IN THE MATTER OF

the Utilities Commission Act, R.S.B.C. 1996, Chapter 473

 

and

 

FortisBC Energy Inc. and FortisBC Inc.

Multi-Year Performance Based Ratemaking Plans for 2014 through 2019

approved by the British Columbia Utilities Commission Decisions and Orders G-138-14 and G-139-14

Application for Reconsideration and Variance

 

 

BEFORE:               D. M. Morton, Commissioner/Panel Chair

D. A. Cote, Commissioner                                            February 10, 2015

N. E. MacMurchy, Commissioner

 

 

O  R  D  E  R

WHEREAS:

A.      On June 10, 2013 and July 5, 2013, FortisBC Energy Inc. (FEI) and FortisBC Inc. (FBC), respectively, applied to the British Columbia Utilities Commission (Commission) for approval of a proposed multi-year performance based ratemaking (PBR) plans for the years 2014 through 2018;

 

B.      On September 15, 2014, the Commission issued Order G-138-14 for FEI and Order G-139-14 for FBC, with accompanying Decisions, setting out the approved PBR plans for FEI and FBC (collectively, FortisBC) for the period from 2014 through 2019 (PBR Decisions);

 

C.      By letter dated October 3, 2014, FortisBC filed a Request for Clarification and Request for Reconsideration and Variance of certain aspects of the PBR Decisions (Reconsideration Application);

 

D.      By letter dated October 9, 2014, the Commission established Phase One of the reconsideration process wherein it requested comments from interveners in the PBR proceedings on whether the Commission should proceed to Phase Two of the reconsideration process. FortisBC was also given the opportunity to respond to intervener comments;

 

E.       By Order G-173-14 dated November 12, 2014, the Commission determined that the Reconsideration Application should proceed to Phase Two of the reconsideration process and established a regulatory timetable for parties to file final and reply submissions;

 

F.       The Commission reviewed the Reconsideration Application and the submissions of all participants.

 

NOW THEREFORE as set out in the reasons for decision attached as Appendix A to this order, the British Columbia Utilities Commission orders as follows:

 

1.       FortisBC Energy Inc. (FEI) and FortisBC Inc. (FBC)’s request for reconsideration and variance of the Commission’s determination regarding the use of prior year actuals for the Growth Term in the Performance Based Ratemaking (PBR) formula for FEI and FBC is denied. However, the Commission makes two refinements to its previous determination to use prior year actual customer growth:

a.       FEI and FBC are approved to recover the variance in earned return driven by the use of prior year customer additions for the growth term when compared to the actual customer additions. This positive or negative variance in earned return resulting from the Growth Term shall be recovered from or returned to customers in the subsequent year through the earnings sharing mechanism.

 

b.      At the end of the PBR term, or any subsequent extension to the PBR term, FEI and FBC are approved to adjust the earnings sharing calculation for the last year of the PBR term to account for the actual growth in the last year of the PBR term.

 

2.       FEI’s request for reconsideration and variance of the Commission’s determination regarding the adoption of the Uniform System of Accounts is approved. FEI is approved to continue utilizing its New Code of Accounts.

 

3.       FEI is directed to file, for Commission approval, any proposed changes to its New Code of Accounts prior to implementing these changes. As part of the filing for approval, FEI must describe the reason for the change

and provide the quantitative and qualitative impact of the change on the affected accounts. FEI must also clearly track the movement of the expenses from the old account activity to the new account activity.

 

4.       FEI is directed to file within 60 days of the date of this order the Resource and Activity View schedules for Actual 2014 Operating and Maintenance (O&M) results for each of FEI, FortisBC Energy (Vancouver Island) Inc. (FEVI), FortisBC Energy (Whistler) Inc. (FEW), and FEI amalgamated (FEI Amalco). FEI must provide the Activity View information as one schedule with separate side-by-side columns for each entity. As part of this filing, FEI must describe any changes or modifications which have been made to its New Code of Accounts as a result of the amalgamation.

 

5.       FEI is directed to file a proposal to deal with any benchmarking difficulties that may arise from the use of its New Code of Accounts by no later than the third Annual PBR Review.

 

6.       FEI’s request for reconsideration and variance of the Commission’s determination regarding the recovery of the 2012 Biomethane Application costs is partially approved. FEI is approved to recover the costs of the

2012 Biomethane Application and the Reconsideration of Order G-29-13 Regarding Supply Risk process from all non–bypass ratepayers. However, FEI must recover the following proceeding costs through the Biomethane Variance Account: Inquiry into Biogas Supplier Exemption; Biomethane Third-Party Suppliers Regulatory Process; Section 71 Purchase Agreement with Greater Vancouver Sewerage and Drainage District; and the submissions on the Certificate of Public Convenience and Necessity (CPCN) threshold for biomethane facilities.

 

7.       FEI must file with the Commission within 60 days of the date of this order a breakdown of the amount of application costs incurred for each of the proceedings identified by the Panel in directive 6 of this order. In the event that a specific breakdown is not available, FEI is directed to use its best efforts to estimate the allocation of costs across the proceedings.

 

 

DATED at the City of Vancouver, in the Province of British Columbia, this        10^th       day of February of 2015.

 

                                                                                                                                BY ORDER

 

Original signed by:

 

                                                                                                                                D. M. Morton

                                                                                                                                Commissioner/Panel Chair

Attachment

 

 

 

In The Matter Of

 

 

 

FortisBC Energy Inc. and FortisBC Inc.

Multi-Year Performance Based Ratemaking Plans for 2014 through 2019

approved by the British Columbia Utilities Commission Decisions

and Orders G-138-14 and G-139-14

Application for Reconsideration and Variance

 

 

REASONS FOR DECISION

 

 

 

February 10, 2015

 

 

 

 

Before:

 

D. M. Morton, Commissioner/Panel Chair

D. A. Cote, Commissioner

N. E. MacMurchy, Commissioner

 

Table of Contents

Page No.

 

 

 

1.0....... Growth Term... 3

1.1          FortisBC submission. 3

1.2          Intervener submissions. 4

1.3          FortisBC reply. 5

2.0....... Uniform System of Accounts. 7

2.1          FEI submission. 8

2.2          Intervener submissions. 9

2.3          FEI reply. 9

3.0....... Biomethane Application Costs. 11

3.1          FortisBC submission. 11

3.2          Intervener submissions. 12

 

 

 

1.0               Growth Term

In the Commission decisions on FortisBC Energy Inc.’s (FEI) and FortisBC Inc.’s (FBC) (collectively, FortisBC) Applications for a Multi-Year Performance Based Ratemaking (PBR) Plan for 2014 through 2018 (PBR Decisions), the Commission made the following determination regarding the Growth Term:

Further, to eliminate the possibility of potential bias, the Panel directs that the ratio be calculated as the ratio of the number customers or service line additions one year previous, to the number of customers or service live additions two years previous. The Panel recognizes that this introduces some lag into the formula calculation, but we consider it necessary in order to eliminate the potential of upward bias. This is the same approach we took in the case of the Inflation Factor.[1]

 

FortisBC seeks reconsideration of the Commission’s determination to use prior year actual customer growth in the capital and Operating and Maintenance (O&M) formula (Reconsideration Application). In its view, “[t]his determination was based on a mistake of fact and would have the material impact of not allowing [Fortis] to recover its prudently incurred cost of adding customers.”

1.1               FortisBC submission

In the Reconsideration Application, FortisBC cites the following statement made by the Panel in the FEI PBR Decision:

“Of further concern to the Panel is that the Growth Term relies on Fortis’ estimate of the average number of customers in the upcoming year.

…

In Fortis’ proposed PBR mechanism, if there is an over estimate, there is never an opportunity for true-up. This is a [sic] similar to the potential for bias that we observed in the use of a forecast inflation term.”

 

FortisBC submits that the conclusion above “is not an accurate summary of the evidence” because:

1.       Formula amounts are subject to true-up going forward for actual customer growth;

2.       There is no potential for bias in overestimating customer counts – i.e. upward bias; and

3.       It is incorrect to draw a correlation between customer growth from the prior year and current year costs.[2]

 

In its Final Argument, FortisBC claims that its proposal on the Growth Term was internally consistent in terms of the drivers of demand and resulting revenues and costs, both being based on a forecast of customers. By using the same driver (forecast customers) in each case, FortisBC’s proposal ensured that changes in revenues and costs would serve to offset each other. This, in turn, ensured that neither customers nor the Company would benefit significantly or suffer significant detriment as a result of forecasting error in the number of customers.[3]

 

FortisBC also submits that under its proposed PBR plans, “an overestimate of customer additions would lead to higher O&M and capital under the formula; however, this same overestimate would also result in higher forecast revenues. These would have offsetting impacts to the annual revenue requirements.”[4]

1.2               Intervener submissions

Commercial Energy Consumers Association of British Columbia (CEC) submits that the use of forecasts does not provide for costs to be accurately attributed to the actual growth experienced in a year. It further submits

that the use of actuals from the prior year is a better representation of the size of the customer base than is the forecast methodology used by FortisBC and using lagged actuals is an appropriate principle to minimize the effects of forecast bias. Additionally, given that the utility will receive a spending envelope for the actual customer base in the following year the extent of the issue is limited to the cost of the delay on any variance from actual. Since customers are not all added at the beginning of the year, the cost to the utility is further mitigated. CEC submits this boils down to a de minimus cost for the utility and should not be reversed by the Commission.[5]

 

In the FEI PBR proceeding, FortisBC provided a “Customer Addition Variance” report. In that report, FortisBC provided an analysis of the variance between forecast and actual customer additions for a 10 year period (2003 to 2012). In that analysis, FortisBC concluded “in only two years were all customer classes additions variances unfavourable,[6] 2003 and 2009. All other years were a mix of favourable and unfavourable variances between the rate classes.” FortisBC also states that across all rate classes, the total 10-year variance (between 2003 and 2012) of 4,733 additions is unfavourable.[7]

 

In its Phase 2 submission, CEC summarizes FortisBC’s 10-year data and asserts that the 10-year variance is 5.6% and then provides two further analyses of the data. In the first, CEC breaks the 10 year period into 4 different consecutive 6 year periods, which are representative of a six year PBR period. CEC concludes that “the forecast customer additions versus actual customer additions variance ranges from 5.3% in Period 1 to 15.7% in Period 4. The average variation is 11.1% over the 4 periods.”[8]

 

The second analysis applied the methodology directed by the Commission (“lagged actuals”) for the 10 year period, and for each of those 4 consecutive 6-year periods, and compares the result to the results of FortisBC’s forecast methodology described in the previous paragraph. Here, CEC concludes that for the 10 year period, “the variance from actuals is only 1%. This is 4.6 percentage points below the 5.6% variance using actuals, and equates to an 81.9% improvement in the variance.” With regard to the four six year periods, CEC submits that:

•         The average lagged actual variance for the four periods is 8.7%.

•         The average difference in variance between using a forecast (11.1 %) and lagged actuals (8.7%) for the four PBR Periods is 2.4%.

•         This change in variance represents a 21.7% improvement in the error that would otherwise have been to the customer's disadvantage. In any given PBR period the over forecasting bias is only partially reduced but in the long term would be eliminated. ^[9]

 

“BCSEA-SCBC agree with FEI-FBC that the Decision’s Growth Factor approach introduced a disconnect between the treatment of revenues and the treatment of costs. In BCSEA-SCBC’s view, the Annual Review is the appropriate venue for identifying, and if necessary responding to, a pattern of overestimating annual customer additions. BCSEA-SCBC support variance of the PBR Decision to change the Growth Term methodology to the FortisBC Growth Term methodology.”[10]

 

British Columbia Old Age Pensioners’ Organization et al. (BCOAPO) submits that it does not agree with FortisBC that the Commission’s statement regarding no opportunity for “true up” under the FortisBC proposal was incorrect.

 

In BCOAPO’s view, “while forecasting error may not ‘compound,’ in the sense that prior years’ forecasting errors are continued into future years, forecasting error is additive over the PBR term as each year’s forecasting error is retained for that year, and is added to any forecasting error occurring in prior or subsequent years of the PBR.”[11]

 

BCOAPO further submits that “[t]he Commission was within its authority to require the Growth Term to be based on actual customer additions. It is not clear that FortisBC’s method is superior, and the Commission’s direction that the Companies rely on actual growth to determine costs was designed to eliminate the possibility of upward bias in forecasting.”[12]

1.3               FortisBC reply

FortisBC argues that as a forecast is unlikely to predict the exact number of customer additions, the relevant question is not whether there are variances per se, but whether the forecast variances display a consistent bias. It submits that “[t]he variances exhibited in FEI’s customer growth do not evidence forecast bias.”[13]

 

FEI submits that “CEC’s assertion that the past variances always favoured the shareholder to the detriment of customers is based on a significant oversimplification of the financial impacts of variances and is not accurate.” It further argues that “CEC Has Presented Data in a way that Exaggerates the Magnitude of Variances.”[14]

 

In support of its argument, FortisBC relies on the analysis provided in Appendix E, Exhibit B-1-1 from the FEI PBR proceeding. In that analysis, FortisBC concluded “in only two years were all customer classes additions variances unfavourable,[15] 2003 and 2009. All other years were a mix of favourable and unfavourable variances between the rate classes.” However, FortisBC does not address the further analysis done by CEC on the results of FortisBC’s forecast methodology over the four six year periods or of the comparison to the Commission directed methodology.[16]

 

Commission determination

 

For the reasons outlined below, the Panel is not persuaded that there has been a mistake in fact, with material implications, made by the Commission in the PBR Decisions regarding the Growth Term. Accordingly, FortisBC’s request for reconsideration of the Commission’s determination to use prior year actual customer growth in the capital and operating and maintenance (O&M) formula is denied. However, as a result of this Reconsideration Application, the Panel makes two refinements to its previous determination to use prior year actual customer growth.

The Panel finds that under the PBR plans there is no longer an offsetting impact from revenues and costs driven by customer additions due to the Commission’s determination that all variances in revenue shall be flowed through to ratepayers. Therefore, the Commission is accurate in its statement that potential bias could exist in forecasting customer additions under FortisBC’s proposed Growth Term. As a result, we find no evidentiary basis for FortisBC’s submission that “[its] proposal ensured that changes in revenues and costs would serve to offset each other.”

 

Under the PBR plans there is no longer an offsetting impact on the revenue side due to the fact that FortisBC has been directed to record all variances between forecast and actual revenues, including variances from customer additions, in a deferral account. Thus, ratepayers and shareholders are not at risk for over or under forecasting of revenues. Further, revenue and cost variances will not offset each other.

 

Directive 1 of both Order G-162-14 and Order G-163-14 states that FEI and FBC, respectively, are:

approved to establish a single flow-through deferral account to capture the annual variances between forecast and actual amounts for all costs and revenues which are flowed through on a forecast basis and which do not have a previously approved deferral account. The flow-through deferral account is approved to be utilized for the duration of the PBR period only.

 

Controllable O&M and capital costs associated with customer growth are not flowed through to ratepayers and they are not subject to the deferral account treatment as directed by the above referenced orders. However, variances in revenues due to customer growth and demand per customer are subject to deferral account treatment. Accordingly, the effect of these directives is to decouple revenues and expenditures.

 

Increases to controllable O&M and capital expenditures are driven by the PBR formula, which includes a growth factor. Any variances between the formula-driven expenditures and the actual expenditures will be shared between the ratepayer and the shareholder on a 50-50 basis through the Earnings Sharing Mechanism (ESM). Therefore, if forecast expenditures are higher than actual, all else equal, there is an opportunity for increased earnings to be realized through the ESM.

 

In its PBR Decisions, the Commission expressed a concern that in FortisBC’s proposed PBR mechanism, if there is an over estimate, there is never an opportunity for true-up. FortisBC took issue with this position and in its submissions tried to demonstrate that this is not the case. The Panel is not persuaded by these arguments and consider FortisBC’s interpretation of the meaning of the term “true-up” to be inappropriate. The use of the term “true-up” means to correct a variance for a particular time period, in this case one year. The fact that uncorrected errors are not compounded does not mean they are trued-up. The methodology proposed by FortisBC eliminates compounding but does not address forecast errors for a given year and therefore, the result cannot be considered to be trued-up.

 

Given this possibility of variance each year which is never trued-up, the issue is whether the forecast methodology proposed by FortisBC is likely to produce significantly superior results to the Commission’s methodology.

 

Neither FortisBC’s proposed method nor the method directed by the Commission in the PBR Decisions gives a perfect result. FortisBC’s proposed method almost certainly introduces a variance each and every year, given the difficulties inherent in forecasting. Further, the methodology provides no opportunity to true-up in a particular year. The Commission directed methodology also almost certainly introduces a variance every year, although it does provide for that variance to be trued up in the following year.

The Panel acknowledges that the past is not necessarily a predictor of the future. However, CEC’s analysis of past data is illustrative in that it demonstrates that over the examined periods, FortisBC’s proposed methodology did not produce results that were superior to the lag method approved by the Commission. The results produced by the Commission’s approved methodology are closer to what actually occurred in terms of net additions than the method proposed by FortisBC. Given these results and the lack of evidence to the contrary, the Panel is not persuaded that the methodology proposed by Fortis will produce superior results with respect to forecasting accuracy. In addition, the Panel concludes there is no evidence to suggest that using the Commission’s methodology is harmful to either ratepayers or FortisBC’s shareholders in any material way.

 

Notwithstanding the lack of evidence of material harm related to the Commission’s approved methodology, the Panel has made two refinements that will serve to minimize the impact of the variance caused by the lag.

 

The first of these recognizes that in the event actual growth exceeds the growth used to calculate the formula spend, the shareholder is out of pocket the cost of financing the difference, until the subsequent year when the formula spending “catches up.” Similarly, in the case where the actual growth is less than the growth used in the formula, the ratepayer is out of pocket for the financing costs. Therefore, the Panel approves the recovery of the variance in earned return, calculated at the weighted average cost of capital, driven by the use of prior year customer additions for the growth term when compared to actual customer additions. This positive or negative variance in earned return resulting from the growth term shall be recovered from or returned to customers in the subsequent year through the earnings sharing mechanism.

 

The second refinement addresses the fact that at the end of the PBR period, there will be no chance to catch up on the last year of lag. Therefore, at the end of this PBR term, or of any subsequent extension to this PBR term, the Panel considers an adjustment to the earning sharing calculation for the last year of the PBR term to be appropriate. This adjustment accounts for any difference between the actual growth and the lagged growth term used to calculate formula spending in the last year of the term.

2.0               Uniform System of Accounts

The Commission made the following determination in the FEI PBR Decision regarding adoption of the Uniform System of Accounts (USoA):

The Panel considers that the use of the USoA for reporting purposes provides consistent and comparable information at an account level over time. The Panel also notes that if forecasting in future RRAs followed this same system of accounts, the comparison of forecast to actual results at the account level would be more transparent, reduce the number of IRs and increase efficiency. FEU’s adoption of the USoA may also assist the bench marking study by increasing the comparability of FEU’s reporting with other jurisdictions that use the USoA…

…Therefore, the Commission Panel directs FEU to fully adopt the USoA and commence tracking all costs under the USoA as of the beginning of 2016.[17]

 

FEI seeks reconsideration of the Commission’s determination to fully adopt the USoA. In FEI’s view: “…adoption of the USoA will not result in the benefits anticipated by the Commission.”[18] Further, FEI submits that it “will be required to incur material work effort and expenditures for no benefit.”[19]

2.1               FEI submission

FEI submits that the evidence on the record does not support the Commission’s conclusions regarding the benefits arising from adoption of the USoA. In particular, FEI disputes four main benefits stated by the Commission in the PBR Decision and argues the following:[20]

(i)      Adoption of the USoA would not result in more transparent or granular analysis;

(ii)    Adoption of the USoA would not result in fewer Information Requests (IRs);

(iii)   Adoption of the USoA may not assist in the bench marking study; and

(iv)  Adoption of the USoA would not result in increased efficiency.

 

FEI states that changing from its New Code of Accounts to the USoA would result in an approximate 20 percent reduction in the number of accounts tracked by FEI. FEI points to accounts such as “Other General Operations” and “Administration Expense” as examples of accounts where FEI’s New Code of Accounts provides greater granularity due to the fact that FEI further breaks these accounts down to even more specific activities.[21]

 

With regards to areas where FEI’s New Code of Accounts provides fewer accounts than the USoA, FEI submits that in these cases it does not separately manage these activities at the USoA level of detail; thus, if FEI were directed to convert to the USoA it would have to allocate costs related to these activities in an arbitrary manner which would not result in more meaningful information.[22]

 

FEI states that the FEI PBR Decision “appears to suggest that FEI would be able to provide more comparable information if it had adopted the USoA.”[23] However, FEI argues that “the adoption of the BCUC USoA for O&M will not resolve these [comparability] issues.”[24] FEI provides support for its assertion by reproducing its response to BCUC IR 2.309.1 from the PBR proceeding, in which FEI provides the following reasons why certain historical O&M information is not comparable:

1.       Customer Service department was insourced starting in 2012;

2.       Accounting policies changed, resulting in items being classified differently between O&M and capital;

3.       Organization changes occurred at a lower level of reporting than was currently being captured in the system; and

4.       The operating environment evolved over the intervening period including changes in energy policies, customer programs, codes and regulations.[25]

 

In the PBR Decisions, the Commission directed FEI and FBC to prepare a benchmarking study to be completed no later than December 31, 2018.[26] When making its determination on adoption of the USoA, the Commission stated that adopting the USoA may assist the bench marking study by increasing the comparability of FEI’s reporting with other jurisdictions that use the USoA. However, FEI submits that adopting the USoA may not assist with benchmarking for the following reason:

Although the USoA is similar to those in place in Ontario and Alberta, having the same accounts will not assist in benchmarking if the items captured in each account differ. This will occur due to different programs in place in different jurisdictions (for example the existence of natural gas for transportation in the FEU), utilities being vertically integrated in BC as compared to separation of the functions in Alberta, utilities following different accounting standards, and different approved capitalization policies.[27]

2.2               Intervener submissions

CEC submits that reconsideration is not supported by FEI’s argument on the basis of mistaken benefits. CEC further states that the Commission has the jurisdiction and is entitled to establish reporting as it so requires and that the Commission is not required to justify the manner in which it requires reporting. CEC notes that adoption of the USoA is consistent with the practice in other jurisdictions such as Alberta and Ontario.[28]

 

CEC agrees that it is important that the USoA deliver the anticipated benefits described by the Commission. It recommends that the Commission clarify the extent to which the USoA needs updating and that the Commission direct FEI to work cooperatively with Commission staff to update and revise the USoA.[29]

 

BCOAPO does not agree with FEI that the Commission made an error in directing FEI to fully adopt the USoA. However, BCOAPO states that it would support a process in which Commission staff work with FEI to update and modify the USoA to meet the needs of FEI, the Commission, and interveners.[30]

 

No other interveners commented or took a position on adoption of the USoA.

2.3               FEI reply

FEI submits that it is “confident that the Commission’s goal…is to require reporting in a manner that can in fact be justified. Indeed, the Commission provided reasons to justify the adoption of the USoA in the FEI Decision.”[31] FEI re-iterates its submission that the USoA will not deliver the benefits anticipated by the Commission and that adoption of the USoA is therefore not justified.

 

FEI notes that both BCOAPO and CEC support FEI’s alternative request that the Panel direct Commission staff to work collaboratively with FEI to modify the USoA. FEI submits: “This shows general agreement that, at the very least, the USoA needs updating. This is also consistent with the fact that both FortisBC Inc. and BC Hydro have developed customized versions of the BCUC USoA for Annual Reporting to the Commission.”[32]

 

Commission determination

 

The Panel does not agree with FEI that the Commission made an error of fact in the PBR Decisions with regard to the benefits to be gained from adoption of the USoA, particularly with regards to creating the ability for the Commission to separately review costs under the “Operating,” “Maintenance,” and “General and Administrative” expense categories. However, the Panel recognizes that the existing Commission USoA is out-dated and therefore may not be reflective of FEI’s current operational situation. The Panel also acknowledges that, with the exception of Pacific Northern Gas Ltd., the other major utilities in BC are not fully compliant with the USoA and that these utilities are not reporting under the USoA for revenue requirement purposes. Thus, requiring FEI to fully adopt the USoA at this time is inconsistent with the approach taken with other BC utilities. Therefore, the Panel finds there is just cause to approve FEI’s request for reconsideration and variance regarding the adoption of the USoA. Accordingly, the Panel approves for FEI to continue utilizing its New Code of Accounts.

 

There were numerous instances during the FEI PBR proceeding where FEI was unable to respond to Commission Information Requests due to an inability to provide comparative historical information under its New Code of Accounts. FEI highlights this comparability issue in its Reconsideration Application and in its Phase Two Submission by re–stating its response to BCUC IR 2.309.2 in the FEI PBR proceeding. This response states that in some cases historical information is not comparable for the following reasons:

1.       Customer Service department was insourced starting in 2012;

2.       Accounting policies changed, resulting in items being classified differently between O&M and capital;

3.       Organization changes occurred at a lower level of reporting than was currently being captured in the system; and

4.       The operating environment evolved over the intervening period including changes in energy policies, customer programs, codes and regulations.[33]

 

Regardless of whether these comparability issues would be resolved by adoption of the USoA, the Panel considers comparability of O&M data to be critical to achieving an adequate understanding of changes in O&M both from a historical perspective and as a tool for analyzing forecasts. Therefore, the Panel directs that FEI file for approval from the Commission any proposed changes to its New Code of Accounts prior to implementing these changes. As part of the filing for approval, FEI must describe the reason for the change and provide the quantitative and qualitative impact of the change on the affected accounts. FEI must also clearly track the movement of the expenses from the old account activity to the new account activity.

 

The Panel notes that FEI has recently undergone a large change which may pose a challenge for comparability going into to the PBR – the amalgamation of FEI, FortisBC Energy (Vancouver Island) Inc. (FEVI), and FortisBC Energy (Whistler) Inc. (FEW). The Panel also notes that in the FortisBC Energy Utilities (FEU) Application for Common Delivery Rates Methodology, FEU provided financial schedules for 2014 for each of FEI, FEVI, FEW, and FEI amalgamated (FEI Amalco). However, it does not appear that FEU provided the O&M information for each of these entities in the Activity View format. Accordingly, the Panel directs FEI to file within 60 days of the date of this order the Resource and Activity View schedules for Actual 2014 O&M results for each of FEI, FEVI, FEW, and FEI Amalco. For ease of comparability, the Panel directs FEI to provide the Activity View information as one schedule with separate side-by-side columns for each entity. As part of this filing, FEI must describe any changes or modifications which have been made to its New Code of Accounts as a result of the amalgamation.

 

Given that FEI is approved to continue using its New Code of Accounts and that the Commission in the FEI PBR Decision directed FEI to complete a benchmarking study by December 31, 2018, the Panel expects that FEI will find a solution to overcome the benchmarking difficulties it has highlighted in its Reconsideration Application. FortisBC is directed to file its proposal to deal with any benchmarking difficulties that may arise from the use of its new Code of Accounts by no later than the third Annual PBR Review.

3.0               Biomethane Application Costs

In the FEI PBR Decision, the Commission stated:

The Panel denies FEI’s request to capture these application costs in the existing Biomethane Program Costs deferral account. In the 2013 Biomethane Decision, the Commission directed “all interconnection and Biomethane Program Costs are to be recorded in the BVA along with the cost of supply.” (2013 Biomethane Decision, p. 65) Recording these costs in the BVA provides FEI with the opportunity to recover all of the Biomethane Program costs from biomethane customers and the Panel expects it will make every effort to do so. Accordingly, FEI is instead directed to record these costs in the Biomethane Variance Account [BVA].[34]

 

FortisBC seeks reconsideration of the Commission’s decision on the grounds that the characterization of these application costs as being Biomethane Program costs is not accurate.[35]

3.1               FortisBC submission

FortisBC submits that in the 2013 Biomethane Decision, the Commission stated that “[f]or clarity, in the Decision, the Panel will refer to ‘Biomethane Program Overhead Costs’ as including education, marketing, direct administration costs of enrollment and the cost of IT upgrades.” Further, the Cost Recovery Model for the biomethane program provided for only the cost of procuring biogas, the cost of upgrading and the Biomethane Program Overhead Costs to be accumulated in the BVA.

 

FortisBC also points out that this treatment is inconsistent with the approved treatment for similar types of applications, in particular citing the Alternative Energy Systems (AES) Inquiry Application Costs, Natural Gas for Vehicles (NGV) for Transportation Application Costs and the Customer Choice Program.

 

FortisBC also noted that “due to the longer than expected regulatory review process, largely driven by the additional five separate public processes that were ultimately initiated, the actual costs of the 2012 Biomethane Application were approximately $425 thousand, or approximately $290 thousand (over three times) greater than the $135 thousand of costs as forecast in the Application.” FortisBC further explained that the five separate processes are: Inquiry into Biogas Supplier Exemption process; Biomethane Third-Party Suppliers process; Section 71 Purchase Agreement with Greater Vancouver Sewerage and Drainage District (GVS&DD) process; Reconsideration of Order G-29-13 Regarding Supply Risk process; as well as submissions on the CPCN threshold for biogas plants. [36]

 

FortisBC further notes that the addition of the 2012 Biomethane Application costs in the BVA would result in a material increase to the BERC rate (if recovered in one year, an increase of approximately $2/GJ) that could significantly affect customer uptake of the Biomethane Program.[37]

3.2               Intervener submissions

CEC agrees that the decision in the 2012 Biomethane Program Application did not include application costs in the BVA, but does not conclude, as does FortisBC, that the absence “should not be relied upon as specifically excluding those costs.”[38]

 

However, CEC submits that “it may be considered discriminatory to single out biomethane customers for recovery of regulatory application costs where regulatory costs for other specific programs are borne by all customers.”[39]

 

With regard to the potential impact on the BERC rate, CEC agrees that it is material and because the program is grounded in government policy, the Commission should vary its decision.

 

BCOAPO submits that there are three issues:

(1)    is it normally correct to allocate application costs to all customers;

(2)    if so, is there anything different about the biomethane program that justifies the application costs being allocated differently than other types of application costs; and

(3)    if so, does this justification outweigh the potential that allocating application costs solely to the biomethane customers would set the price of biomethane at such a high rate that the program is likely to fail.

 

BCOAPO concludes that “[i]f the application costs would be so significant that the biomethane program is likely to fail if application costs are allocated to the small group of customers taking biomethane service, that is a factor weighing against allocating application costs solely to that group. BCOAPO acknowledges that all British Columbians benefit from the environmental benefits associated with the biomethane program, and consequently have an interest in success of the program.”[40]

 

BCSEA-SCBC support FEI’s request for reconsideration and variance of the FEI PBR Decision so as to approve recovery from all non-bypass customers of the application costs. It states that assigning the Biomethane application costs to all non-bypass customers would be consistent with the approved regulatory treatment of other applications. Further, the 2013 Biomethane Decision did not include the application costs in the program costs. In addition, BCSEA-SCBC agree that increasing the BERC rate could significantly affect customer uptake of the Biomethane program and submits that such an outcome would be contrary to the public interest.[41]

 

Commission determination

 

For the reasons outlined below, the Panel allows the requested reconsideration in part.

 

The Panel agrees with the views of FortisBC and interveners that the 2012 Biomethane Application costs should be dealt with in a manner that is consistent with other application costs. In that regard, the Panel finds that at least some of the application costs should be allocated to all non-bypass customers.

 

In the 2012 Biomethane proceeding, FEI argued that,

The costs allocated to all customers are those required to make the service available to all customers and, as such, it follows as a matter of cost causation that they be recovered from all customers. In other words, the costs of making the program available and providing every customer with the choice of taking the service should be borne by all customers who are given that benefit. This is consistent with the approved practise for the Customer Choice program and the Energy Efficiency and Conservation [EEC] program.”[42]

 

The principle underlying this reconsideration decision is consistent with the approach taken in the Customer Choice and EEC programs. The 2012 Biomethane Application costs are in support of a program that provides an offering to all non-bypass customers and, as a result, it is appropriate that all customers share in the application costs.

 

However, the Panel notes that the costs applied for – some $425 thousand – also include costs for the following applications: Inquiry into Biogas Supplier Exemption process, Biomethane Third-Party Suppliers process,
Section 71 Purchase Agreement with GVS&DD process, the Reconsideration of Order G-29-13 Regarding Supply Risk process and Submissions on the CPCN threshold for biomethane facilities.

 

In the 2013 Biomethane Decision, the Commission approved the following Cost Recovery Model:[43]

 

 

The question before the Panel is whether all of these applications are in support of making the program available to all customers or whether they are part of the cost of procuring biogas, upgrading, or interconnection costs. The following proceedings are further described on the Commission website as follows:

•         Inquiry into Biogas Supplier Exemption. British Columbia Utilities Commission Inquiry into an Exemption for Biogas and Biomethane Suppliers.

•         Biomethane Third-Party Suppliers Regulatory Process Applications for Approval of Third-Party Suppliers’ Rates and Acceptance of FEI Biomethane Supply Agreements with Third-Party Suppliers and FEI Capital Expenditures for Related Interconnection Facilities.

•         Section 71 Purchase Agreement with GSV&DD FEI - Biomethane Purchase Agreement between FortisBC Energy Inc. and the Greater Vancouver Sewerage and Drainage District.

 

In addition to the above proceedings, the Commission invited parties in the 2012 Biomethane Application proceeding to make “submissions on the CPCN threshold for biomethane facilities.” The Commission reviewed the submissions and by Order G-27-14 determined that that where FEI builds the interconnection and/or upgrader facilities for biomethane supply projects, the threshold below which a Certificate of Public Convenience and Necessity is not required remains $5 million.

 

The Panel is of the view that the Inquiry into Biogas Supplier Exemption, the Biomethane Third-Party Suppliers Regulatory Process, the Section 71 Purchase Agreement with GVS&DD and the submissions on the CPCN threshold for biomethane facilities are all related to the supply and acquisition of biogas and interconnection or upgrader facilities. The Cost Recovery Model provides that costs of this nature be

 

recovered through the BVA. Accordingly, we find that the costs of these proceedings should be recovered through the BVA. The costs of the remaining proceedings – the 2012 Biomethane Application and the Reconsideration of Order G-29-13 Regarding Supply Risk process – are approved to be recovered from all non-bypass ratepayers.

 

FortisBC provides no breakdown of the approximately $425 thousand of application costs. The Panel directs FEI, within 60 days of the date of this order, to provide a breakdown of the amount of application costs incurred for each of the proceedings identified by the Panel. In the event that a specific breakdown isn’t available, FEI is directed to use its best efforts to estimate the allocation of costs across the proceedings.

 

In making this determination, the Panel recognizes there may be an impact on the BERC rate that could potentially affect the ability to attract biomethane customers. However, the 2013 Biomethane Decision provides mitigation options for FEI in that eventuality.

 

Further, the Panel notes that by incurring regulatory costs related to the process to determine exemptions for Biogas suppliers, an outcome was reached that will have the effect of reducing biogas supply costs in the future.