the balance to the rate base EEC deferral account as opposed to transferring the balance to FAES’ TESDA:
1. The balance consists of FEI’s expenditures on demand-side measures made in accordance with an expenditure schedule accepted by the Commission under section 44.2(1)(a) of the UCA; therefore, FEI has a right to a reasonable opportunity to recover this balance in FEI’s rates.
2. Transferring the balance to the TESDA would be unfair to FAES customers and contrary to the intent of providing the incentive to adopt energy efficient technology because the FAES customers would then have to pay back the incentives through amortization of the TESDA into FAES’ customer rates.
3. Since FAES did not make the EEC expenditure, FAES would be recovering amounts that it never expended.[101]
None of the interveners opposed FEI’s request.
Commission determination
The Panel approves the transfer of the ending balance in the EEC Incentives for AES/TES deferral account to the rate base EEC deferral account and approves the discontinuation of the EEC Incentives for AES/TES deferral account, effective January 1, 2015. The Panel further grants approval for FEI to capture any future EEC incentives related to AES customers within the existing approved EEC funding envelope.
FEI’s rationale for recovering the EEC incentives related to AES/TES customers from FEI customers is reasonable given that FEI incurred the expenditures. The Panel also agrees that recovering the incentives from FAES customers through the TESDA would be contrary to the intent of providing the incentive.
4.0 ANNUAL REVIEWS
As noted earlier, the Commission in the FEI PBR Decision found that a more extensive annual review process is necessary to build trust among all stakeholders and to ensure the PBR Plan functions as intended.
By letter dated March 10, 2015, issued subsequent to the FEI 2015 Annual Review Workshop, the Commission invited all registered parties for the FEI Annual Review proceeding to provide comments in their final and reply submissions on the scope and level of informational detail required for future annual review applications, and on the parties’ views on the optimum review process for future annual reviews.
4.1 Preparation of future applications and reporting on efficiency initiatives
A key topic explored in this proceeding is how savings during PBR are achieved, whether these savings will be sustainable, and how the initiatives implemented by FEI during the PBR term to achieve savings and other benefits should be used to evaluate the performance of FEI under the PBR Plan.
When asked what criteria FEI will use to evaluate the operation of the PBR Plan, FEI stated that the effectiveness of the PBR Plan over the plan’s term can be evaluated using the following criteria:
(i) Cost efficiencies realized;
(ii) Regulatory efficiency; and
(iii) Maintaining service quality.
FEI also stated that because the PBR Decision was not issued until September 15, 2014 and the PBR Plan is designed to provide a longer term framework, it is too early at this stage to be evaluating the effectiveness of the approved PBR Plan.[102]
FEI’s projected 2014 O&M expenses (excluding items forecast outside the PBR formula) are $6.851 million lower than formula amounts but the projected 2014 capital expenditures (excluding items forecast outside the PBR formula) are $4.095 million higher than formula amounts. This results in $3.341 million in earnings sharing for 2014 to be disbursed to Mainland customers.[103]
As noted earlier in this Decision, much of the savings in 2014 have been described by FEI as associated with labour, reflecting a broad-based, Company-wide effort to seek alternate solutions to the filling of vacancies.
In response to BCUC IR 1.1.1, FEI states that the total number of Full Time Equivalent Employees (FTEs) declined by 60 for 2014, which reduced the number of FTEs from 1,570 at the end of 2013 to 1,510 at the end of 2014. When including FEVI’s 113 FTEs and FEW’s 1 FTE, the FEI Amalgamated FTEs for 2014 are 1,624.[104]
FEI states that its Regionalization Initiative, which was implemented in 2014, contributed to the 2014 O&M savings but was not able to quantify the amount of savings attributable to this initiative. FEI submits it is difficult to separate regionalization savings from the broader initiatives of improving customer service, enhancing productivity focus and strengthening the accountability culture. The overall operations O&M savings related to all of these broader initiatives are approximately $1 million in 2014.[105]
FEI provided the following information on the Regionalization Initiative in response to BCUC IR 1.2.9 for each year of the PBR term:[106]
FEI states that with the PBR Decision now in place it has the regulatory certainty it requires to implement more large scale customer service and productivity-related initiatives, such as Project Blue Pencil. FEI describes Project Blue Pencil as an initiative focused on reviewing and streamlining several high volume customer-facing processes from the perspective of the customer, such as in the areas of new service connections, meter exchange, collections and high bill inquiry.[107]
FEI was asked in BCUC IR 1.3.3 to provide the same information on Project Blue Pencil as was requested for the Regionalization Initiative. FEI provided the following table:
FEI stated in response to CEC IR 1.12.4:
The productivity improvements and related savings for Project Blue Pencil (refer to the response to BCUC IR 1.3.3) and for the Regionalization initiative (refer to the response to BCUC IR 1.2.9) are expected to extend into future years, but circumstances may change before the end of the PBR period and it is possible that these savings may be offset in future years by cost pressures.[108]
Intervener submissions
As noted in Section 1.5 of this Decision, CEC submits that the PBR should include evaluation against the retention of beneficial activities and potentially the development of new beneficial programs and services. CEC recommends that an additional criterion be considered when evaluating the effectiveness of the PBR Plan – cost effectiveness of efficiencies realized.[109]
CEC is concerned that FEI has been able to reduce 60 FTEs in 2014 without impacting the benefits that those positions would normally have provided. CEC submits that “if there were effectively 60 excess positions in the budget in 2014 going into PBR, then the base was either incorrectly established, or the customer has received a significant loss of benefits.”[110]
CEC further submits that “the information available through the current Annual Review process is inadequate to evaluate PBR and identify issues with PBR, or to resolve them.”[111]
FEI reply
FEI submits that if it is able to meet the challenge set by the PBR Plan and maintain savings compared to the formula amounts over the course of the PBR term, and at the same time maintain the safety and reliability of service to customers, this will be indicative of the ultimate success of the PBR.
FEI makes the following counter-points to CEC’s submissions regarding how the PBR should be evaluated:
(i) CEC’s proposed evaluation criterion is contrary to the basic concept of PBR, in which a utility is free to manage its costs within the formula amounts of the PBR Plan;
(ii) Attempting to assess the cost effectiveness of efficiencies realized would mire the annual review process in a confusing and ambiguous assessment of FEI’s actions in any given year because it is unclear what would count as a “beneficial activity” or how cost efficiency could be weighed against potential lost benefits;
(iii) Efficiency initiatives undertaken by FEI during the PBR are also part of the prudent management of the utility and it would not be possible to demonstrate whether any particular activity was the “direct result of performance based ratemaking”;
(iv) CEC is implicitly seeking to compare what would have been achieved under cost of service to what is achieved under PBR.[112]
In FEI’s view, the format and content of the Application was sufficient for the purpose of the annual review and no material changes are required. However, based on IRs which arose during the annual review proceeding, FEI proposes to include the following additional information in its next annual review application:
(i) A description of the demand forecast methodology consistent with the detail provided in response to IRs in the proceeding;
(ii) Information on the cost and savings of major productivity initiatives in a format similar to that requested by the Commission with respect to Project Blue Pencil and the Regionalization Initiative.[113]
Commission determination
FEI has identified what it views as the appropriate three criteria with which to evaluate the effectiveness of the PBR Plan over the six-year term – cost efficiencies realized, regulatory efficiency, and maintaining service quality. The Panel agrees that these three criteria are important measures; however, we also acknowledge CEC’s concerns over how the efficiencies are achieved and its recommendation for a fourth evaluation criterion to be considered which CEC characterizes as “cost effectiveness of efficiencies realized.”
As noted in Section 1.5 of this Decision, the Panel considers the PBR to be at a very early stage and it is premature to evaluate its success or failure. However, it is not too early to consider the criteria upon which a future evaluation will be based. The Panel has considered FEI’s arguments against CEC’s additional criterion and agrees that imposing such requirements could be unnecessarily onerous and could lead to “micro-managing” of the Company’s business. Accordingly, the Panel rejects CEC’s recommendation to include “cost effectiveness of efficiencies realized” as a required criterion for measuring the success of the PBR Plan.
Nonetheless, the Panel considers it essential during the PBR term for certain information to be gathered on efficiency initiatives, particularly with regards to how these initiatives impact the organizational structure of the Company and the expected savings and/or costs which result from these efficiency initiatives. The purpose of obtaining this information is not for the Commission or interveners to challenge FEI on the appropriateness of the initiatives being undertaken, as this could be viewed as attempting to manage the Company’s business. Instead, the purpose is to gain an understanding of how savings are being achieved and to acquire some quantifiable data on these savings and initiatives throughout the PBR term.
Therefore, the Panel directs FEI to continue to provide in each annual review application the information that was provided in response to BCUC IRs 1.2.9 (Regionalization Initiative) and 1.3.3 (Project Blue Pencil) and to update these tables for actual results as this data becomes available. The same analysis is to be performed on new initiatives that are implemented during the PBR term.
The Panel notes that in response to BCUC IR 1.2.1, FEI was not able to distinguish between savings related to the Regionalization Initiative and savings attributable to its “broader initiatives.” As a result, FEI did not separately quantify labour and non-labour savings in the table provided in response to BCUC IR 1.2.9. The Panel does not consider this acceptable and notes that FEI was clearly able to quantify a portion of the Regionalization Initiative savings as evidenced by the $267 thousand in labour costs transferred from FEI to FEVI as a result of regionalization of the dispatch group. The Panel directs FEI to update the table provided in response to BCUC IR 1.2.9 as part of its compliance filing with its best estimate of labour and non-labour savings specifically attributable to the Regionalization Initiative. The Panel expects that FEI will provide this level of detail, as it has done for Project Blue Pencil, on all the future initiatives it reports on.
In light of the concerns raised by CEC over labour reductions, the Panel directs FEI to include in its annual review filings both the total year-end number of employees and the total year-end number of Full Time Equivalent Employees.
4.2 Future annual review process
The Annual Review of 2015 Delivery Rates was conducted under the following regulatory framework:
• Intervener and Interested Party Registration;
• Commission and Intervener Information Requests No. 1;
• FEI Response to Commission and Intervener Information Request No. 1;
• Workshop;
• FEI Response to Undertakings from Workshop;
• Intervener Written Submissions;
• FEI Written Reply Submissions.[114]
FEI submits that “the process utilized in the current proceeding, with one round of IRs and a workshop, is appropriate and should continue.” It views the workshop, with the Panel in attendance and a transcript of proceedings entered in evidence, as an effective substitute for a second round of IRs. Further, it considers this format preferable to a more formal Streamlined Review Process (SRP).[115]
Intervener submissions
With regard to whether a second round of IRs is needed, CEC, BCSEA and BCOAPO submit that one round of IRs may be sufficient, but the Commission should not preclude the possibility of a second round if deemed useful. The interveners further submit that final determination should be on a case by case basis. All interveners support a workshop as part of the process and are supportive of the workshop following the first round of IRs. CEC suggests that a brief oral hearing should precede the workshop where the parties could identify issues and concerns to be covered within the workshop.
CEC also suggests that there may be a need for more than one workshop and it would be useful to insert a step prior to holding a workshop in which all parties work together to develop the workshop. CEC further submits that “interactive two-way communication workshops would be useful for examining identified items and working on solutions to those problems.”[116]
BCOAPO suggests that in the event that the first round of IRs plus the workshop have not adequately addressed all issues in the proceeding, it may be preferred to add a second workshop rather than a second round of IRs.[117]
With regard to whether an SRP would be a more appropriate format than the Company-led workshop which took place in the current proceeding, the interveners submit the following:
• BCOAPO does not support an SRP process for the annual review;[118]
• CEC suggests that the workshops should follow a format that is similar to an SRP such that all parties have an opportunity to make their respective points of view and ask questions of all other participants. CEC makes no submissions as to how these workshops would be facilitated.[119]
• BCSEA comments that an SRP-type process led by a Commission panel is a more conventional Commission process than a Company-led workshop with the Commission panel attending as participants. BCSEA submits that with the Commission panel in attendance in this proceeding’s workshop, the dynamic of the Company-led workshop was not dissimilar to that of an SRP and the panel should continue to participate in the workshops.[120]
FEI Reply
FEI states it is generally in agreement with BCOAPO and BCSEA with respect to the review process and supports continuance of the process utilized in the current proceeding. FEI submits that holding a workshop has a number of advantages over a second round of IRs, pointing out that one benefit is the opportunity for face-to-face discussion where “questions are posed and answered in real-time” with more technical questions handled through an undertaking. FEI considers a formal SRP process to be unnecessary and notes that with the workshop being on the record all the benefits of an SRP are captured.
Concerning CEC’s submissions on two-way communication, FEI points out that it cannot generate such communication on its own and it was prepared with its presentation and could have answered questions if asked. FEI states that for future workshops it would be pleased to have an open question period following its presentation but it does not support holding more than a single workshop.[121]
Commission determination
The Panel shares the view held by most parties that the process used in the current proceeding is an appropriate general framework for future annual reviews. While we understand CEC’s concerns with precluding the possibility of additional steps to determine agenda items and ensuring a fulsome record in a given year, we are also mindful that one of the underlying principles of the PBR regime is regulatory efficiency.
Hence, the Panel sets out the following guidelines as the default template for future annual reviews.
• Intervener and Interested Party Registration;
• Commission and Intervener Information Requests No. 1;
• FEI Response to Commission and Intervener Information Request No. 1;
• A workshop which includes Commission panel participation. The format of the workshop, including who facilitates it, will be determined at each annual review proceeding;
• FEI Response to Undertakings from Workshop;
• Intervener Written Submissions; and
• FEI Written Reply Submissions.
In the event further process is required we agree with the parties that it is best dealt with on a case by case basis as the need occurs.
5.0 Summary of Directives
This Summary is provided for the convenience of readers. In the event of any difference between the Directions in this Summary and those in the body of the Decision, the wording in the Decision shall prevail.
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Directive |
Page |
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1. |
The Panel rejects FEI’s forecast residential average UPC of 81.5 GJ for 2015. |
8 |
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2. |
The Panel directs FEI to adjust its 2015 residential UPC forecast to 83.1 GJ as part of its compliance filing. |
8 |
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3. |
The Panel directs FEI to review alternative methodologies and develop one that overcomes the identified shortcomings and more accurately predicts actual average UPC for the next annual review. |
8 |
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4. |
The Panel approves FEI’s commercial UPC forecasts as filed. |
9 |
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5. |
The Panel directs FEI to include commercial customers as part of its review of alternative methodologies for forecasting UPC for the next annual review. |
9 |
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6. |
The Panel approves FEI’s 2015 forecast for residential net customer additions and accepts the use of CBOC housing starts as a proxy for these additions. |
10 |
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7. |
The Panel also approves FEI’s 2015 forecast for commercial net customer additions, as the 2015 forecast is in keeping with the recent actual customer additions and none of the interveners have taken issue with this forecast. |
10 |
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8. |
The Panel directs FEI to consider alternative methods for forecasting commercial customer additions which are appropriately sensitive to the business cycle. FEI is to provide an analysis of these alternatives in its next annual review application. |
10 |
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9. |
The Panel approves the FEI 2015 industrial demand forecast as filed. |
12 |
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10. |
The Panel approves the NGT and LNG demand forecasts as filed. |
13 |
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11. |
In future annual reviews, FEI is directed to address the issue of spot purchases more fully and provide a proposal for including some or all of these purchases in the demand forecast based on an analysis of the probability of various outcomes. |
13 |
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12. |
The Panel also directs FEI to include information that in this proceeding was obtained through staff and intervener information requests as well as the analyses of alternative forecasting methodologies directed in this Decision. This information is to include: • Historical forecast and actual data broken down by customer classes and service areas, as well as consolidated totals[122]; • The results along with an explanation of various aspects of the Industrial Survey used by FEI to forecast industrial demand;[123] • As directed in Sections 2.1.2 and 2.1.3 of this Decision, a fulsome description of alternatives to existing forecast methodologies with recommendations to improve residential and commercial UPC forecasts and commercial net customer additions forecasts; and As directed in Section 2.1.5 of this Decision, a proposal for including some or all of the spot purchases in FEI’s future demand forecasts. The Panel directs FEI to include the most recent ten years of historical actual data where possible. |
14 |
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13. |
The Panel approves FEI’s proposal to reduce Rate Schedule 46 O&M by $480 thousand, which results in a revised 2015 Rate Schedule 46 O&M forecast of $935 thousand. The Panel directs FEI to update its financial schedules for this adjustment as part of its compliance filing. |
17 |
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14. |
The Panel agrees with BCSEA that a five-year rolling average of Leaks per KM of Distribution System Mains would be helpful information and directs FEI to provide this information in future annual reviews. The Panel also agrees that with regard to the SQI Public Contact with Pipelines, the number of line damages and the number of calls to BC One Call would be helpful and directs FEI to also provide this information in future annual reviews. |
19 |
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15. |
FEI is directed to provide SQI results from 2009 onward for future annual reviews. |
19 |
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16. |
For subsequent annual reviews, FEI is directed to report the number of Transmission Reportable Incidents in each of the severity levels. |
19 |
|
17. |
With regard to including the Estimated Annual GHG Emissions (in tCO2e) reported by the Company to the Ministry of Environment, the Panel has no objection, and directs FEI to provide this information in future annual reviews. |
19 |
|
18. |
The Panel approves the updates and adjustments outlined in FEI’s Reply Submission and directs FEI to revise its financial schedules to incorporate these changes as part of its compliance filing. |
20 |
|
19. |
The requested permanent delivery rates for all non-bypass customers effective January 1, 2015, representing an increase of 2.03 percent compared to 2014 common delivery rates, are not approved as filed. Permanent delivery rates for all non-bypass customers effective January 1, 2015, as modified by the directives in this Decision, are approved.
The difference between the 2015 interim rates and permanent rates, including the Earnings Sharing rider for Mainland customers, is approved to be collected from/refunded to customers with interest at the average prime rate of FEI’s principal bank by way of a bill adjustment reflecting customers’ consumption from January 1, 2015.
FEI is directed to re-calculate 2015 delivery rates and file revised financial schedules with the Commission reflecting the changes outlined in the Decision by June 30, 2015. |
21 |
|
20. |
The Panel approves the 2014 earnings sharing amount as projected by FEI in the Application and directs FEI to disburse the 2014 earnings sharing amount to Mainland customers via a rate rider effective for a twelve month period from January 1, 2015. |
23 |
|
21. |
The Panel approves the establishment of the 2016 Cost of Capital Application deferral account and the 2017 Rate Design Application deferral account and approves a weighted average cost of capital to be earned on each of these two new deferral accounts. |
24 |
|
22. |
The Panel rejects FEI’s request for approval of the 2017 LTRP Application deferral account at this time pending further review at the next annual review. The Panel directs FEI in its next annual review application to provide a more detailed budget and justification for its requested 2017 LTRP application costs. |
26 |
|
23. |
The Panel directs FEI to provide the following specific information in its upcoming annual review application: • The total forecast spending for 2016 on preparation of the LTRP; • A description of each key activity that FEI intends to undertake in developing the LTRP, and the reasons why these activities are deemed as “incremental” to Base O&M. For each key activity identified, provide the following: o Budget amounts for 2016 and project totals, with comparisons to the 2014 LTRP amounts; o Breakdowns of internal versus external resource budgets, including the estimated percentage of 2016 spending related to external consultants versus internal staff, with descriptions of the role(s) undertaken by each group, again with comparisons to 2014 experience; o The number of hours forecast to be spent by external consultants on the LTRP in 2016 compared to the number of hours forecast to be spent by internal staff; and • Whether FEI plans to hire additional permanent employees to perform LTRP-related work, including an estimated number of new employees to be hired for 2016. |
27/28 |
|
24. |
The Panel approves the transfer of the balance in the BFI Costs and Recoveries Account – All Other Recoveries deferral account to the CNG and LNG Recoveries deferral account, effective December 31, 2015. The Panel further approves the disposition and discontinuance of the BFI Costs and Recoveries Account – All Other Recoveries deferral account, effective December 31, 2015. |
28 |
|
25. |
The Panel approves the amortization of the balance in the FEW 2014 Revenue Surplus/Deficiency deferral account into rates for all natural gas customers in 2015. The Panel further approves any remaining balance at the end of 2015 in this deferral account to be amortized into rates in 2016. The Panel directs FEI to discontinue the FEW 2014 Revenue Surplus/Deficiency deferral account effective January 1, 2017. |
29 |
|
26. |
The Panel approves the transfer of the ending balance in the EEC Incentives for AES/TES deferral account to the rate base EEC deferral account and approves the discontinuation of the EEC Incentives for AES/TES deferral account, effective January 1, 2015. The Panel further grants approval for FEI to capture any future EEC incentives related to AES customers within the existing approved EEC funding envelope. |
30 |
|
27. |
The Panel rejects CEC’s recommendation to include “cost effectiveness of efficiencies realized” as a required criterion for measuring the success of the PBR Plan. |
34 |
|
28. |
The Panel directs FEI to continue to provide in each annual review application the information that was provided in response to BCUC IRs 1.2.9 (Regionalization Initiative) and 1.3.3 (Project Blue Pencil) and to update these tables for actual results as this data becomes available. The same analysis is to be performed on new initiatives that are implemented during the PBR term. |
34 |
|
29. |
The Panel directs FEI to update the table provided in response to BCUC IR 1.2.9 as part of its compliance filing with its best estimate of labour and non-labour savings specifically attributable to the Regionalization Initiative. |
35 |
|
30. |
In light of the concerns raised by CEC over labour reductions, the Panel directs FEI to include in its annual review filings both the total year-end number of employees and the total year-end number of Full Time Equivalent Employees. |
35 |
Dated at the City of Vancouver, in the Province of British Columbia, this 27th day of May, 2015.
Original signed by:
____________________________
D. A. Cote
Commissioner
Original signed by:
____________________________
D. M. Morton
Commissioner
Original signed by:
____________________________
H. G. Harowitz
Commissioner
IN THE MATTER OF
the Utilities Commission Act, R.S.B.C. 1996, Chapter 473
and
FortisBC Energy Inc.
Application for Approval of 2015 Delivery Rates
pursuant to the Multi-Year Performance Based Ratemaking Plan
approved for 2014 through 2019 by Order G-138-14
BEFORE: D. A. Cote, Commissioner
D. M. Morton, Commissioner May 27, 2015
H. G. Harowitz, Commissioner
O R D E R
WHEREAS:
A. On September 15, 2014, the British Columbia Utilities Commission (Commission) issued its Decision and Order G-138-14 for FortisBC Energy Inc. (FEI) approving a Multi-Year Performance Based Ratemaking (PBR) Plan for 2014 through 2019. In accordance with the PBR decision, FEI is to conduct an annual review process to set delivery rates for each year;
B. On November 13, 2014, the Commission issued Order G-178-14 approving, among other things, FEI’s 2015 delivery rates on an interim and refundable basis, pending the outcome of the annual review of 2015 delivery rates;
C. On January 14, 2015, FEI submitted an application for the Annual Review of 2015 Delivery Rates (Application);
D. Pursuant to Order G-6-15 issued on January 22, 2015, the Commission established the Regulatory Timetable for review of the Application which provided for one round of information requests, a workshop to review FEI’s 2014 performance results and the 2015 revenue requirements, a response by FEI to undertakings arising from information requested at the workshop, and written final and reply submissions;
E. FEI filed an evidentiary update to the Application on January 29, 2015;
F. The Annual Review Workshop was held on March 6, 2015;
G. The following interveners filed Final Submissions on March 27, 2015:
• British Columbia Old Age Pensioners’ Organization, et al;
• Commercial Energy Consumers Association of British Columbia; and
• BC Sustainable Energy Association and the Sierra Club of British Columbia;
H. FEI filed its Reply Submission on April 9, 2015;
I. The Commission considered the Application, evidence and submissions of the parties as set forth and discussed in the Decision issued concurrently with this Order.
NOW THEREFORE pursuant to sections 59 to 61 of the Utilities Commission Act, for the reasons set out in the Decision, the British Columbia Utilities Commission orders as follows:
1. FortisBC Energy Inc.’s requested permanent delivery rates for all non-bypass customers effective January 1, 2015, representing an increase of 2.03 percent compared to 2014 common delivery rates, are not approved as filed. Permanent delivery rates for all non-bypass customers effective January 1, 2015, as modified by the directives in the Decision, are approved.
2. FortisBC Energy Inc. is directed to re-calculate 2015 delivery rates and file revised financial schedules with the Commission reflecting the changes outlined in the Decision by June 30, 2015.
3. FortisBC Energy Inc. is directed to collect from/refund to customers the difference between the 2015 interim rates and permanent rates, including the Earnings Sharing rider for Mainland customers, with interest at the average prime rate of the Company’s principal bank, by way of a bill adjustment reflecting customers’ consumption from January 1, 2015.
4. FortisBC Energy Inc. must comply with all determinations and directives as set out in the Decision.
DATED at the City of Vancouver, in the Province of British Columbia, this 27th day of May 2015.
BY ORDER
Original signed by:
D. A. Cote
Commissioner
Attachment
List of Acronyms
|
2017 LTRP Application |
2017 Long Term Resource Plan Application |
|
AES/TES |
Alternative Energy Services/Thermal Energy Services |
|
AFUDC |
Allowance for Funds Used During Construction |
|
Application |
Annual Review Application |
|
BCOAPO |
British Columbia Pensioners’ and Seniors’ Organization, et al. |
|
BCOGC |
BC Oil and Gas Commission |
|
BCSEA |
BC Sustainable Energy Association and the Sierra Club of British Columbia |
|
CBOC |
Conference Board of Canada |
|
CEC |
Commercial Energy Consumers of British Columbia |
|
CNG |
Compressed Natural Gas |
|
CPI |
Consumer Price Index |
|
Commission |
British Columbia Utilities Commission |
|
COPE |
Canadian Office and Professional Employees Union, Local 378 |
|
EEC |
Energy Efficiency and Conservation |
|
FAES |
FortisBC Alternative Energy Services Inc. |
|
FEI, the Company |
FortisBC Energy Inc. |
|
FEU |
FortisBC Energy Utilities Inc. (FEI, FEVI, FEW) |
|
FEVI |
FortisBC Energy (Vancouver Island) Inc. |
|
FEW |
FortisBC Energy (Whistler) Inc. |
|
FTEs |
Full Time Equivalent Employees |
|
GCOC |
Generic Cost of Capital |
|
GHG |
Greenhouse Gas |
|
GJ |
gigajoule |
|
IRs |
Information Requests |
|
KM |
Kilometre |
|
LNG |
Liquefied Natural Gas |
|
NGT |
Natural Gas for Transportation |
|
O&M |
Operating and Maintenance |
|
PBR Plan |
Performance Based Ratemaking Plan |
|
PCP |
Public Contact with Pipelines |
|
PJs |
petajoules |
|
PST |
Provincial sales tax |
|
ROE |
Return on Equity |
|
RRA |
Revenue Requirements Application |
|
RSAM |
Rate Stabilization Adjustment Mechanism |
|
SQI |
Service Quality Indicator |
|
SRP |
Streamlined Review Process |
|
STIP |
Short Term Incentive Plan |
|
TES |
Thermal Energy Services |
|
TESDA |
Thermal Energy Services Deferral Account |
|
TJ |
terajoules |
|
TPP/CoC |
Transfer Pricing/Code of Conduct |
|
TRI |
Transmission Reportable Incidents |
|
UCA |
Utilities Commission Act |
|
UPC |
use per customer |
IN THE MATTER OF
the Utilities Commission Act, R.S.B.C. 1996, Chapter 473
and
FortisBC Energy Inc.
Application for Approval of 2015 Delivery Rates
pursuant to the Multi-Year Performance Based Ratemaking Plan
approved for 2014 through 2019 by Order G-138-14
EXHIBIT LIST
Exhibit No. Description
Commission Documents
|
A-1 |
Letter Dated January 22, 2015 – Order G-6-15 Establishing the Regulatory Timetable |
|
A-2 |
Letter Dated January 23, 2015 – Appointment of Commission Panel |
|
A-3 |
Letter Dated February 10, 2015 – Commission Information Request No. 1 to FEI |
|
A-4 |
Letter Dated February 13, 2015 – Panel Attendance at Workshop |
|
A-5 |
Letter Dated February 13, 2015 – Late Intervener Status COPE |
|
A-6 |
Letter Dated March 10, 2015 – Request for Comments on Process for Future Annual Reviews |
|
|
|
|
A2-1 |
Letter Dated February 10, 2015 – Commission Staff Submitting Excerpt from FortisBC Energy Inc. (FEI) Application for Approval of Rates and Contract for Compressed Natural Gas (CNG) Fueling Services from the CNG Fueling Station, Located at FEI’s Victoria Regional Office Facility in Langford, for Evergreen Industries Ltd. |
Applicant Documents
|
B-1 |
FortisBC Energy Inc. (fei) Letter Dated January 14, 2015 – Application for Approval of 2015 Delivery Rates pursuant to the Multi-Year Performance Based Ratemaking Plan approved for 2014 through 2019 by Order G-138-14
|
|
B-1-1 |
Letter Dated January 29, 2015 – FEI Submitting Evidentiary Update to the Application
|
|
B-2 |
Letter Dated March 2, 2015 - FEI Submitting Response to BCUC IR No. 1 |
|
B-3 |
Letter Dated March 2, 2015 - FEI Submitting Response to BCOAPO IR No. 1 |
|
B-4 |
Letter Dated March 2, 2015 - FEI Submitting Response to BCSEA IR No. 1 |
|
B-5 |
Letter Dated March 2, 2015 - FEI Submitting Response to CEC IR No. 1 |
|
B-6 |
Letter Dated March 4, 2015 - FEI Submitting Workshop Agenda |
|
B-7 |
Letter Dated March 6, 2015 - FEI Submitting Workshop Presentation |
|
B-8 |
Letter Dated March 13, 2015 – FEI Response to Workshop Undertakings |
|
|
|
Intervener Documents
|
C1-1 |
British Columbia Pensioners’ and Seniors’ Organization, Active Support Against Poverty, BC Coalition of People with Disabilities, Counsel of Senior Citizens’ Organizations of BC, and the Tenant Resource and Advisory Centre (bcoapo) Letter dated January 27, 2015 – Request for Intervener Status by Tannis Braithwaite, Lobat Sadrehashemi and Russ Bell |
|
C1-2 |
Letter Dated February 10, 2015 – BCOAPO Submitting Information Request No. 1 to FEI |
|
C2-1 |
Commercial Energy Consumers Association of British Columbia (cec) Letter Dated January 28, 2015 – Request for Intervener Status by Christopher Weafer
|
|
C2-2 |
Letter Dated February 10, 2015 – CEC Submitting Information Request No. 1 to FEI |
|
C3-1 |
BC Sustainable Energy Association and the Sierra Club of British Columbia (bcsea) Letter Dated January 29, 2015 – Request for Intervener Status by William J. Andrews and Thomas Hackney |
|
C3-2 |
Letter Dated February 10, 2015 – BCSEA Submitting Information Request No. 1 to FEI |
|
C4-1 |
Canadian Office and Professional Employees Union, Local 378 (Cope) Letter Dated February 12, 2015 – Request for Late Intervener Status by Jim Quail and Iain Reeve |
Interested Party Documents
|
D-1 |
|
Letters of Comment
|
E-1 |
|
[1] FEI 2014-2018 Performance Based Ratemaking Revenue Requirements Decision (PBR Decision), p. 182.
[2] FEI PBR Decision, pp. 185-186.
[3] Exhibit B-1, p. 1.
[4] Exhibit B-1, p. 2.
[5] FEI Reply, p. 8.
[6] Ibid, p. 6.
[7] Ibid, p. 7.
[8] CEC Final Submission, p. 19.
[9] FEI Reply, p. 9.
[10] Exhibit B-1-1, p. 28.
[11] Exhibit B-1, pp. 14-15.
[12] FEI PBR Decision, pp. 188, 234.
[13] Exhibit B-1, p. 15.
[14] Exhibit B-2, BCUC IR 1.6.1.
[15] Exhibit B-2, BCUC IR 1.6.2.
[16] Based on information in Exhibit B-2, BCUC IR 1.6.2.
[17] Exhibit B-1, p. 15.
[18] Exhibit B-2, BCUC IR 1.5.1.1.
[19] BCOAPO Final Submission, p. 3.
[20] CEC Final Submission, pp. 4-5.
[21] FEI Reply, pp. 12-16.
[22] CEC Final Submission, p. 5.
[23] BCOAPO Final Submission, pp. 3-4.
[24] FEI Reply, p. 15.
[25] Exhibit B-1, pp. 19-21.
[26] CEC Final Submission, pp. 3-4.
[27] FEI Reply, p. 13.
[28] FEI PBR Decision, pp. 192-194.
[29] T-1, pp. 64-67.
[30] Exhibit B-1, p. 25.
[31] Exhibit B-2, BCUC IR 1.9.4.
[32] CEC Final Submission, p. 6.
[33] FEI Reply, pp. 17-18.
[34] Exhibit B-1, p. 26.
[35] Exhibit B-5, CEC IR 1.31.1.
[36] CEC Final Submission, pp. 6-7.
[37] FEI Reply, p. 20.
[38] Exhibit B-1, p. 6.
[39] FEI Reply, p. 26.
[40] Exhibit B-2, BCUC IR 1.5.1, pp. 20-31.
[41] Exhibit B-3, BCOAPO IR 1.8.1, pp. 13-14; Exhibit B-5, CEC IR 1.21.0, pp. 51-52.
[42] Exhibit B-1, p. 4.
[43] FEI Application for Approval to Include FEVI and FEW into the PBR Plan, Exhibit B-5, BCUC IR 1.3.1.
[44] CEC Final Submission, pp. 2, 15-16.
[45] Ibid.
[46] FEI Reply, p. 23.
[47] Exhibit B-1, pp. 41-42.
[48] Exhibit B-1, pp. 41-42.
[49] Exhibit B-5, CEC IR 1.31.1.
[50] Exhibit B-1, Appendix B, Table B-6, p. 8.
[51] Exhibit B-5, CEC IR 1.31.1.
[52] CEC Final Submission, pp. 7-9.
[53] FEI Reply, p. 20.
[54] Exhibit B-1, p. 124.
[55] T1: p. 112.
[56] T1: p. 114.
[57] Exhibit B-2, BCUC IR 1.31.2.
[58] Ibid, BCUC IR 1.31.3, 1.31.3.1.
[59] T1:112-115.
[60] BCSEA Final Submission, p. 5.
[61] FEI Reply, p. 26.
[62] BCSEA Final Submission, p. 5.
[63] Ibid, p. 7.
[64] BCSEA Final Submission, p. 6.
[65] CEC Final Submission, p. 17.
[66] FEI Final, p. 25.
[67] FEI Reply, pp. 2-3.
[68] BCOAPO Final Submission, p. 4; CEC Final Submission, p. 13.
[69] Exhibit B-1-1, pp. 5, 8.
[70] Ibid, p. 62.
[71] Exhibit B-2, BCUC IR 1.29.1.
[72] Ibid, BCUC IR 1.29.2.
[73] CEC Final Submission, pp. 15-16.
[74] Ibid.
[75] FEI Reply, pp. 23-24.
[76] Exhibit B-1, p. 50.
[77] Ibid.
[78] Exhibit B-2, BCUC IR 1.24.1.
[79] Exhibit B-2, BCUC IR 1.24.3.
[80] Ibid, BCUC IR 1.24.5.
[81] Exhibit B-1, p. 50; Exhibit B-2, BCUC IR 1.25.1.
[82] Exhibit B-1, p. 50.
[83] Exhibit B-2, BCUC IR 1.25.1.
[84] Exhibit B-1, p. 51.
[85] Ibid.
[86] Exhibit B-2, BCUC IR 1.26.2.
[87] Ibid.
[88] Ibid, BCUC IR 1.26.5.
[89] Exhibit B-2, BCUC IR 1.26.2.
[90] FEU 2012-2013 RRA Decision, p. 59.
[91] CEC Final Submission, p. 13.
[92] BCOAPO Final Submission, p. 19.
[93] BCSEA Final Submission, p. 2.
[94] FEU 2014 LTRP Decision, p. 11.
[95] Ibid, p. 12.
[96] Exhibit B-1, pp. 52-53.
[97] Exhibit B-2, BCUC IR 1.28.1.
[98] Exhibit B-1, pp. 53-54.
[99] Exhibit B-1, pp. 53-54.
[100] Ibid, pp. 107-110.
[101] Exhibit B-2, BCUC IR 1.30.6.
[102] Exhibit B-5, CEC IR 1.4.1.
[103] Exhibit B-1, p. 4.
[104] Exhibit B-2, BCUC IR 1.1.1.
[105] Ibid, BCUC IR 1.2.1.
[106] Ibid, BCUC IR 1.2.9.
[107] Exhibit B-1, p. 5.
[108] Exhibit B-5, CEC IR 1.12.4.
[109] CEC Final Submission, p. 18
[110] Ibid, p. 19.
[111] Ibid, p. 20.
[112] FEI Reply, pp. 6-11.
[113] Ibid, p. 26.
[114] Order G-6-15, Appendix A.
[115] FEI Reply, p. 28.
[116] CEC Final Submissions, p. 23.
[117] BCOAPO Final Submissions, p. 6.
[118] BCOAPO Final Submissions, p. 6.
[119] CEC Final Submissions, p. 23.
[120] BCSEA Final Submission, p. 7.
[121] FEI Reply Submission, p. 28-29.
[122] Exhibit B-2, BCUC IR 1.5.1, pp. 20-31.
[123] Exhibit B-3, BCOAPO IR 1.8.1, pp. 13-14; Exhibit B-5, CEC IR 1.21.0, pp. 51-52.