IN THE MATTER OF
the Utilities Commission Act, RSBC 1996, Chapter 473
and
FortisBC Energy Inc.
Annual Review of 2016 Delivery Rates
BEFORE: H. G. Harowitz, Panel Chair/Commissioner
D. A. Cote, Commissioner December 7, 2015
D. M. Morton, 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 approving for FortisBC Energy Inc. (FEI) a Multi-Year Performance
Based Ratemaking (PBR) Plan for 2014 through 2019 (the PBR Decision). In
accordance with the PBR Decision, FEI is to conduct an Annual Review process to
set rates for each year;
B. As part of the FEI Annual Review of 2015 Delivery Rates Decision issued on May 27, 2015, the Commission set out a default regulatory timetable template for future annual reviews. In accordance with this default regulatory timetable template, FEI filed a proposed regulatory timetable for the review of the 2016 annual review materials in advance of filing its 2016 annual review application;
C. On August 20, 2015, the regulatory timetable for the FEI Annual Review of 2016 Rates proceeding was established by Order G-138-15 and included, among other things, an anticipated date of September 4, 2015 for FEI to file its 2016 Annual Review materials;
D. On September 3, 2015, FEI submitted its Annual Review for 2016 Rates Application materials (Application);
E. The following interveners registered in the proceeding:
• Commercial Energy Consumers Association of British Columbia;
• Canadian Office and Professional Employees’ Union, Local 378;
• BC Sustainable Energy Association and the Sierra Club of British Columbia; and
• British Columbia Old Age Pensioners’ Organization, et al.;
F. In accordance with the Regulatory Timetable established by Order G-138-15, the Application review process included the following:
• one round of Commission staff and intervener information requests;
• an evidentiary update filed by FEI on October 16, 2015;
• a workshop held on October 26, 2015, to review FEI’s 2015 performance results and the 2016 forecast revenue requirements;
• a response by FEI to undertakings arising from the information requested at the workshop;
• written final submissions from interveners filed on November 9, 2015; and
• FEI’s written reply submission filed on November 18, 2015;
G. The Commission has reviewed the Application and evidence filed in the proceeding and finds it necessary to make determinations with Reasons for Decision to follow in a timely manner upon issuance of this order.
NOW THEREFORE pursuant to sections 59-61 of the Utilities Commission Act, and for the reasons to follow, the British Columbia Utilities Commission orders as follows:
1. FortisBC Energy Inc.’s (FEI) requested interim delivery rates for all non-bypass customers effective January 1, 2016, resulting in an increase of 2.74 percent compared to 2015 delivery rates, are not approved as filed.
2. Interim delivery rates for all non-bypass customers effective January 1, 2016, as modified by the directives in this order, are approved. Rates will remain interim pending the outcome of FEI’s current cost of capital proceeding.
3. FEI’s existing capital structure and return on equity (ROE) is made interim effective January 1, 2016, and will remain in force until otherwise directed by the Commission in the current FEI cost of capital proceeding.
4. FEI’s requested changes to depreciation and net salvage rates are not approved. FEI is directed to maintain existing depreciation and net salvage rates until otherwise directed by the Commission. FEI is further directed to submit additional information and analysis on depreciation and net salvage rate changes, as outlined in the Reasons for Decision to follow, by February 29, 2016.
5. Establishment of the following rate base deferral accounts are approved:
a) 2015 System Extension Application deferral account; and
b) Biomethane Energy Recovery Charge (BERC) Rate Methodology Application deferral account.
6. Establishment of the 2017 Long-term Resource Plan (LTRP) Application deferral account is approved, subject to the following limitations on inclusion of costs for external resources:
a) Eligible costs for external resources are limited to required external resources that are incremental to the costs included in the FEI Base O&M under PBR; and
b) A maximum of $1.050 million over two years, whereby FEI must submit any amount in excess of this to the Commission for approval prior to committing to those excess expenditures.
7. The Rate Stabilization Deferral Account riders for Mainland customers effective January 1, 2016, in the amounts set out in Table 10-5 in Section 10 of the Application are approved.
8. The Phase-in Rate riders effective January 1, 2016, in the amounts set out in Table 10-7 for Mainland customers and Table 10-9 for Vancouver Island and Whistler customers in Section 10 of the Application are approved.
9. The Revenue Stabilization Adjustment Mechanism riders effective January 1, 2016, in the amounts set out in Table 10-10 in Section 10 of the Application are approved.
10. The transfer of the balance in the FortisBC Energy (Whistler) Inc. Rider B Refund deferral account to the Residual Rate Riders deferral account as described in Section 12.4.1 of the Application is approved.
11. Capital costs associated with the Fraser Gate IP Project as approved in Order C-11-15 are excluded from PBR Base Capital.
12. The method used by FEI to allocate costs to FortisBC Inc. (FBC) regarding costs incurred by FEI staff handling call-centre activity to support FBC customers is acceptable, subject to the following:
a) If in the future the costs being allocated to FBC from FEI for the handling of calls exceeds $100,000 in any one year, FEI is directed to provide an analysis of various cost allocation methods and provide evidence as to which will provide the most appropriate results.
13. FEI is directed to re-calculate 2016 interim delivery rates and file revised financial schedules with the Commission reflecting the changes outlined in this order by January 15, 2016.
DATED at the City of Vancouver, in the Province of British Columbia, this day of 7th December 2015.
BY ORDER
Original signed by:
H. G. Harowitz
Panel Chair/Commissioner
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In The Matter Of
FortisBC Energy Inc.
Annual Review of 2016 Delivery Rates
REASONS FOR DECISION
December 21, 2015
Before:
H. G. Harowitz, Panel Chair / Commissioner
D. A. Cote, Commissioner
D. M. Morton, Commissioner
Table of Contents
Page No.
1.3 Application review process
2.0....... DETERMINATIONS ON APPROVALS SOUGHT.
2.2 Depreciation and net salvage rates
2.3 Interim delivery rate approval
3.0....... DETERMINATIONS ON ISSUES ARISING..
3.1 Treatment of Fraser Gate IP Project capital costs.
3.1.1 Should the LMIPSU Project be regarded as a single CPCN or as two CPCNs?
3.1.2 Do the revised capital exclusion criteria apply to the Fraser Gate IP Project?
3.3 Service quality indicators
3.3.3 Telephone Service Factor (Non-Emergency)
3.4 Cross-utilization of FEI employees
3.5 Reconciliation of taxes and depreciation to the revenue deficiency
3.6.1 Savings from FTE reductions
By Order G-138-14 dated 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. As part of the FEI Application for Approval of a Multi-Year PBR Plan for 2014 through 2018 Decision (PBR Decision), the Commission set out the following list of activities to be undertaken in each annual review:
- 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.
- Review of the current year projections and the upcoming year’s forecast.
- 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.
- 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.
- 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.
- Assess and make recommendations with respect to any SQIs that should be reviewed in future annual reviews.
- Assess and make recommendations to the Commission on the scope for future annual reviews.[1]
On September 3, 2015, FEI filed its Annual Review of 2016 Rates application (Application). FEI proposes a 2016 delivery rate increase of 2.22 percent over 2015 delivery rates (updated to 2.74 percent in Exhibit B-2-1), which equates to an increase of approximately $13 to the annual bill for an average Mainland residential customer and is in line with inflation.[2]
Under the PBR Plan’s earnings sharing mechanism, FEI proposes to distribute $5.068 million in earnings sharing to customers in 2016. These savings are attributable to projected 2015 operations and maintenance (O&M) expense savings as well as actual O&M savings in 2014 being higher than projected. FEI does not project any savings in capital expenditures relative to the PBR formula in 2015 and projects that 2015 capital expenditures will exceed the PBR formula amount by $6.816 million.[3]
FEI seeks the following approvals pursuant to sections 59 to 61 of the Utilities Commission Act (UCA):
- Interim delivery rates for all non-bypass customers effective January 1, 2016, resulting in an increase of 2.22 percent (updated to an increase of 2.74 percent in Exhibit B-2-1) compared to 2015 common delivery rates, with the increase to be applied to the delivery charge, holding the basic charge at existing levels. Rates will remain interim pending the outcome of FEI’s current cost of capital proceeding.
- The creation of rate base deferral accounts for the following regulatory proceedings:
- 2015 System Extension Application;
- Biomethane Energy Recovery Charge (BERC) Rate Methodology Application; and
- 2017 Long-Term Resource Plan (LTRP) Application.
- Rate Stabilization Deferral Account (RSDA) riders for 2016 in the amounts set out in Table 10-5 in Section 10 of the Application.
- Phase-In Rate Riders for 2016 in the amounts set out in Table 10-7 for Mainland customers and Table 10-9 for Vancouver Island and Whistler customers in Section 10 of the Application.
- Revenue Stabilization Adjustment Mechanism (RSAM) riders for 2016 in the amounts set out in Table 10-10 in Section 10 of the Application.
- Depreciation rates in the amounts set out in Table 12-2 in Section 12 of the Application.
- The 2016 revenue requirement impact of the difference between the updated depreciation rates and the existing depreciation rates for Fort Nelson to be captured in the existing Fort Nelson Revenue Surplus/Deficiency deferral account.
- Net salvage rates in the amounts set out in Table 12-3 in Section 12 of the Application.
- The transfer of the December 31, 2015 remaining balance of the FortisBC (Whistler) Energy Inc. (FEW) Rider B Refund Deferral to the existing Residual Rate Riders deferral account.
These approvals will be addressed in section 2 of the Reasons for Decision.
1.3 Application review process
In accordance with Order G-138-15, establishing the Regulatory Timetable for review of the Application, the following review process was undertaken:
- One round of Commission staff and intervener information requests (IRs);
- An evidentiary update to the Application filed by FEI on October 16, 2015;
- A workshop open to all participants held on October 26, 2015;
- An opportunity for FEI to file responses to undertakings arising from information requested at the workshop;
- Written final submissions from interveners filed on November 9, 2015; and
- Written reply submission from FEI filed on November 18, 2015.
The following four interveners registered and actively participated in the proceeding:
- Commercial Energy Consumers Association of British Columbia (CEC);
- Canadian Office and Professional Employees’ Union, Local 378 (COPE 378);
- BC Sustainable Energy Association and the Sierra Club of British Columbia (BCSEA); and
- British Columbia Old Age Pensioners’ Organization et al. (BCOAPO).
The following issues arose during the course of these proceedings, requiring further discussion and/or determinations:
- Treatment of the Fraser Gate Intermediate Pressure (IP) Project capital costs;
- Demand forecast issues;
- SQI issues;
- Cross-utilization of FEI customer service representatives;
- Reconciliation of depreciation and taxes to the components of the revenue deficiency; and
- Evaluation of the PBR, including savings from full time equivalent (FTE) reductions.
Each is addressed in section 3 of the Reasons for Decision.
2.0 DETERMINATIONS ON APPROVALS SOUGHT
No issues were raised with respect to four of the requested approvals, and the Panel finds them to be just and reasonable, and accordingly approves them, with no further comments provided in these Reasons for Decision.
• RSDA riders for 2016 in the amounts set out in Table 10-5 in Section 10 of the Application.
• Phase-In Rate Riders for 2016 in the amounts set out in Tables 10-7 for Mainland customers and Table 10-9 for Vancouver Island and Whistler customers in Section 10 of the Application.
• RSAM riders for 2016 in the amounts set out in Table 10-10 in Section 10 of the Application.
• The transfer of the December 31, 2015 remaining balance of the FEW Rider B Refund Deferral to the existing Residual Rate Riders deferral account.
Discussion of the remaining requested approvals is provided in the immediately following sections.
FEI proposes to create three new deferral accounts to capture the costs related to the following applications: 2015 System Extension; BERC Rate Methodology; and the 2017 LTRP. None of these applications are Certificate of Public Convenience and Necessity (CPCN) applications.[4]
On June 30, 2015, FEI filed the 2015 System Extension Application and expects to incur approximately $325 thousand in costs related to consulting, legal fee expenditures, intervener and participant funding costs, Commission costs as well as related miscellaneous costs. FEI requests approval for these costs to be captured in a rate base deferral account and amortized over a two-year period commencing in 2016.[5]
FEI filed the BERC Rate Methodology Application in August 2015. FEI expects to incur $75 thousand in costs related to the application and points out that the actual costs will be dependent on the process and the number of participants. FEI requests approval to capture the costs in a rate base deferral account and to amortize the costs over a one-year period in 2016.[6]
FEI is also seeking a deferral account for the 2017 LTRP Application to capture the costs of required external resources that are incremental to the costs included in FEI’s Base O&M under PBR. Previously, incremental costs incurred for development of the 2014 LTRP were approved in rates as part of the FortisBC Energy Utilities (FEU) 2012-2013 Revenue Requirements Decision.[7] However, in the subsequent PBR Decision, the Commission directed FEI to remove these incremental LTRP costs from FEI’s Base O&M.[8]
FEI states: “…in the 2014 LTRP Decision the Commission directed FEI to conduct additional activities and analyses for the 2017 LTRP that were not required for the 2014 LTRP.”[9] FEI also states that in the 2015 Annual Review Decision, the Commission agreed that requiring these incremental activities would result in additional costs that were unanticipated in the PBR Decision but requested that FEI provide additional detail concerning these incremental expenditures prior to approving the LTRP deferral account. This information has been provided in Appendix C2 of the Application. FEI forecasts total expenditures for the 2017 LTRP to be captured in the requested deferral account of $1.050 million with $0.505 million incurred in 2016. FEI states that this deferral account will only capture actual final amounts for third-party consultants.[10]
Intervener submissions
With specific reference to the BERC Rate Methodology Application, CEC raised concern with granting deferral account treatment to non-CPCN application costs. CEC submits that FEI has relied on its own presumptions and has presented no evidence that the PBR Decision contemplated non-CPCN application costs as a flow through item, nor has it provided history verifying its position. CEC continues by stating that if the Commission is satisfied that deferral account treatment has been granted for non-CPCN regulatory costs and it was intended that such costs would be outside the PBR Base O&M, it is suitable for deferral account treatment to be applied. Otherwise it is appropriate for the Commission to deny deferral accounts for these items.[11]
Concerning the 2017 LTRP Application, CEC submits “it would be difficult to determine if there are potentially any activities in completing the 2017 LTRP that would normally be included in the O&M base…” However, CEC notes the evidence on the record is that only incremental costs will be captured in the LTRP deferral account and submits that FEI has provided significant justification for its position. CEC therefore recommends approval of the LTRP deferral account.[12]
BCSEA supports FEI’s request for deferral account treatment for both the BERC Rate Methodology Application and the 2015 System Extension Application. BCSEA states it has a strong interest in the FEI 2017 LTRP meeting expectations as introduced in the 2010 LTRP Decision. Accordingly, BCSEA supports Commission approval of a deferral account for incremental spending on outside resources to prepare the LTRP. It is satisfied that FEI “has established that the incremental spending is not included in the PBR O&M spending and is required for FEI to meet the Commissions requirements for the content of the 2017 LTRP.”[13]
FEI reply
FEI states that CEC’s submission regarding FEI not providing evidence that the PBR Decision contemplated inclusion of non-CPCN application costs to be a flow through item is incorrect. FEI asserts that deferral accounts have been consistently granted to capture external costs related to regulatory applications both before and during PBR. Given this practice, FEI submits these costs clearly could not have been within the Base O&M for PBR. In support of its position, FEI cites comments from the PBR Decision where the Commission approved the establishment of the 2014-2018 PBR Application Costs Deferral Account, stating “[t]he Panel considers this treatment to be consistent with past deferral accounts approved for application-related costs.”[14]
FEI submits CEC’s comments concerning the difficulty of determining whether there are activities in completing the 2017 LTRP that should be in the Base O&M are incorrect. FEI asserts that the Commission in its 2010 and 2014 LTRP Decisions directed the incremental activities being undertaken in the 2017 LTRP. Further, FEI states that the incremental funding for completion of the 2014 LTRP “were explicitly removed from FEI’s Base O&M.”[15]
Commission determination
There are two issues raised concerning the approval of the three application deferral account requests as proposed by FEI. The first of these is whether deferral accounts to capture external costs related to regulatory applications have been granted as a matter of regulatory practice and were thus contemplated within the PBR Decision as qualifying as a flow through item. The second refers to FEI’s specific request for approval of an estimated $1.050 million of incremental costs to employ outside resources to complete the 2017 LTRP.
i) Application cost deferral accounts
The Panel finds the practice of approving deferral accounts to capture external costs related to the preparation of an application is warranted within the PBR and should not be included as part of Base O&M. Accordingly, the Panel approves deferral account treatment as proposed by FEI for the BERC Rate Methodology and the 2015 System Extension Review Applications. The Panel notes that the practice of deferring external costs related to the preparation of regulatory applications is consistent and longstanding. In the past there has been no distinction among application cost deferral accounts related to CPCNs as opposed to other types of applications. Further there have been no compelling reasons raised in this proceeding that suggest this practice should change.
ii) Incremental resources for the 2017 LTRP
The Panel approves FEI’s request for approval of the 2017 LTRP Application deferral account to capture the costs of required external resources that are incremental to the costs included in FEI’s Base O&M under PBR. The issue of providing additional resources was raised in the 2015 Annual Review where FEI was requested to provide additional detail concerning expenditures. This has been provided in Appendix C2 of the Application. The Panel is satisfied that funds for the these incremental costs are not included in FEI’s Base O&M and the
requested deferral account treatment is appropriate in this instance. Additionally, the Panel notes that both CEC and BCSEA expressed support for FEI’s proposed deferral account treatment of these incremental costs and no other intervener raised concerns.
FEI estimates the cost of third party consultants to assist with preparatory work for the 2017 LTRP Application to be $1.050 million (over two years). The Panel considers this amount to be a ceiling and directs FEI to submit any amount in excess of this to the Commission for approval prior to committing to expenditures.
2.2 Depreciation and net salvage rates
As part of the Application, FEI filed an updated depreciation study (Appendix D-1 of the Application) based on FEI’s gas plant-in-service as of December 31, 2014. Consistent with FEI’s previous depreciation study filed as part of the FEU 2012-2013 Revenue Requirements Application (RRA), FEI contracted Gannett Fleming Valuation and Rate Consultants Inc. (Gannett Fleming) to perform the review of FEI’s depreciation and net salvage rates.
Based on the Depreciation Study recommendations, FEI proposes to decrease the average composite depreciation rate from 3.19 percent to 3.06 percent, resulting in a decrease to depreciation expense of $6.9 million in 2016. FEI further proposes to increase the composite net salvage rate from 0.44 percent to 0.64 percent, resulting in an increase to net salvage expense of $10.1 million in 2016. The overall impact of the proposed changes, including the changes to the Contribution in Aid of Construction (CIAC) amortization rate, is a net increase in depreciation and amortization expense for 2016 of $5 million compared to 2015.[16]
In FEI’s recent revenue requirement applications where depreciation studies have been filed, issues have been raised and explored related to the quantum of depreciation rate changes, asset losses, and the collection of net salvage. In the current proceeding, similar issues were explored by Commission staff and interveners. These issues and the resulting determinations are described in the following subsections.
FEI’s recent history of depreciation studies is as follows:
• 2009 depreciation study filed as part of the FEU 2012-2013 RRA;
• 2007 depreciation study filed as part of the FEI (then Terasen Gas Inc.) 2010-2011 RRA; and
• 1998 depreciation study filed as part of the 2000 RRA.[17]
All of these studies recommended increases to depreciation rates.
The recommended depreciation rate increases in the 1998 depreciation study were not adopted into rates. However, the study was used to implement depreciation rate changes to some asset classes commencing in 2004, which was the first year of FEI’s previous PBR term.[18]
The depreciation rate increases recommended by the 2007 study were approved as part of a negotiated settlement agreement (NSA) which the Commission approved pursuant to Order G-141-09. As part of the NSA, FEI agreed to file a new depreciation study with its next RRA. This new study (the 2009 depreciation study) recommended a further increase to FEI’s depreciation rates that was subsequently approved by the Commission in the FEU 2012-2013 RRA Decision.[19]
Departing from the recommendations in the previous three depreciation studies, the current depreciation study recommends a decrease to the composite depreciation rate starting in 2016.
When asked if it is common for utilities to experience a general depreciation rate decrease following a period of higher depreciation rates, Gannett Fleming responded that “generally, it is not common.”[20] In explanation, Gannett Fleming submitted the following:
The experience of FEI can be attributed to the relatively long time periods between the completion of depreciation studies… Prior to the 2007 depreciation study, a full study was last completed in 1998, so that there was a gap of nine years between studies. As a result of this, rates were increased significantly by the 2007 depreciation study to catch-up for the under depreciation of assets that had occurred over the nine year time period since the last study in 1998.[21]
During the Annual Review Workshop, FEI was asked to provide an updated table of asset losses similar in format to a table it filed in its PBR Application. In the PBR Application, FEI provided the following explanation regarding the asset losses shown in that table:
[T]he asset classes with the largest forecast losses are Distribution services, mains and meters, accounting for more than 90 percent of the $6 million loss forecast for 2014. These are the same asset classes that have historically been subject to significant retirements before the assets were fully depreciated…[22]
As indicated by the preceding quote, asset losses occur if/when assets are retired before they have been fully depreciated. Of note, the removal costs incurred by the utility to retire assets are not included in the calculation of asset losses, but rather in net salvage rates, discussed subsequently in section 2.2.2 of these Reasons for Decision.
Table D3-2 in the PBR Application shows that the aforementioned three asset classes (473 - Services, 475 ‑ Mains, 478 - Meters) have incurred net asset losses in each year from 2003 through 2012.[23] For 2013 and 2014, these asset classes have continued to experience net asset losses.[24] In explanation of the 2013 and 2014 net asset losses, FEI submits the following:
The 2013 actual losses as shown in the table above are higher than the forecast due to retirement of compressors at the Kingsvale Compressor Station, and to a higher number of meters retired than had been forecast. The 2014 actual losses as shown in the table above are also higher than the forecast due to retirements of Transmission mains for the Gateway project.[25]
Despite continual net asset losses, Gannett Fleming recommends an increase to the average service life of Asset Class 475 - Mains, which is described in the depreciation study as the “largest account studied and represents 25% of FortisBC’s depreciable plant.”[26] The impact of increasing the average service life of Asset Class 475 (and therefore decreasing the depreciation rate) is a decrease to depreciation expense of $300,545.[27]
There are other instances in which Gannett Fleming has recommended increases to the average service life of asset classes (i.e. depreciation rate decreases) or no change to the average service life, despite a history of net asset losses. Some examples are:
• Gannett Fleming recommends no change in depreciation rate for Asset Class 465 - Transmission – Pipeline, which represents approximately 22 percent of the depreciable plant studied[28] despite historical results showing that this account has experienced net asset losses in every year from 2003 through 2014.[29]
• Gannett Fleming recommends increases to the average service lives for Asset Classes 467 - TP Measuring & Regulating Equipment and 477 - DS Measuring & Regulating Equipment which result in depreciation rate decreases of 1.87 percent and 1.66 percent, respectively.[30] However, based on historical results, these accounts have experienced net asset losses in every year from 2003 through 2014 (an exception to this is in 2003 where Asset Class 477 experienced a net gain).[31]
Gannett Fleming confirms that all else being equal, lower depreciation rates result in a longer time period over which the assets are depreciated and recovered.[32] However, Gannett Fleming submits that under the average service life methodology, increasing the expected length of an asset class’ depreciation period does not potentially increase the likelihood of early retirements in an asset class. In explanation, Gannett Fleming submits the following:
The average service life methodology recognizes that some assets in the classes will be retired later than the estimated average life and some will be retired earlier. Increasing the estimated life by itself does not potentially increase the likelihood of early retirements. Rather, as successive Depreciation Studies are undertaken and the experience of asset retirements is known, more early retirements than expected will decrease the depreciation period, or conversely, more later retirements than anticipated will increase the depreciation period.[33]
As noted by FEI in response to Undertaking No. 6 from the Annual Review Workshop, the Company originally forecast net asset losses for 2013 and 2014 of $5.9 million and $6.0 million, respectively. By contrast, actual net asset losses for these years were substantially higher at $8.4 million in 2013 and $7.3 million in 2014.[34]
Intervener submissions
None of the interveners oppose the proposed decrease in depreciation rates.
Gannett Fleming recommends an increase to the composite net salvage rate of 0.2 percent which increases the 2016 net salvage expense by $10.1 million.[35]
The asset categories which account for the majority of the increase in net salvage costs are:[36]
• Asset Class 465 - TP Transmission Pipeline
• Asset Class 473 - DS Services
• Asset Class 474 - DS Meters/Regulators Installations
• Asset Class 475 - DS Mains
Gannett Fleming confirms that, consistent with other utilities in the Canadian natural gas utility industry, part of the driver of increased net salvage is higher asset retirement costs in recent years. Gannett Fleming attributes the causes of increased net salvage to a number of factors, including the following:
• New asset classes, mainly attributable to Mount Hayes, have been assigned net salvage rates for the first time due to not being in-service at the time of the last depreciation study;
• Increased retirement costs since the last depreciation study for specific projects in Asset Class 465, such as transmission pipeline relocation activities in 2014 requiring the removal of old pipe;
• Increased retirement costs in Asset Class 473 due to FEI’s focus on retiring inactive distribution service lines. Factors contributing to the increased costs for retiring services lines were the practice of cutting the service line at the main for safety reasons instead of at the property line and increased costs from inflation; and
• The initiation by the provincial government, municipalities, other utilities and FEI to upgrade distribution main infrastructure as well as FEI initiating a program to replace distribution mains having a high relative risk of pipe failure. As a result of these programs and the congested locations of many of the mains, higher retirement costs are being incurred in order to adjust facilities to meet other parties’ requirements and to install new distribution mains in permitted locations.[37]
Intervener submissions
BCOAPO argues that the proposed increases in net salvage are “insufficiently justified” and recommends the changes to net salvage be denied. BCOAPO submits that FEI and Gannett Fleming did not adequately respond to its IR request for a “full and complete evaluation of the research and analysis conducted by Gannett Fleming in support of the recommended salvage costs.”[38] BCOAPO also points to a statement made by Gannett Fleming which indicates that the estimates of net salvage were based “primarily on professional judgment.”[39]
No other interveners opposed the proposed changes to net salvage rates.
FEI reply
FEI argues that BCOAPO is basing its recommendation on a “selective reading of FEI’s evidence” and points to BCOAPO’s statement that estimates of net salvage were based primarily on professional judgment as an example of this. FEI submits that in its response to BCOAPO IR 1.6.1, it described a six step process used to estimate net salvage percentages and that only one of these steps involved discussions with FEI staff or the professional judgement of Gannett Fleming.[40]
FEI agrees with BCOAPO that in many cases, the recommendation for net salvage percentages in the depreciation study will not match exactly to the historical net salvage percentages. This is due to the Company and Gannett Fleming taking a “conservative approach” to transition to higher net salvage rates over time and therefore recommending “lower net salvage rates than the historical analysis alone supported.”[41]
With regards to BCOAPO’s assertions that FEI did not provide “a full and complete explanation of the research and analysis conducted by Gannett Fleming in support of the recommended salvage costs”, FEI submits:
Even though this information had been provided in the 2014 Depreciation Study, FEI summarized the information in the response to BCOAPO 1.6.1 rather than simply refer to the study. FEI is not aware of any other information it could have provided by way of ‘research.’[42]
Commission determination
The Panel is not persuaded that the proposed changes to depreciation and net salvage rates have been adequately justified. Based on our review of the evidence collected in this proceeding, the Panel finds that certain issues have not been sufficiently addressed and as a result, we are unable to make a determination on whether the proposed depreciation rate changes are appropriate. Of particular concern is the number of instances where Gannett Fleming has recommended changes in depreciation rates which do not appear to be supported in evidence.
Therefore, the Panel does not approve the changes to depreciation rates and directs FEI to maintain existing depreciation rates until otherwise directed by the Commission.
The Panel notes that the recommendations for net salvage rate changes are also based on the findings of the depreciation study and that the findings on depreciation and net salvage rates are likely interconnected. Therefore, the Panel directs FEI to maintain net salvage rates at existing rates until otherwise directed by the Commission.
FEI is further directed to submit additional information and analysis on depreciation and net salvage rate changes to the Commission by February 29, 2016.
In particular, the Panel requests that FEI address the following questions in its filing:
Question #1 (Asset Class 475):
(a) What specific information/data led Gannett Fleming to recommend an increase to this asset class’s average service life?
(b) How is the recommended increase to the average service life of Asset Class 475 consistent with the past twelve years of historical net asset losses experienced in this asset class?
(c) Please explain how the recommendations and findings in the depreciation study to decrease the depreciation rate align with the increased retirement activities described in response to BCUC IR 1.28.1 of this proceeding.
Please consider and reference the following statements from the Depreciation Study and BCUC IR 1.28.1 when responding to Question #1:
Page II-4 of the Depreciation Study: “Since the last study, this account has continued to incur retirements at a consistent rate which provide for a reliable statistical indication of average service life characteristics.”
BCUC IR 1.28.1: “Starting around 2010, the provincial government, municipalities, other utilities and FEI initiated significant projects and programs to upgrade infrastructure… At the same time, FEI initiated a program to replace distribution mains having high relative risk of pipe failure.”
Question #2 (Asset Class 465):
(a) How does Gannett Fleming’s recommendation to maintain the existing depreciation rate correlate to the past twelve years of historical net asset losses experienced in this asset class?
(b) Please explain how the recommendations and findings in the depreciation study regarding this asset class’ depreciation rate align with the increased retirement costs described in response to BCUC IR 1.28.1.
Please consider and reference the following statements from the Depreciation Study and BCUC IR 1.28.1 when responding to Question #2:
Page II-5 of the Depreciation Study:
The Retirement Rate Analysis as presented at pages V-17 and V-18 of this report and discussions with the operations and engineering staff have indicated that to date the pipe has experienced only a limited level of retirement activity… The company has indicated that there are no major replacements expected during the immediate planning horizon and that the historical indications are indicative of the future.
BCUC IR 1.28.1: “Since the last depreciation study in 2009, retirement costs have increased for the period 2010-2014 with notable increases experienced in 2011 and 2014 for specific projects...”
Question #3 (Asset Classes 467 and 477):
(a) What specific information led to Gannett Fleming recommending an increase to these asset classes’ average service lives?
(b) How is this recommendation consistent with the past twelve years of historical net asset losses experienced in these asset classes?
Question #4:
For the five asset classes which have experienced the largest historical net losses since 2003 (Asset Classes 465, 473, 474, 475 and 478), does Gannett Fleming expect that at some point in the future the trend of net losses will reverse and that these asset classes will start exhibiting net gains? If yes, please explain when the net gains are expected to starting occurring. If not, please explain why not.
Question #5:
Please compare the proposed depreciation rates for the following FEI asset classes to the depreciation rates for the same (or similar) asset classes of other large Canadian gas utilities:
- Asset Class 465 - TP Mains
- Asset Class 467 - TP Measuring & Regulating Equipment
- Asset Class 473 - DS Services
- Asset Class 475 - DS Mains
- Asset Class 477 - DS Measuring & Regulating Equipment
- Asset Class 478 - DS Meters
The rate impacts of any changes to depreciation and net salvage rates arising from the Commission’s review of the additional information and analysis outlined above shall be incorporated into FEI’s proposed delivery rates for 2017 as part of the Annual Review of 2017 Rates. Therefore, 2016 delivery rates will not be adjusted to reflect changes, if any, to FEI’s depreciation and net salvage rates and will instead take effect commencing in 2017.
In light of the immediately foregoing determinations, FEI’s request to capture the impact of the difference between the updated depreciation rates and the existing depreciation rates for Fort Nelson in the existing Fort Nelson Revenue Surplus/Deficiency deferral account is rendered moot, and therefore the Panel makes no determination on this request.
The Panel notes that the complexity and breadth of material contained in a depreciation study does not easily lend itself to the PBR annual review process as it is currently structured. The Panel recommends that for future PBR annual reviews, depreciation studies be treated as separate filings from the annual review applications.
2.3 Interim delivery rate approval
FEI requests approval of interim delivery rates for all non-bypass customers effective January 1, 2016, resulting in an increase of 2.74 percent compared to 2015 delivery rates, with the increase to be applied to the delivery charge, holding the basic charge at existing levels.[43]
FEI requests that rates remain interim pending the outcome of FEI’s current cost of capital proceeding.[44] In the cost of capital proceeding, FEI requests to change the common equity component of its capital structure to 40 percent and to increase its return on equity (ROE) to 9.5 percent, effective January 1, 2016.[45]
Commission determination
The Panel does not approve FEI’s requested interim delivery rates for 2016 as filed. As described in section 2.2 of these Reasons for Decision, the Panel does not approve FEI’s requested changes to depreciation and net salvage rates. Accordingly, interim delivery rates for all non-bypass customers effective January 1, 2016, as modified by the adjustments to the 2016 revenue requirements resulting from the Panel’s determinations on depreciation and net salvage rates, are approved.
FEI’s request for 2016 delivery rates to remain interim pending the outcome of the cost of capital proceeding is approved. FEI’s existing capital structure and ROE is made interim effective January 1, 2016, and will remain in force until otherwise directed by the Commission in the current FEI cost of capital proceeding.
FEI is directed to re-calculate 2016 interim delivery rates and file revised financial schedules with the Commission reflecting the changes outlined in these Reasons for Decision by January 15, 2016.
3.0 DETERMINATIONS ON ISSUES ARISING
3.1 Treatment of Fraser Gate IP Project capital costs
On October 16, 2015, this Panel issued a letter that expanded the scope of the current PBR Annual Review proceeding “in order to reach definitive conclusions on issues relating to whether the Fraser Gate IP Project should be excluded from FEI’s PBR Base Capital.”[46]
The issue arises from decisions rendered in two somewhat parallel Commission proceedings. First, in the FEI Application for a CPCN for Approval of the Lower Mainland Intermediate Pressure System Upgrade Project Decision (LMIPSU Decision) issued on October 16, 2015, the Fraser Gate IP Project component of the overall project (estimated to cost $18 million at the time of the original application) was adjusted during the course of that proceeding and ultimately approved at a cost of $9 million.[47] Second, in the FEI-FBC Multi-Year PBR Plans for 2014 through 2019 approved by Decisions and Orders G-138-14 and G-139-14 Capital Exclusion Criteria under PBR (PBR Capital Exclusion Criteria) proceeding, the Commission increased the materiality threshold from $5 million to $15 million for determining whether capital costs are eligible for exclusion from FEI’s formula-driven capital spending.[48]
Thus, the question of whether the Fraser Gate IP Project should be excluded from FEI’s PBR Base Capital hinges on resolving two questions:
- Should the LMIPSU Project be regarded as a single CPCN or treated as two discrete CPCNs for the purpose of this issue?
- And if treated as discrete CPCNs, do the revised capital exclusion criteria apply to the Fraser Gate IP Project at its approved cost of $9 million?
3.1.1 Should the LMIPSU Project be regarded as a single CPCN or as two CPCNs?
FEI states that it does not dispute that the Coquitlam Gate IP and Fraser Gate IP Projects can be justified on their own merits.[49] FEI goes on to say that there is compelling rationale for grouping the projects under one CPCN, as summarized below.
- Both replace existing pipe along sections of the two primary pipelines supplying gas to the Metro system in order to improve safety and system reliability.
- Both share common attributes in terms of design, routing process, materials procurement and specialized construction and installation techniques.
- With the Coquitlam Gate IP Project in place, it will be possible to execute the Fraser Gate IP Project without needing to resort to a costly bypass.
- Economies of scale can be achieved by using the same contractor and by executing the Projects in parallel.[50]
BCOAPO submits that “each of the factors identified relate to work flow, rather than to the propriety of grouping the Projects together for the purposes of a CPCN application… The potential cost savings identified by FEI relate to work flow… The fact that projects can be scheduled in a way that creates efficiencies does not turn separate projects into a single project.”[51]
CEC challenges “the appropriateness of combining the two projects into a single CPCN, and submits that the projects could still be constructed together without combining the CPCNs.”[52]
Commission determination
For the purposes of determining whether the Fraser Gate IP Project costs are excluded from FEI’s PBR Base Capital, the Panel finds that the Fraser Gate IP Project is to be treated as a discrete Project (i.e. as separate from the Coquitlam Gate IP Project that was part of the same CPCN).
Whereas FEI has put forward a number of areas where costs can be reduced by managing the projects in parallel, we are not persuaded that these benefits arise from a common CPCN as opposed to prudent management of two (arguably similar and/or related) discrete projects.
3.1.2 Do the revised capital exclusion criteria apply to the Fraser Gate IP Project?
As noted, two important changes took place in the course of events: the costs for the Fraser Gate IP Project went from $18 million to $9 million; and the capital exclusion criteria materiality threshold went from $5 million to $15 million.
The timeline of events is therefore a critical element in determining what rules should apply to this situation.
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Parallel Applications – Key Events Time Line |
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LMIPSU CPCN |
PBR Capital Exclusion Criteria |
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12/19/14: Application filed Replace two segments of the LMIPSU system, at total cost of $263M, including $18M for the Fraser Gate Project (FGP)[53] |
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1/30/15: Application filed Set FEI’s PBR capital exclusion threshold at $15M[54] |
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4/24/15: FEI reply argument Adjustment to base capital not required, as FEI does not anticipate any CPCN projects within the $5M to $15M range during the PBR period[55] |
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4/30/15: Evidentiary update FGP cost revised to $9M in as spent dollars[56] |
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5/26/15: CEC IR-2 questions filed Includes questions on PBR Capital Exclusion if FGP viewed on its own |
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6/18/15: FEI reply to CEC IR-2, including: Question of excluding FGP from Base Capital is hypothetical: FGP is part of a larger CPCN that is clearly above threshold; even if FGP is considered on its own the Capital Exclusion Decision should be seen as applying prospectively to future CPCN Applications, and not to this or prior CPCN Applications[57] |
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7/22/15: Decision issued Exclusion criteria threshold increased to $15M[58] |
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7/31/15: Intervener arguments BCOAPO and CEC argue that, pursuant to the new capital threshold of $15M, the Commission should consider whether the FGP should be excluded from PBR Base Capital[59] |
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8/14/15: FEI reply argument FEI’s position in the Capital Exclusion Application that there were no projects with the $5M to $15M range took into consideration that the FGP was part of a larger (LMIPSU) CPCN |
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10-16-15: Decision issued Declines to rule on the PBR Capital Exclusion issue, stating that it is not a CPCN matter and better addressed inside the Annual PBR review framework[60] |
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No new evidence was presented within the current Application. And having reviewed the parties’ arguments presented in this proceeding, the Panel views them as largely consistent with the positions and arguments they brought forward in the LMIPSU proceeding.
Commission determination
The Panel determines that the Fraser Gate IP Project costs should be excluded from Base Capital.
When viewed in light of the time line laid out above, the Panel finds the following:
- At the time of filing the PBR Capital Exclusion Criteria Application, FEI considered the LMIPSU Application as a single CPCN, and therefore viewed it as having no bearing on the PBR Capital Exclusion Criteria proceeding.
- At the time of filing its reply argument in the PBR Capital Exclusion Criteria proceeding, the evidence does not support a definitive determination as to whether or not FEI realized that the Fraser Gate IP Project revised cost estimates were at a level within the $5 million and $15 million range. More specifically, given the short amount of elapsed time between this reply argument and the LMIPSU Evidentiary Update (i.e. 6 days), one might conclude that this was known inside the organization, but it is equally plausible that the final cost revisions on the Fraser Gate IP Project had not yet been completed.
- At the time of filing the PBR Capital Exclusion Criteria final argument and the LMIPSU evidentiary update, FEI was proceeding under the premise that in any event, the Fraser Gate IP Project was part of a much larger CPCN application that was clearly outside the $5 million and $15 million range.
- The first time FEI was asked to consider the implications of possibly treating the Fraser Gate IP Project as a separate CPCN for the purposes of the capital exclusion issue was at the time of CEC’s filing of its LMIPSU IR No. 2 questions: a date well beyond the close of evidence in the PBR Capital Exclusion Criteria proceeding.
- FEI presents a compelling response to the CEC IR No. 2 questions explaining why FEI did not consider the lower cost estimate for the Fraser Gate IP Project as posing a potential problem with regard to the soon-to-be released PBR Capital Exclusion Criteria Decision.
- At the time the PBR Capital Exclusion Criteria Decision was released, that panel had no cause to consider the implications of the Fraser Gate IP Project being treated as a stand-alone project that could potentially belie FEI’s assertion that there were, in fact, no capital projects that fell into the $5 million and $15 million range during the PBR period. Said another way, the first time an argument was put forward to treat the Fraser Gate IP Project as falling within the range came only after release of the PBR Capital Exclusion Criteria Decision.
Given these facts, the current Panel is persuaded that the question of excluding the Fraser Gate IP Project capital costs from FEI’s PBR Base Capital arises only due to the two proceedings running in parallel. It is clear that FEI’s “silence” on the Fraser Gate IP Project during the PBR Capital Exclusion Criteria proceeding is entirely consistent with the fact pattern above. Thus, with the benefit of hindsight, we are convinced that the just and reasonable treatment of the Fraser Gate IP Project capital costs is to exclude these costs from FEI’s PBR Base Capital.
FEI forecasts an increase in demand for 2016, with the total normalized 2016 demand projected to be approximately 208 petajoules (PJs), which is an increase of approximately 0.4 PJs from the 2015 approved consumption.[61]
As described by FEI in the Application, in the FEI Application for Approval of 2015 Delivery Rates pursuant to the Multi-Year PBR Plan approved for 2014 through 2019 by Order G-138-14 (Annual Review of 2015 Delivery Rates) Decision, the Commission directed FEI to analyze and report on alternatives to its existing forecasting methodologies, including residential and commercial use per customer (UPC) forecasting methods and commercial net customer additions forecasting methods.[62] Pursuant to Commission letter L-30-15, FEI was granted an extension for filing this information. As outlined in letter L-30-15, the Commission expects FEI to file a progress report by April 30, 2016, with the final report filed as part of FEI’s annual review of 2017 rates application.
Intervener submissions
The only intervener to take issue with FEI’s demand forecasts is BCOAPO. The following three issues were raised by BCOAPO in its final submission:
- Rate Schedule 23 - BCOAPO submits that there has been significant historical under and over forecasts of customer additions/losses in Rate Schedule 23 and requests that FEI specifically address this issue in its reply and/or as part of its review of net customer additions forecasting methodologies to be undertaken for inclusion as part of the annual review of 2017 delivery rates application.
- Residential UPC - BCOAPO submits that FEI has likely under forecast the 2016 residential UPC amount and recommends that the forecast decline for residential UPC for 2016 be reduced to 1.3 gigajoules (GJ) per year rather than 1.6 GJ per year.
- Industrial Customer Survey - BCOAPO is concerned that the timing of the industrial customer survey, which is based on a survey collected in May to June 2015, will decrease the accuracy of the 2016 industrial demand forecast. BCOAPO submits that “FEI should not have conducted the 2016 survey six months ahead of filing the application, when it appears feasible to do the survey as little as three months in advance” and requests that FEI “consider conducting the industrial survey closer to the date of filing the 2017 rates application.”[63]
FEI reply
FEI submits that its Rate Schedule 23 demand forecast is reasonable and should be approved as filed for the following reasons:
- Consistent with prior years, FEI forecasts Rate Schedule 23 demand by multiplying the total customer count, as opposed to customer additions, by the use rate; therefore, the total customer count is more relevant than customer additions.
- Rate Schedule 23 is part of the commercial rate group, which in aggregate produced demand variances which were lower than the Itron survey average in four out of the past five years (the Itron survey does not break down survey results between large and small commercial customers).
- Alternatives to forecasting commercial customer additions are already within the scope of FEI’s demand forecast review to be provided in the next annual review.[64]
FEI submits that BCOAPO’s statements regarding the 2016 residential UPC forecast “appear to be based on a misunderstanding”, as FEI’s forecast decline in UPC for 2016 is 1.3 GJ per year, not the 1.6 GJ per year stated by BCOAPO. FEI states that it is “unable to deduce the source of the 1.6 GJ per year figure noted by BCOAPO.”[65]
In response to BCOAPO’s assertion that FEI conducted the industrial survey six months ahead of filing the application, FEI submits that it conducted the survey in May to June of 2015 for the 2016 test period and filed the Application on September 3, 2015; therefore, the survey was closed approximately two months prior to FEI filing the Application, not six months. FEI further submits that “given the time needed to prepare the annual review materials, it would not be possible to conduct the survey any closer to the filing date of the application.”[66]
Commission determination
The Panel approves the 2016 demand forecasts as proposed by FEI. The Panel is satisfied with FEI’s responses to the issues raised by BCOAPO and notes that with regards to two of the issues - residential UPC forecast and timing of the industrial survey - it appears that much of BCOAPO’s concerns were based on a misunderstanding of the evidence.
With regards to the Rate Schedule 23 demand forecast, the Panel is satisfied that the forecasting methodology is reasonable for the purposes of forecasting 2016 demand and reiterates our expectation that this forecasting methodology will be reviewed as part of FEI’s overall forecasting methodology review process as directed in the FEI Annual Review of 2015 Delivery Rates Decision and letter L-30-15.
3.3 Service quality indicators
The following three issues related to SQIs were raised by interveners:
- Reporting of greenhouse gas (GHG) emissions;
- Presentation of SQI results; and
- Savings resulting from a lower benchmark for the Telephone Service Factor (Non-Emergency).
FEI provided 2014 annual GHG emissions results. The 2014 GHG emissions were 140,507 tCO2e; an increase over the 2013 reported value of 127,940 tCO2e.
BCSEA “accept that the annual GHG emission values for 2013 and 2014 are not directly comparable to values reported from 2009 through 2012, during which period FEI’s annual GHG emissions declined steadily.” However, it submits that “[t]he difference between the two figures is in the wrong direction, although this is only two years of data.”[67]
In BCSEA’s view, “FEI should include in its 2016 annual report a description of the steps it is taking to reduce its GHG emissions, along with the 2015, 2014 and 2013 annual GHG emissions results. If 2015 produces another increase in annual GHG emissions then FEI should explain why this is occurring.” BCSEA also submits that the Commission should require FEI to provide information assuring that cost-effectiveness measures incented by the PBR regime are not resulting in increased annual GHG emissions.[68]
FEI reply
FEI submits that BCSEA’s recommendation should be rejected, because it would not be appropriate to introduce this new requirement into the PBR Plan, and that there is no compelling reason to do so. In FEI’s view, “any GHG targets or requirements to reduce GHG emissions are a matter of public policy and will be imposed by legislation. FEI’s costs to meet such requirements would come before the Commission for review in the course of annual reviews or revenue requirement proceedings.”[69]
FEI also points out that the PBR Plan did not include any requirement that FEI meet any SQIs related to GHG emissions and submits:
Imposing a requirement now for FEI to take steps to reduce GHG emissions would therefore be a new burden on FEI, which could potentially entail significant costs. It would therefore be inappropriate to introduce these new cost drivers on FEI’s business which were not contemplated at the time the PBR Plan was approved. (In this regard, FEI notes that BCSEA submits it is too early in the PBR term to make changes in the SQIs.)[70]
Additionally, FEI submits that in the absence of any target or standard for GHG emissions, it is unclear by how much FEI should be expected to reduce GHG emissions in future years and therefore no guidance as to what steps or the level of spending that would be appropriate to invest in reducing GHG emissions.[71]
Commission discussion
The Panel requests FEI to provide the 2015, 2014 and 2013 annual GHG emissions results in the 2017 annual review application if FEI has the capabilities to report on this information and if that information is readily available. Additionally, if there is an increase in GHG emissions for 2015 compared with the prior year, the Panel requests FEI to explain what may have caused the increase, if the cause is readily apparent.
In making this request, the Panel considers that to the extent that any such information is already available, it should be released to the public unless there are compelling issues of confidentiality. The PBR Plan does not now include any GHG reporting requirement, and BCSEA has not provided a persuasive argument to require the implementation of reporting measures that may significantly increase FEI’s costs, so this request is limited to already available information.
The Panel rejects BCSEA’s request for FEI to provide information on whether cost-effectiveness measures are resulting in higher GHG emissions. This would be unduly burdensome to FEI and it is unclear how a causal relationship could be established between PBR efficiency savings and GHG emissions with any reasonable degree of accuracy.
Regarding presentation of SQI information, BCSEA asks the Commission to endorse FEI’s acknowledgement that presentation of the test year and historical SQI results in a single table is a useful way to present the key figures regarding SQIs.[72]
FEI agrees that “providing the requested information in the format suggested allows for a more convenient way to compare the historical performance of the indicator and will provide the SQI performance data in such a format in future PBR annual reviews.”[73]
Commission discussion
The Panel acknowledges FEI’s statement that it will present the test year and historical SQI results in a single table in future annual review filings, as requested by BCSEA.
3.3.3 Telephone Service Factor (Non-Emergency)
CEC submits that the reduction in FEI's Telephone Service Factor (Non-Emergency) benchmark to 70 percent results in annual savings of $50,000 which should not be attributed to the PBR, but rather to the reduction in service levels.[74]
FEI did not comment on this in its reply; however, in Part One of its submission, FEI states: “While FEI has sought to address each topic raised by interveners, silence on FEI’s part should not be interpreted as agreement.”[75]
Commission determination
The Panel dismisses CEC’s submissions regarding FEI’s Telephone Service Factor (Non-Emergency) SQI. The 70 percent benchmark was established as part of the PBR Plan and there is no evidence that this benchmark should be changed, nor would it be appropriate to remove any savings which may be resulting from this change in benchmark, as this is an appropriate outcome of the PBR regime.
3.4 Cross-utilization of FEI employees
Through responses to COPE 378’s IRs, FEI disclosed that approximately 18 of its employees have been trained to take FBC customer calls when FBC requires additional support to reduce wait times for customers. FEI stated: “This initiative takes advantage of slower periods of call volume for the gas operations where previously there would have been idle time for FEI staff.”[76]
Intervener submissions
COPE 378 raises cross subsidization concerns with respect to the methodology employed by FEI to allocate FEI employee costs to FBC.
COPE 378 notes that in answer to COPE 378 IR 1.2.2.1, FEI’s response described a per transaction method of costing as opposed to preparing a time sheet that is tracked hourly. Relying on the testimony provided by Mrs. Mehrer (from FEI) as to the methodology employed, COPE 378 concludes “these cross-service charges to FBC load in many costs that have nothing to do with providing FBC customers with service but rather costs incurred in the service of FEI customers.”[77]
COPE 378 submits this is an “unacceptable billing model” as FBC is “compensating FEI for overtime and other expenses not associated with service to FBC customers” and it is impossible to assess whether the methodology is cost effective as compared to other options. COPE 378 points out that when questioned as to the methodology, FEI representatives were unable to provide examples where this method is employed by FEI and FBC. In addition, COPE 378 submits it was noted that the use of time sheets were the norm and Mrs. Mehrer admitted that time sheet tracking is more accurate.[78]
COPE 378 further notes that Mrs. Mehrer acknowledged that FEI is able to track call lengths but the cost of doing this in her words “would exceed the value of the costs themselves.” COPE 378 does not accept that the utility cannot efficiently and inexpensively track work done on a per file basis and submits that the costing model is contrary to the regulatory principles prohibiting cross-subsidization. COPE 378 further submits that the costing model “violates FBC customer’s legal rights to a fair and reasonable rate based on the cost of serving them.”[79]
FEI reply
FEI asserts that there are numerous methods to allocate costs that are acceptable. Included among these are the use of timesheets and the Massachusetts method. FEI considers the most appropriate method to be dependent upon the cost driver most relevant to a particular allocated cost. FEI submits that the number of interactions is the most relevant cost driver in this instance and has allocated costs accordingly.[80]
FEI takes exception to COPE 378’s concluding that the cross-service charges are costs incurred in the service of FEI customers and add costs that have nothing to do with providing service for FBC customers. FEI submits that if it did not charge an appropriate allocation of contact centre costs it would be cross-subsidizing FBC. It points out that FBC benefits from contact centre facilities and equipment and other employee costs as well as benefiting from the individual employee time. Therefore, it is reasonable for FBC to bear a proportionate share of these costs.[81]
FEI also takes exception to what it considers to be a misleading statement by COPE 378 with respect to the context where timesheet accuracy was discussed. FEI argues that Ms. Mehrer’s statement as to the accuracy of timesheets related to training costs and she was clear in indicating that cost per interaction is “an accurate representation of costs and a fair representation for both FEI and FBC customers.”[82]
Commission determination
The Panel agrees with FEI that there are many methods to allocate costs that are acceptable and the choice of approach may be influenced by cost drivers that are most relevant in each instance. After considering the evidence related to FEI employees handling calls on behalf of FBC, the Panel is persuaded that the approach taken by FEI to allocate costs to FBC is not unreasonable nor is it unfair. While the approach taken by FEI to allocate such costs may, under more intense scrutiny, prove to be more or less appropriate than the method advocated by COPE 378, the issue has to be viewed in the context of materiality.
The Panel notes that Ms. Mehrer addressed magnitude of costs in her testimony in the FEI Annual Review Workshop. With reference to the potential changing of the allocation methodology she made the following statement:
And keeping in mind that for the number of calls for FEI, about 99.7 percent of the calls are for FEI customers and .3 that we’re taking for electric. So, using a different allocation methodology wouldn’t have any significant impact on whatever FEI is incurring. With the costs being between, you know, 500 and 3,000 dollars a month.[83]
We interpret these comments to mean that the total amount under consideration at this time falls in the $12,000 to $36,000 range per annum which the Panel finds is a small amount and does not warrant incurring the costs of reviewing the allocation methodology at this time. However, the Panel also accepts that the costs in question have the potential to grow over time and the cost allocation methodology may produce variances which are more significant in the future. Therefore, if in the future the annual costs being allocated to FBC from FEI for the handling of calls exceeds $100,000 in any one year, FEI is directed to provide an analysis of various cost allocation methodologies and provide evidence as to which will provide the most appropriate results.
3.5 Reconciliation of taxes and depreciation to the revenue deficiency
CEC raises concern with the reconciliation of information FEI has provided in its evidentiary update and what was outlined in the Annual Review Workshop presentation materials. In the Application and in the workshop materials, FEI provided a figure summarizing the components of the 2016 revenue deficiency.[84] Figure 1-1 of the Application shows an amount of $19.1 million representing the increase to depreciation and amortization expense in 2016.[85] Of this amount, $5 million is related to changes to the depreciation and net salvage rates recommended by the depreciation study.[86]
CEC attempts to reconcile the $14.1 million and $19.1 million revenue deficiency components to the updated financial schedules filed by FEI marked as Exhibit B-1-2 but submits it is “unable to establish a clear reconciliation from the evidence above of either the $14.1 million nor of the total $19.1 million claimed in the Application.”[87]
As a result of its reconciliation difficulties, CEC recommends that the Commission “have a clear understanding of the sources of the $19.1 million in total that is being claimed for changes in Depreciation and Amortization prior to approval.” CEC further recommends that in the future, FEI “provide clear statements as to where each of the contributors to the revenue deficiency can be identified in the application and Schedules for ease of reference by the Commission and interveners.”[88]
CEC raises a similar issue with attempting to reconcile taxes to the revenue deficiency and recommends that the Commission “satisfy itself of the accuracy of the tax implications and their impact on the Revenue Deficiency prior to approval.”[89]
No other interveners commented on issues with reconciliation of taxes or depreciation.
FEI reply
FEI provides a reconciliation of depreciation and tax changes to the 2016 forecast revenue deficiency on page 37 of its reply submission. FEI explains that the “source of CEC’s confusion would appear to be that in order to show the earnings sharing separately on the Summary of Revenue Deficiency slide, the amortization and the tax related to the earnings sharing were taken out of the applicable lines on Schedule 1.” FEI agrees to provide a reconciliation of these components in future annual reviews.[90]
Commission discussion
The Panel is satisfied with FEI’s reconciliation provided as Table 1 in its reply submission and notes FEI’s agreement to provide a reconciliation between the contributors to the revenue deficiency and the financial schedules in its future annual review applications.
In its final submission, CEC raised a number of PBR-related concerns, which are described in the following subsections of these Reasons for Decision.
3.6.1 Savings from FTE reductions
CEC takes issue with the manner in which FEI is handling staffing levels in the context of the PBR framework and does not consider savings achieved from FTE reductions to be appropriately characterized as efficiencies incented by PBR.[91]
FEI states “from 2013 Actual to 2015 Projected, total FTEs for the Company decreased by approximately 81, with the decreases estimated to contribute to O&M savings of approximately $7 million.”[92]
The majority of FTE reductions have occurred in the Customer Service department (reduction of 65 FTEs) and the Operations department (reduction of 14 FTEs). The Customer Service department FTE reductions contribute approximately $4.7 million to overall O&M savings and are the result of management reorganization and COPE 378 reductions due to FEI experiencing lower call volumes and lower high-bill complaints in 2015 as the result of warmer weather. Included in the estimated total of $4.7 million in Customer Service savings are reductions in COPE 378 FTEs related to Project Blue Pencil in 2015, contributing an estimated O&M savings of $1 million.[93]
FEI estimates Operations department FTE reductions have contributed approximately $1.7 million in O&M savings. Reductions include those due to ongoing productivity initiatives as well as reductions related to the Regionalization Initiative started in 2014.[94]
Intervener submissions
CEC submits it is not appropriate to reward the reductions in headcount and FTEs over the full period of the PBR as they are “more likely a result of excess headcount in the base than of the discovery of the creative efficiencies intended to be incented by PBR” and that a “comprehensive efficiency review by external consultants prior to PBR could potentially have identified several areas of overstaffing.”[95]
CEC is also concerned that “excessive staffing cuts could potentially have long term adverse effects which will need to be rectified in the future.” It notes “headcount and FTE reductions do not typically require any investment by the utility which would extend beyond a two year period, and as such would be equally profitable for the utility under Cost of Service.”[96]
CEC also submits:
FTE reductions of 81 over a two year period would appear to represent savings that could have been achieved under Cost of Service, with a more than adequate reward to the utility shareholder and at lower cost to the ratepayer. CEC submits that $7 million in headcount and FTE savings would have been appropriately rebased under Cost of Service after two years, rather than continuing to accrue over the 6 year period of the PBR.[97]
FEI reply
FEI submits that CEC provides no basis for its assertion that the reductions in FTEs are “more likely a result of excess headcount in the base.” In its view, “the evidence is that the savings achieved are the result of FEI’s continued focus on productivity, rather than any shortcomings in the base levels set under PBR.”[98]
FEI asserts:
[t]here is no evidentiary foundation to the CEC’s claim that there was excess headcount in the base. Contrary to the CEC’s assertions, FEI’s Base O&M and Capital were the subject of a rigorous review and were approved by the Commission. CEC’s assertion that the savings achieved by FEI are due to the Base O&M being too high is not based on any evidence or analysis, and therefore should be rejected.[99]
FEI also submits that CEC “is seeking to compare what would have been achieved under cost of service to what is achieved under PBR. CEC’s position would appear to be that FEI should only retain earnings sharing for savings that are in addition to what would be expected under cost of service and that are a direct result of PBR.” In FEI’s view, it requires an impossible comparison to a hypothetical cost of service regime in which FEI would not have the incentives provided under the PBR Plan in order to determine what efficiencies are due solely to PBR. FEI submits that “[s]uch a hypothetical comparison serves no function under the PBR Plan approved by the Commission or PBR generally, and would be a speculative exercise. CEC’s suggestions are unworkable and would undermine the incentives and regulatory efficiency of PBR.”[100]
FEI also argues that “it appears that the CEC is advocating for material changes to the terms of the existing PBR Plan, which are more appropriately the subject of a reconsideration request and are therefore outside the scope of this proceeding.”[101]
Commission determination
The Panel finds CEC’s submissions regarding the savings achieved due to FTE reductions to be out of scope to this annual review. While not explicitly stated by CEC in its final submission, the Panel interprets CEC’s submissions as suggesting that FEI’s O&M should be rebased, which would be a significant adjustment to the approved PBR Plan. The Panel therefore re-iterates the statements made by the Commission in the Annual Review of 2015 Delivery Rates Decision:
Those recommendations…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.[102]
This issue will not be considered further in these Reasons for Decision.
In addition to the aforementioned comments by CEC on FTE reductions, CEC provided comments on other aspects of the PBR framework, including major initiatives, SQIs and capital expenditures.
With regards to the major initiatives introduced by FEI since the commencement of the PBR, such as the Regionalization Initiative and Project Blue Pencil, CEC submits:
…the cost to customers of sharing benefits from utility management efficiency initiatives appear to be in excess of what prudent regulation of the utility should expect customers to pay to the utility shareholders and management for the efficiencies achieved.[103]
CEC further submits: “In future PBR processes alternative means of incenting efficiency should be a central focus for customer group representatives.”[104]
CEC states that overall it is satisfied with the SQI results but raises an issue with the Telephone Service Factor (Non-Emergency) SQI.[105] This issue was addressed in section 3.3.3 of these Reasons for Decision.
With regards to capital expenditures, CEC submits “the evidence is building through this PBR period, that PBR incentives are ineffective from a capital perspective and therefore, should be monitored by the Commission.”[106]
Commission discussion
In reviewing the comments in their entirety, the Panel notes that CEC did not make any specific request that would require a finding of fact or a determination in the current proceeding, and hence we make none.
The Panel recognizes that the annual review process is also a forum in which parties can express their perspectives on the efficacy of the PBR framework from year to year, and in that spirit we welcome the comments provided.
Dated at the City of Vancouver, in the Province of British Columbia, this 21st day of December 2015.
Original Signed By
_________________________________
H. G. Harowitz
Panel Chair/Commissioner
Original Signed By
_________________________________
D. A. Cote
Commissioner
Original Signed By
_________________________________
D. M. Morton
Commissioner
[1] FEI Application for Approval of a Multi-Year PBR Plan for 2014 through 2018 (PBR), Decision dated September 15, 2014, pp. 185–186.
[2] Exhibit B-2, p. 1.
[3] Ibid., pp. 1, 4, 7.
[4] Exhibit B-2, p. 56.
[5] Ibid., p. 57.
[6] Ibid.
[7] FEU 2012-2013 Revenue Requirements Application (RRA), Order G-110-12 with reasons for decision dated August 16, 2012, p. 59.
[8] FEI PBR Decision, dated September 15, 2014, p. 210.
[9] Exhibit B-2, p. 57.
[10] Ibid., pp. 57–59.
[11] CEC Final Submission, pp. 14–15.
[12] Ibid., pp. 15–16.
[13] BCSEA Final Submission, pp. 1–2.
[14] FEI PBR Decision, dated September 15, 2014, p. 231.
[15] FEI Reply, pp. 23–24.
[16] Exhibit B-2, pp. 112–113, 116.
[17] Exhibit B-5, BCUC IR 1.27.5.
[18] Ibid.
[19] FEU 2012-2013 RRA, Order G-110-12 with reasons for decision, dated August 16, 2012, pp. 80–81.
[20] Exhibit B-5, BCUC IR 1.27.4.1.
[21] Ibid.
[22] FEI PBR, Exhibit B-1, p. 273 [Emphasis added].
[23] Ibid., Table D3-2, p. 271.
[24] Ibid., Table D3-3, p. 273; Exhibit B-13, Undertaking No. 6.
[25] Exhibit B-13, Undertaking No. 6.
[26] Exhibit B-2, Appendix D-1, p. II-4.
[27] Ibid., Table 12-2, p. 114.
[28] Exhibit B-2, Appendix D-1, p. II-5.
[29] FEI PBR, Exhibit B-1, Table D3-2, p. 271; Exhibit B-13, Undertaking No. 6.
[30] Exhibit B-2, Table 12-2, p. 114.
[31] FEI PBR, Exhibit B-1, Table D3-2, p. 271; Exhibit B-13, Undertaking No. 6.
[32] Exhibit B-5, BCUC IR 1.27.1.
[33] Ibid., BCUC IR 1.27.2.
[34] Exhibit B-13, Undertaking No. 6.
[35] Exhibit B-2, Tables 12-1 and 12-3, pp. 113, 117.
[36] Ibid., Table 12-3, p. 117.
[37] Exhibit B-5, BCUC IR 1.28.1.
[38] Exhibit B-6, BCOAPO IR 1.6.1.
[39] BCOAPO Final Submission, p. 6.
[40] FEI Reply, p. 38.
[41] Ibid., pp. 40–41.
[42] Ibid., pp. 39–40.
[43] Exhibit B-2-1.
[44] Exhibit B-2, p. 2.
[45] FEI Application for its Common Equity Component and Return on Equity for 2016, Exhibit B-1, Appendix D.
[46] Exhibit A-5, p. 1.
[47] FEI Application for a CPCN for Approval of the Lower Mainland Intermediate Pressure System Upgrade Project (LMIPSU), Decision dated October 16, 2015, p. 53.
[48] FEI-FBC Multi-Year PBR Plans for 2014 through 2019 approved by Decisions and Orders G-138-14 and G-139-14 Capital Exclusion Criteria under PBR (PBR Capital Exclusion Criteria), Order G-120-15 with reasons for decision, dated July 22, 2015.
[49] FEI Reply, p. 30.
[50] Ibid., p. 31.
[51] BCOAPO Final Submission, pp. 7–8.
[52] CEC Final Submission, p. 11.
[53] FEI LMIPSU, Exhibit B-1, p. 1.
[54] FEI-FBC PBR Capital Exclusion Criteria, Exhibit B-1, p. 3.
[55] FEI-FBC PBR Capital Exclusion Criteria, FEI Reply, p. 17.
[56] FEI LMIPSU, Exhibit B-1-6, p. 22.
[57] FEI LMIPSU, Exhibit B-14, CEC IRs 3.3, 3.4.
[58] FEI-FBC PBR Capital Exclusion Criteria, Order G-120-15 with reasons for decision, dated July 22, 2015.
[59] FEI LMIPSU, BCOAPO Final Submission, p. 16; CEC Final Submission, pp. 30–32.
[60] FEI LMIPSU, Decision dated October 16, 2015, p. 64.
[61] Exhibit B-2-1, Section 11, Schedule 16.
[62] Exhibit B-2, pp. 16–18.
[63] BCOAPO Final Submission, pp. 3–4.
[64] FEI Reply, pp. 11–12.
[65] Ibid., pp. 12–13.
[66] Ibid., pp. 13–14.
[67] BCSEA Final Submission, p. 3.
[68] Ibid.
[69] FEI Reply, p. 42.
[70] Ibid., p. 43.
[71] Ibid.
[72] BCSEA Final Submission, p. 3.
[73] FEI Reply, p. 43.
[74] CEC Final Submission, p. 25.
[75] FEI Reply, p. 3.
[76] Exhibit B-9, COPE 378 IR 1.2.2.
[77] COPE 378 Final Submission, p. 5.
[78] Ibid.
[79] Ibid.
[80] FEI Reply, pp. 19–20.
[81] Ibid., p. 20.
[82] Ibid.
[83] Workshop Transcript, Volume 1, p. 105.
[84] Exhibit B-2, p. 8; Exhibit B-12, p. 4.
[85] Exhibit B-2, p. 8.
[86] Exhibit B-12, p. 4.
[87] CEC Final Submission, pp. 7–10.
[88] Ibid., p. 10.
[89] Ibid., p. 18.
[90] FEI Reply, pp. 36–38.
[91] CEC Final Submission, pp. 22–23.
[92] Exhibit B-2, p. 5.
[93] Ibid.
[94] Ibid.
[95]CEC Final Submission, p. 23.
[96] Ibid.
[97] Ibid.
[98] FEI Reply, p. 4.
[99]Ibid.
[100] Ibid., p. 5.
[101] Ibid.
[102] FEI 2015 Annual Review Decision, p. 4.
[103] CEC Final Submission, p. 25.
[104] Ibid., p. 24.
[105] Ibid., p. 25.
[106] Ibid.