october 3, 2014 · october 3, 2014 british columbia utilities commission multi-year performance...

October 3, 2014 Via Email Original via Mail British Columbia Utilities Commission 6th Floor, 900 Howe Street Vancouver, BC V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: Re: FortisBC Energy Inc. (FEI) and FortisBC Inc. (FBC) (together the Companies or

FortisBC)

Multi-Year Performance Based Ratemaking Plans for 2014 through 2019 (the PBR Plans) approved by British Columbia Utilities Commission (Commission) Decisions and Orders G-138-14 and G-139-14

Request for Clarification and Request for Reconsideration and Variance

On September 15, 2014, the Commission issued Order G-138-14 for FEI and Order G-139-14 for FBC, each with accompanying Decisions, (the FEI or FBC Decision, or collectively the Decisions) setting out the approved PBR Plans for the Companies for the period from 2014 through 2019 in response to the Companies’ respective 2014-2018 PBR Plan Applications (the Applications). FortisBC is seeking clarification of four aspects of the Decisions based on apparent contradictions or ambiguity, as set out below. In addition, FortisBC seeks a reconsideration and variance of the Commission’s determinations in the Decisions regarding:

The use of prior year actuals for the Growth Term in the formula for FEI and FBC;

The adoption of Uniform System of Accounts (USoA) for FEI; and

The recovery of the 2012 Biomethane Application costs for FEI.

FortisBC first discusses the requests for clarification, followed by the request for reconsideration and variance.

Diane Roy

Director, Regulatory Affairs

FortisBC Energy

16705 Fraser Highway

Surrey, B.C. V4N 0E8

Tel: (604) 576-7349

Fax: (604) 576-7074

www.fortisbc.com

Regulatory Affairs Correspondence Email: [email protected]

Dennis Swanson

Director, Regulatory Affairs

FortisBC Inc.

Suite 100 – 1975 Springfield Road

Kelowna, BC V1Y 7V7

Tel: (250) 717-0890

Fax: 1-866-335-6295

www.fortisbc.com

Regulatory Affairs Correspondence

Email: [email protected]

B-1

http://www.fortisbc.com/

mailto:[email protected]



markhuds

FEI FBC PBR-Reconsideration Phase-1 Stamp

October 3, 2014 British Columbia Utilities Commission Multi-Year Performance Based Ratemaking Plans for 2014 through 2019 Decisions FortisBC Request for Clarification and Reconsideration and Variance

REQUESTS FOR CLARIFICATION

FortisBC requests clarification of the following four items:

FEI Pages FBC Pages Description Clarification Required

1. 111 to 112 107 to 108 The Commission denies FBC’s request to establish, and orders FEI and FBC to discontinue, certain deferral accounts, but establishes that the actual expenditures for these items should be flowed-through to customers.

FortisBC is seeking clarification of the order, as the order issued appears to run counter to the Commission's stated objective.

2. 107 and 124 104 and 120 The Commission rejects FortisBC’s proposal to apply the 50/50 Earnings Sharing Mechanism (ESM) to any of the flow-through revenues/costs and directs that the ESM mechanism is not to be applied to flow-through items, but accepts FortisBC’s proposed ESM. Since FortisBC’s proposed ESM is designed as a 50/50 sharing of variances in the ROE (which is affected by variances in any items that are not subject to deferral), these two determinations are again mutually inconsistent.

FortisBC seeks confirmation that the Commission’s direction is that variances in ROE are subject to earnings sharing.

3. 122 119 The Commission approves Growth Terms, stated as: 0.5 * (SLAt-1/SLAt-2) for FEI’s growth capital, and 0.5 * (ACt-1/ACt-2) for all other cases. Application of the formulae as stated would result in O&M and capital under the formula being reduced by approximately one-half.

FortisBC seeks confirmation that the O&M and capital formulae were stated in error and that the intention was to only reduce the Growth Term by one-half and not to reduce the entire spending envelope by one-half.

4. 132 and 185 128 and 179 The Commission sets out the steps that are required for FortisBC to receive approval of an Efficiency Carryover Mechanism (ECM) initiative in two different sections of the Decisions. The descriptions differ and would have a different result.

FortisBC seeks clarification that the description as provided in the Annual Review process section of the Decisions is the correct one.

FortisBC submits that all of these matters are matters of clarification, rather than reconsideration or variance, because they address ambiguous or internally inconsistent portions of the Decisions. In the event that the Commission holds a different view as to whether these can be addressed as an issue of clarification, FortisBC respectfully requests that these four items also be made part of the application for reconsideration and variance of the Decisions also included in this filing. FortisBC discusses each of the requests for clarification in greater detail below.

1. Mechanism to Flow Through Variances in Uncontrollable Items

The Commission Panel has ordered that the following deferral accounts either be discontinued (if they previously existed) or not be approved (if they did not previously exist):


Tax Variance – to capture impacts of changes in tax laws or accepted assessing practices and audit reassessments, among other items;

Insurance Expense Variance – to capture variances in insurance premiums;

Property Tax Variance – to capture variances in property taxes;

Interest Expense Variance – to capture impacts of short-term and long-term interest rate variances, and variances in volume and timing of long-term debt issues;

Revenue Variance (FBC only) – to capture variances in sales revenues, the majority of which are attributable to weather related load variances, customer usage rate variances and customer count load variances; and

Power Purchase Expense Variance (FBC only) – to capture variances between forecast and actual power purchase expense and water fees.

The Commission Panel makes the following statements in the Decisions:

“The Panel notes that the denial of these deferral accounts does not impact the determination that the actual expenditures of these items should be flowed-through to customers (see previous section in this Decision). In order to reflect in rates the actual costs related to these flow-through items as close as possible to the period in which they were incurred, the Commission Panel directs FBC to true-up these costs each year. Finally, the Panel also clarifies that these flow-through items should be applied first, and then a calculation of the earnings sharing mechanism will follow. This is the same treatment as conducted by FBC in its last PBR.”1

The issue that FortisBC perceives to arise from the Decisions in this regard may be rooted in a misunderstanding of the information that the Commission was seeking in the oral argument phase, the agenda for which included the question: “Are these deferral accounts necessary?” FortisBC provided substantial oral submissions setting out the factual background to four of the above deferral accounts and addressing the concept of deferral accounts (e.g., in terms of the objectives that deferral accounts are intended to accomplish), but not targeted to the specific point that, in retrospect, we appreciate the Commission may have been focused on: namely, whether a deferral account is necessary where flow through treatment is provided for. Commissioner Morton fairly raised that specific point during the course of the oral argument phase, and FortisBC responded (as outlined below), but without the detailed support that it would have provided either at the hearing or by way of follow-up filing had it realized that was the crux of the agenda item. On page 1372 of the Transcript Volume 8 from the oral argument phase, the following exchange occurred:

THE CHAIRPERSON: So when you say you gather – are you saying that FortisBC’s interpretation of being approved or having those expenses approved as flow-through expenses, does FortisBC then interpret that as an approval to establish a deferral account to flow those expenses through? Is that what you’re saying?

1 FBC Decision page 108 and FEI Decision page 112.


MS. HERBST: I’ll check. I’m not sure that would be the case in all circumstances. I believe that was the practice within the context of the 2007 plan. THE CHAIRPERSON: Yes, please. MS. HERBST: But if I may have a moment I can check that. THE CHAIRPERSON: Sure, please do. Thank you. MS. HERBST: Yes, Mr. Chair, and thank you for the opportunity to consult. That was the mechanism that was used where there was a variance that needed to be flowed through[:] a deferral account - - was used. And I’m not sure that there would be another mechanism that would be envisioned if that approval was given…

In light of what the Commission may have been seeking to determine through its agenda item, this response may not have provided the detail required. The points below are based on extensive consultation with FortisBC’s finance. First, based on the first sentence in the quote from the Decisions, above, FortisBC understands the Commission Panel’s intention to be that amounts that would otherwise have been captured in the six deferral accounts listed above would no longer be captured in these specific deferral accounts, but that the amounts would still be flowed-through to customer rates. The directive that “these items should be flowed-through” and “to true-up these costs”, in absence of a mechanism that would allow FortisBC to do so,, is inconsistent. In order for the amounts to be flowed-through, some deferral mechanism is required – either the different deferral accounts requested or a single deferral account to capture all of the flow-through amounts collectively. In the absence of such deferral accounts, the variances would flow through earnings in the year incurred and would impact the Companies’ Return on Equity (ROE). Accounting guidance requires the Commission approval of a deferral account to capture variances and then recover or refund the balance in the deferral account to customer rates in the following year(s). Without this approval, the variances will impact earnings, and earnings sharing, which is contrary to the Commission’s express intent (that the items be flowed through before calculation of the earnings sharing). The explicit Commission approval to flow through costs by way of deferral accounts, also known as regulatory assets and liabilities, is also required for external financial reporting. Absent this approval, FortisBC would see significant variances and volatility in its financial results for financial reporting as compared to regulatory reporting which would run counter to the purpose behind FortisBC’s adoption of US Generally Accepted Accounting Principles (US GAAP) for regulatory purposes, which was approved pursuant to Commission Order G-83-14. Second, in the last sentence in the quote above, the Commission indicated its expectation that this directive was consistent with what was done in FBC’s prior PBR plans. However, FortisBC’s proposal for deferral treatment, which the Commission appears to have rejected for the flow-through items, would have been the same treatment as conducted by both FEI and FBC in their last PBR Plans. Although the presentation of the items differed, the end result was the same. For both Companies, any variances between actual and forecast for the items subject to deferral treatment were excluded from the calculation of the ESM. This


is because they were captured in deferral accounts, and items captured in deferral accounts do not directly impact earnings or ROE. The treatment followed by FBC in its previous PBR Plan was to accumulate the variances between actual and forecast in a given year in a single deferral account balance and record this balance on the deferred charges schedule as “flow-throughs”. This flow-through balance was classified in deferred charges and approved each year to be recovered from or refunded to customers in the subsequent year(s). This previously followed treatment results in the same treatment that FBC and FEI proposed in their Applications, however, the Companies had proposed using multiple deferral accounts rather than a single deferral account. Third, FEI requires an Earning Sharing deferral account to flow through to customers any result of the ESM. FEI had anticipated requesting approval of an Earnings Sharing deferral account at its first Annual Review which it anticipated would occur in the fall of 2014. Given the timing of the Decisions, the first Annual Reviews are now expected to occur early in 2015, and the Companies will need to calculate and record the earnings sharing amounts, if any, in 2014. Therefore, the Earnings Sharing deferral for FEI will need to be approved in advance of the first Annual Reviews. (FBC has already received approval of its Earnings Sharing deferral account in Order G-139-142). In conclusion, if the Commission’s expressed intent of flowing through amounts to customers is to be accomplished for 2015, then FEI and FBC require the approval of a Flow-Through deferral account and FEI requires the approval of an Earnings Sharing deferral account, before the end of 2014. The approval of these deferral accounts would also be consistent with the Commission’s statement quoted above, namely that “This is the same treatment as conducted by FBC in its last PBR.”

2. Calculation of the Earnings Sharing Mechanism

The ESM as proposed by FortisBC is a calculation based on the variance in earnings, or ROE, between approved and achieved. This is consistent with the calculation of ESM in FEI’s and FBC’s prior PBR Plans. In its Decisions, the Commission approved the inclusion of a symmetrical ESM. The FBC Decision, for example, stated on Page 225:

“The Commission Panel approves FBC’s proposal to establish an ESM deferral account. The Commission Panel considers the use of this deferral account to be an appropriate mechanism for refunding or recovering from customers the 50 percent of amounts above or below the approved ROE.”

Also in the FBC Decision, on page 104, the Commission stated:

“The Commission Panel rejects Fortis’ proposal to apply the 50/50 ESM to any of the flow-through revenues/costs and directs that the ESM mechanism is not to be applied to flow-through items.”

2 FBC Decision page 225.


Throughout the evidence, FortisBC used the term “flow-through” to describe any items that were not subject to the O&M and capital formulae, meaning that they would be flowed through on a forecast basis. Certain elements of the items that are flowed through each year on a forecast basis are subject to deferral, or true-up, based on variances between forecast and actual. FortisBC provided a list of items under the heading “Flow-Through Expenses” in Section 6.3.2 of its Applications3, with the following sub-headings:

Interest Expense

Return on Equity

Taxes

Pension and OPEB Expenses and Insurance Costs

Power Purchase Expense

Revenues

Depreciation and Amortization

Rate Base other than Gas Plant in Service

Further description was provided under each of these sub-headings that set out which elements of the sub-headings were subject to deferral or true-up. For example, variances between actual and forecast for certain components of Interest Expense would be recovered from or refunded to customers, while the variances between actual and forecast Depreciation would affect achieved ROE and would be subject to the ESM. FortisBC agrees that the deferred or trued-up items should be excluded from the calculation of the ESM, since it is the actual costs that are ultimately paid by customers. However, all of the items that are flowed through or re-forecast each year should not be excluded from the calculation of the ESM. Specifically, the Commission has identified that industrial delivery revenues for FEI, rate base other than Plant in Service for FEI and FBC4, and AMI and PCB compliance costs for FBC5 should be excluded from the ESM. The impact of excluding these items (and all other re-forecast items) from the calculation of the ESM would be that the Companies would retain 100% of the variance between forecast and actual for these items, in the same manner as would occur under a cost of service regime. The result would be that it is not the variance in ROE that is shared, but rather only the ROE impact of the variance in O&M and capital under the formula. FortisBC seeks clarification of the Commission’s intent given the conflict between the acceptance of FortisBC’s proposed ESM, and the Commission’s exclusion from the ESM of items that are flowed-through on a forecast basis. Specifically, FortisBC seeks confirmation that the Commission approves the ESM as proposed by FortisBC which is designed as a

3 FEI Exhibit B-1, pages 68 to 70 and FBC Exhibit B-1, pages 61 to 63.

4 FEI Decision page 107 and FBC Decision page 104.

5 FBC Decision page 210.


50/50 sharing of variances in the ROE, which is affected by variances in any items that are not subject to flow through treatment via a deferral account.

3. Correction of Growth Term in the O&M and Capital Formulae

The Growth Term has been determined by the Commission Panel to be: 0.5 * (SLAt-1/SLAt-2) for FEI’s growth capital, and 0.5 * (ACt-1/ACt-2) for all other cases. FortisBC believes that there is a typographical error in this formula that has significant unintended ramifications if left as stated. Using the second formula (all other cases) as an example for FEI, application of this Growth Term results in the following Sustainment and Other or Remaining Capital (RC) formula (replacing t-1 with t, and t-2 with t-1 to be consistent with FortisBC’s proposal in order to isolate the impact of the one-half reduction):

[ ( )] (

)

Applying this formula to the proposed 2013 Base for Sustainment and Other Capital for FEI (assuming all of the other formula variables are the same as applied for) results in the following calculation:

[ ( )] (

)

That is, the 2013 Base is reduced from $101,043 thousand to $51,728 thousand, effectively a reduction of the entire capital expenditure by one-half, and a reduction in total formula-driven O&M and capital spending for FEI from $321,692 thousand to $164,705 thousand6. A reduction of this magnitude means that the Companies would be unable to meet their requirements to maintain a safe and reliable system and maintain their service quality commitments. FortisBC would be unfairly penalized by any spending above the formula-driven envelope, because there would be no return of or on this required spending. The result would, in effect, violate the fair return standard by a considerable margin on any reasonable assessment. FortisBC does not believe this was the result that the Commission intended. The proper application of the formula that results in a one-half reduction of the Growth Term instead of a one-half reduction of the entire capital spending envelope would be: [1 + ((ACt-1 -

ACt-2)/ACt-2) x 50%)]. Applying this formula results in the following capital formula:

[ ( )] [ {([ ]

) }]

6 The overall reductions are much greater than this. Applying the formulae as written results in a reduction of

growth capital from $$21,881 thousand in 2013 to $11,225 thousand in 2014, and a reduction in O&M from $198,768 thousand in 2013 to $101,757 thousand in 2014.


The following numerical calculation is the result when applied to the proposed 2013 Base for Sustainment and Other Capital.

[ ( )] [ {([ ]

) }]

That is, Sustainment and Other capital increases from $101,043 thousand in 2013 to $103,170 thousand in 2014 (which is $286 thousand less than when calculated using the full growth factor). This same situation of a reduction by almost one-half of the entire spending envelope arises when the Commission’s Growth Term is applied to Growth Capital and to O&M. FortisBC requests that the Commission confirm that the Growth Term for FEI’s growth capital should have been stated as [1 + ((SLAt-1 - SLAt-2)/SLAt-2) x 50%)] and FortisBC’s Growth Term for all other cases should have been stated as [1 + ((ACt-1 - ACt-2)/ACt-2) x 50%)].

4. Approval of Efficiency Carryover Mechanism Initiatives

Page 132 of the FEI Decision and page 128 of the FBC Decision set out the Commission Panel’s determination regarding what is required as part of the Annual Review process to receive approval for an ECM initiative. It states:

“For each proposed initiative for which the benefits are expected to extend beyond the term of the PBR, Fortis will file an ECM proposal providing a description of the proposal, its timing, costs and benefits, and reasoning as to why it is appropriate and how long benefits should be paid.” [emphasis added]

Page 185 of the FEI Decision and page 179 of the FBC Decision then describe what is included in the Annual Review process, of which one of the items is:

“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…” [emphasis added]

These two statements are internally inconsistent in the way they have been articulated. Only the statement that appears on page 185 of the FEI Decision and page 179 of the FBC Decision is appropriate in the context of the purpose of an ECM. The vast majority of initiatives that FortisBC undertakes are expected to have benefits extending beyond the term of the PBR, but not all of them will achieve payback within the PBR plan period. Since these directives are regarding the ECM, which is intended to incent investments in initiatives that have a payback beyond the end of the PBR plan period, FortisBC requests that the Commission Panel clarify that the requirement to be met to bring forward a request for ECM for consideration is that the efficiency initiative requires a “payback period” extending beyond


the PBR plan period as stated on page 185 of the FEI Decision and page 179 of the FBC Decision, and not simply “benefits” extending beyond the PBR plan period.

APPLICATION FOR RECONSIDERATION AND VARIANCE

As stated above, FortisBC seeks reconsideration and variance under Section 99 of the Utilities Commission Act of three determinations in the Decisions and Orders G-138-14 and G-139-14. The basis for reconsideration in each case is that the Commission made errors in fact and drew conclusions that have no basis in the evidence. As described below, each of these errors would have material implications. As reflected in the Reconsideration and Appeals section of “Understanding Utility Regulation: A Participant’s Guide to the B.C. Utilities Commission,” the Commission’s default process for addressing reconsideration applications is to proceed in two phases. FortisBC submits that in the present circumstance, it has established a prima facie case sufficient to warrant a full reconsideration, and that due to the limited nature of the reconsideration requests and evidence, the Commission can combine the two phases and allow the information provided below to stand for both phases. The three items for reconsideration are set out below.

1. Use of Prior Year Actual Growth Term

FortisBC is seeking reconsideration of the Commission’s determination to use the prior year actual customer growth in the capital and O&M formulae. This determination was based on a mistake of fact and would have the material impact of not allowing FortisBC to recover its prudently incurred cost of adding customers. The Commission’s determination to use the prior year actual customer growth in the capital and O&M formulae was made on page 122 of the FEI Decision, as follows:

“Given the lack of evidence concerning the quantum of the required adjustment, the Panel applies its best judgement and directs that the Growth Term be reduced by 50 percent. Further, to eliminate the possibility of potential bias, the Panel directs that the ratio be calculated as the ratio of the number customers [sic] or service line additions one year previous, to the number of customers or service live [sic] 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.”

The Commission’s finding that there was a potential of upward bias is found on page 122 of the FEI Decision and page 118 of the FBC Decision, where the Panel concludes its evaluation of the Growth Term as follows:

“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.”

This statement is not an accurate summary of FortisBC’s evidence for two reasons. First, regarding there being no opportunity for true-up, FortisBC had stated in its Applications7 that formula amounts are subject to true-up going forward for actual customer growth. This was further explained in the response to BCUC IR 3.6.3 in FEI’s Exhibit B2-8, and in the following excerpt from Transcript Volume 2, page 237, lines 6 to 9:

“This growth factor is reforecast each year based on the same forecasting methods used to forecast demand, and in fact, the prior year’s actual is actually trued up.”

Since the customer growth factor is trued up for actuals, there is no compounding of any variances between forecast and actual customer counts. The impact of any variance is limited to the upcoming forecast year. Second, regarding the potential for bias in overestimating customer counts, the evidence demonstrates that no such bias exists. Since FortisBC utilizes the same customer count forecasts for its revenues as it does for its O&M and capital formulae, bias could only exist if there was a benefit to be gained by overestimating both revenue and O&M/capital. FEI has demonstrated in its Appendix E5 (Exhibit B-1-1) and summarized on pages 114 to 116 of FEI’s Application that this is not the case, i.e. that variances in customer additions do not have a significant impact on earnings. Under the PBR Plan as proposed in the Application, an overestimate of customer additions would lead to higher O&M and capital amounts under the formula but this same overestimate would also result in higher forecast revenues. These would have offsetting impacts to the annual revenue requirements. Finally, it is incorrect to draw a correlation between customer growth from the prior year and current year costs. Costs are driven by the actual growth experienced, particularly for the growth capital formula. This is clear because under cost of service, or a traditional price cap or revenue cap per customer plan8, it is the current year’s growth in customers and associated volumes that are incorporated into the PBR formula. There is no lag in obtaining required revenues to address growth in the customer base. This is described by Mr. Bell in testimony in Transcript Volume 6, page 1305, lines 20 to 25:

MR. GHIKAS: Q: Okay. And as the customer base grows, the gas utility is allowed to increase its overall revenue collection by this per customer amount, as adjusted by the I minus X formula, for each new customer that is added, correct? MR. BELL: A: That is correct.

7 FEI Exhibit B-1, page 81 and FBC Exhibit B-1, page 73.

8 FEI and FBC Exhibits B-44, page 8 Rebuttal Evidence to Mr. Russ Bell in describing Alberta’s revenue cap per

customer plan: As the customer base grows, the gas utility is allowed to increase its overall revenue collection by this per customer amount (as adjusted by the I-X formula) for each new customer that is added.


As quoted above, the Panel found that “some lag into the formula calculation” was “necessary in order to eliminate the potential of upward bias.” However, for the reasons described above, there is no potential for upward bias. As such, there is no justification for the introduction of any lag in the recovery of FortBC’s prudently incurred costs of adding customers. In light of this evidence regarding the Growth Term, FortisBC seeks a reconsideration and variance of the Commission’s determination to use the prior year actual customer growth in the capital and O&M formulae. FortisBC requests the Commission reconsider and vary the Decisions to instead approve the calculation of the Growth Term using forecast growth (reduced by one-half as determined by the Commission in its Decisions), and trued up in subsequent years to reflect actual customer growth.

2. Uniform System of Accounts

Regarding the Commission’s determination on adoption of the USoA for FEI, FEI submits that there is just cause to reconsider and vary Order G-138-14 in the circumstances because adoption of the USoA will not result in the benefits anticipated by the Commission (refer to page 248 of the FEI Decision). Namely, the FEI Decision indicates that adoption of the USoA would result in consistent and comparable information over time, and that the comparison of forecast to actual results at the account level that “would be more transparent, reduce the number of IRs and increase efficiency” in future RRAs and “may also assist the bench marking study by increasing the comparability of FEU’s reporting with other jurisdictions that use the USoA.” As discussed below, FEI respectfully submits that the evidence on the record does not support the conclusion that these benefits will follow from adoption of the USoA. For ease of reference, FEI has provided the full evidence regarding the USoA from the proceeding record as Attachment 1 to this filing. This includes its USoA Compliance Filing and associated responses to Information Requests (Exhibits A2-13 to A2-15), and FEI’s responses to the second round of BCUC Information Requests series 308 and 309 (Exhibit B-24).

Adoption of the USoA would not Result in more Transparent or Granular Analysis

The FEI Decision mistakenly appears to suggest that adoption of the USoA would enable FEI to provide more granular or transparent analysis of forecast to actual results in future RRAs. The evidence shows that this is not the case. FEI will not be able to use the USoA for forecasting purposes in future RRAs, as suggested on page 248 of the FEI Decision. As stated in response to BCUC IR 2.308.9, “As is the case with both FBC and BC Hydro, FEU would be unable to include this BCUC USoA view in the body of its RRAs since there would be no drilldown capability or specific management responsibility for the resulting line items.” This means that forecasting in future RRAs cannot follow the USoA, as expected on Page 248 of the Decision.


Further, future IR responses will not be any more informative after adoption of the USoA. The FEI Decision appears to anticipate that FEI would be able to track more granular information using the USoA. Page 247 of the FEI Decision states:

“In response to IRs on the USoA Compliance Filing, FEU stated that its unable to track customer education costs Employee Expenses, Fees and Administrative Costs (this includes advertising costs), and Legal Fees and Retainers through FEU. Furthermore, FEU stated that “If there is a requirement to know the total costs (O&M and capital) at this level of detail, it can be provided in information requests. (Exhibit A2-15, BCUC 6.0, 8.0)” “

This, however, is not a correct recapitulation of the evidence. In fact, the FEU stated that they do indeed track Employee Expenses, Fees and Administration Costs, and Contractor Costs (including legal fees and retainers) in its New Code of Accounts, using resource codes.9 FEU also stated that the further details requested in the IR (newspaper vs. television vs. radio advertising, website vs. social media, direct mail, bill inserts, printed matter, display materials for exhibits, decals for CNG and LNG, advertising on transit vehicles, bus shelters, bill boards, posters, stadium and building advertising) is not available in the New Code of Accounts but that such information could be provided if required. FEI did provide seven years of history for the amounts recorded for Communications – Public Relations, Communications – Employees, Advertising – Media, Advertising – Printed Matter, and Miscellaneous Advertising in response to BCUC IR 1.188.2 (Exhibit B-1-5). What the quote above from the FEI Decision does not capture is that this more detailed information that is not tracked in the New Code of Accounts is also not tracked in the USoA. In the USoA, the listed items would likely be included under one of the following accounts but the detail would not be reported at the lower level:

701 Advertising – This account shall include the cost of labour, supplies and expenses incurred in advertising, which is designed to promote or retain the use of utility service.

709 Other Sales Promotion Expense – This account shall include the cost of labour, supplies and expenses incurred in connection with sales activities, except merchandising, which are not includible elsewhere.

719 Other Customer Accounting Operations – This account shall include the cost of labour, supplies and expenses incurred in customer accounting not includible elsewhere.

721 Administrative Expense – This account shall include the cost of salaries, supplies and expenses incurred in connection with the general administration of the company, which are assignable to specific executive, administrative and general departments and are not chargeable to a specific operating function. (Note that employee expenses are listed as an example of the types of expenses included here, but only if not applicable to a specific operating function).

722 Special Services – This account shall include the fees and expenses of professional consultants and others for general services not applicable to a particular

9 See response to BCUC IR 8 from the USoA Compliance Filing.


operating function. (Note that legal consultants are listed as an example of the types of services included here, but only if not applicable to a specific operating function).

Therefore, the USoA does not require that these items be tracked separately. Adopting the USoA will not result in this further more detailed information being provided as compared to the New Code of Accounts.

Also, the FEI Decision appears to suggest that FEI would be able to provide more comparable information if it had adopted the USoA. Page 247 of the FEI Decision states:

“In the current proceeding, FEI was unable to provide five-year comparable information in BCUC 1.81.2, 1.101.1, 1.110.1, 1.127.3, 1.129.1, 1.137.2, 1.138.2, and other IRs (Exhibit B-11). In addition, states it was unable to provide comparable 2010-2013 O&M due to “different set of accounting classifications between O&M and capital”, changes in set of circumstances and organizational changes (Exhibit B-8, CEC 1.60.1).” ”

As FEI had stated in its evidence, the adoption of the BCUC USoA for O&M will not resolve these issues. In support of this, the response to BCUC IR 2.309.1 is reproduced below. BCUC IR 2.309.1 asked “Given that FEI was unable to provide 5-year comparable information in BCUC 1.81.2, 1.101.1, 1.110.1, 1.127.3, 1, 1.129.1, 1.137.2 1.138.2, and other IRs please explain why FEU should not be directed to comply with Directive 63 from the 2012-2013 FEU Decision requiring “FEU to fully adopt the USoA.”?”

“Response: FEI did provide the information in the referenced IRs with the proviso that, in some cases, the information was not comparable. The reasons that it was not comparable included:

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. Organizational 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. Had FEI adopted the USoA for O&M, the information would not have been any more comparable than it currently is. A different method of grouping costs does not change the fact that accounting policies have changed to required capitalization differences, or that data that was previously captured at a higher level cannot be retroactively split to a lower level without considerable estimation which makes the data unreliable, or that there have been changes in the environment that drive costs and make O&M costs from 2007 not comparable to O&M costs from 2014. FEI is concerned that there is a misunderstanding about what the outcome of adopting a different USoA would be, and that there is an expectation it will resolve all comparability problems. This is not the case.


In FEI’s view, adopting the USoA provides no incremental value and will tie up the utility’s resources in a project, potentially incur incremental external costs, and require a reconciliation process each year. FEI will not be able to provide accurate responses to questions on the resulting accounts since much of the data would be created through a judgement-based allocation process. …

Based on the original report and the analysis and discussion provided in response to the BCUC IR 2.308 series, the FEU submit that the Commission should determine that it is in customers’ best interests that the FEU continue with its existing approach of the New Code of Accounts.” [Emphasis added.]

Contrary to the conclusions of the Commission, the evidence is that FEI will not be able to provide more comparable information using the USoA. Moreover, if FEI adopts the USoA FEI will not be able to provide accurate responses to questions on the resulting accounts since much of the data would be created through a judgement-based allocation process.

Adoption of the USofA would not Result in Fewer IRs

FEI also submits that there is no evidence that adoption of the USoA will result in fewer IRs. The Panel’s support for this conclusion appears to be drawn from the CEC’s comments at the procedural conference, as paraphrased by the Commission in the FEI Decision on page 245, as follows:

“At the September 5, 2013 Procedural Conference the CEC stated that “[if] the application satisfied the needs of Staff and interveners, there probably wouldn’t have been as many IRs” and that the “application is not as comprehensive as expected, and that the analysis and empirical evidence needs to be improved” (T1:60)

There is no evidence, however, that the CEC’s comments had been directed towards the historical O&M schedules provided in Appendix F6 (Exhibit B-1-1), which are the only ones that are affected by the USoA. Furthermore, the CEC had not taken issue with the FEU’s reporting in the proceeding. As quoted in the FEI Decision at page 248:

“FEI stated that…no customer groups have taken issue with FEU’s current reporting…The Company also noted that there was a lack of interest from interveners and that “there were no intervener submissions on the topic of the BCUC Uniform System of Accounts.””

There is no evidence on the proceeding record that would support the conclusion that adoption of the USoA will reduce the number of IRs, nor is that a logical inference.

Adoption of the USoA may not Assist in the Bench Marking Study

Although the USoA is similar to those in place in Ontario and Alberta10, having the same accounts will not assist in benchmarking if the items captured in each account differ. This

10

Page 11 of the USoA Compliance Filing.


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. The adoption of the USoA will not assist in reconciling these differences.

Adoption of the USoA would not Result in Increased Efficiency

The FEU also respectfully submit that there is no evidence that adoption of the USoA will result in increased efficiency. Rather, the opposite is likely to occur. As discussed above, the USoA will not result in more transparent or granular information or the ability to provide more comparable information. The USoA was created in 1961 and has not kept up with developments in the industry and does not contain current business descriptions. As stated in the USoA Compliance Filing at page 12:

“Although big buckets can be expected to remain fairly static over time (distribution, transmission, general operations and administration), specific O&M categories within those buckets reflect changes in technology, changes in management and changes in reporting relationships within the utility, and can change over time. The 1961 BCUC USoA for O&M accounts no longer reflects how each utility operates its activities.”

As the FEU stated in response to BCUC IR 2.308.9:

“If the Commission directed the FEU to follow the BCUC USoA for O&M despite any evidence of the benefits that would be obtained, then the FEU believe the Commission has a responsibility to first review and revise the USoA from 1961 to bring it more up to date and in line with the way utilities currently manage their business so that at least some value would be provided to ratepayers.”

Since this issue has not been addressed in the FEI Decision, FEI respectfully requests that if the Commission does not vary its Decision, that the Panel direct Commission staff to work collaboratively with FEI in making modifications to the 1961 USoA to bring it into compliance with more recent developments in the industry. While this approach is not as efficient as simply maintaining the existing New Code of Accounts, it would at least make the alternative workable from a practical perspective.

Conclusion on the USoA

FEI respectfully requests that the Commission reconsider and vary its determination to adopt the USoA. While FEI understands that a standardized approach to accounting policies may appear on the surface to be attractive, in the circumstances of British Columbia and FEI in particular, the evidence is clear that the benefits that the FEI Decision concludes will result from adoption of the USoA will not materialize, but rather will result in material expenditures for no benefit. FEI requests that the Commission reconsider the evidence on the record and vary the FEI Decision by making the determination that continuing with FEI’s New Code of Accounts is in the best interest of ratepayers.


3. Biomethane Application Costs

FEI is also seeking reconsideration of the Commission’s determination to include the 2012 Biomethane Application costs in the Biomethane Variance Account (BVA). As explained below, this determination was made based on an incorrect characterization of these costs and would have a material adverse impact on the Biomethane Program. On page 238 of the FEI Decision the Panel concludes, in its evaluation of the 2012 Biomethane Application costs, as follows:

“In the 2013 Biomethane Decision, the Commission directed “all interconnection and Biomethane program Costs are to be recovered in the BVA along with the cost of supply. Recording these costs in the BVA provides FEI with the opportunity to recover all of the Biomethane Program costs from biomethane customers.”

The characterization of these Application costs as being Biomethane Program costs is not accurate and as such, FEI respectfully requests that the Commission reconsider and vary its determination to record these costs in the BVA. In the Decision attached to Order G-210-13 on the 2012 Biomethane Application, on page 46, the Commission specifically defines Biomethane Program Overhead Costs as costs including education, marketing, direct administration, cost of enrollment and the cost of IT upgrades. The Commission states:

“For clarity, in the Decision, the Panel will refer to “Biomethane Program Overhead Costs” as including education, marketing, direct administrations costs of enrollment and the cost of IT upgrades.”

Furthermore, on page 70 of the same decision, the Commission provides a table outlining the costs to be included in the Biomethane Variance Account (BVA) and this table does not identify generic application costs. This table is reproduced below for reference:


Table 5 Biomethane Service Offering Cost Recovery Model- Going Forward

Biomethane variance account (BVA)

Cost of procuring biogas Biomethane Customer

Cost of upgrading Biomethane Customer

Interconnection costs including the pipe Biomethane Customer shared with Supplier based on Interconnection Test

Biomethane Program Overhead Costs Biomethane Customer

LESS

REVENUES collected through BERC rates Biomethane Customer

= Variance may be transferred to MCRA for recovery from all non -bypass customers

and the BPDA on the terms directed by the Commission Panel

MCRA/UBPDA COST RECOVERY MECHANISM

Variance from BVA due to difference between cost of supply and selling price

Final method for the cost recovery of Biomethane that cannot be sold at the BERC rate, or cannot be sold at all

Subject to a separate BCUC approval

FEI therefore submits that the Commission’s FEI Decision contradicts its prior Order G-210-13, which had not contemplated that 2012 Biomethane Application costs be included in the BVA. In addition, inclusion of these costs in the BVA for cost recovery from only biomethane customers is inconsistent with the approved treatment for similar types of applications. While the 2012 Biomethane Application costs in question are clearly connected to the biomethane service offering, the purpose of the 2012 Biomethane Application was to review the continuation and potential modifications to the program and impacts on all customers. That is, Order G-210-13 considered the interests of all customers and whether this service offering should be provided. The 2012 Biomethane Application costs should, therefore, be shared by all customers consistent with the approved regulatory treatment for similar application costs such as the AES Inquiry Application Costs (Order G-44-12 and G-201-12) and NGV for Transportation Application Costs (Order G-128-11) and the Customer Choice Program11 (Order G-25-04 and Order C-6-06). Finally, it should also be noted that due to the longer than expected regulatory review process, largely driven by the additional five separate public processes12 that were ultimately

11

Referred to as Commodity Unbundling in the Order and Decisions; the name of the program has since changed to Customer Choice.

12 Inquiry into Biogas Supplier Exemption process, Biomethane Third-Party Suppliers process, Section 71 Purchase Agreement with GSV&DD process, Reconsideration of Order G-29-13 Regarding Supply Risk process, as well as submissions on the CPCN threshold


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. 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. To be consistent with Order G-210-13 regarding the costs to be included in the BVA and the approved regulatory treatment of similar application costs, the 2012 Biomethane Application costs should be recovered from all non-bypass FEI customers as proposed in Exhibit B-1, p. 296.

2014 RATES

FortisBC anticipates filing for permanent 2014 rates in the upcoming weeks based on the Decisions and Orders G-138-14 and G-139-14. If there is an impact to the 2014 rates as a result of the Commission’s ultimate determinations with respect to the items contained in this filing for which clarification and reconsideration and variance is sought, FortisBC will calculate the 2014 revenue requirement impact and propose a method to address it in the upcoming Annual Review processes that will determine 2015 rates. If further information is required, please contact the undersigned. Sincerely, FORTISBC ENERGY INC. and FORTISBC INC. Original signed by: Diane Roy

For: Diane Roy and Dennis Swanson Attachment cc (email only): FEI and FBC PBR Registered Parties

ERICA HAMILTON COMMISSION SECRETARY

[email protected] web site: http://www.bcuc.com

SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC CANADA V6Z 2N3

TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

Log No. 44029

PF/FEI/PBR 2014-2018/A2-13-FEU-BCUC Uniform System of Accounts Report

VIA EMAIL [email protected] October 23, 2013

FORTISBC ENERGY PERFORMANCE BASED RATEMAKING

REVENUE REQUIREMENTS 2014-2018 EXHIBIT A2-13 Ms. Diane Roy Director, Regulatory Affairs FortisBC Energy Inc. 16705 Fraser Highway Surrey, BC V4N 0E8 Dear Ms. Roy:

Re: FortisBC Energy Inc. Project No. 3698715/Order G-99-13

Application for Approval of a Multi-Year Performance Based Ratemaking Plan for 2014 through 2018

Commission staff submits the following document for the record in this proceeding: FortisBC Energy Utilities – BCUC Uniform System of Accounts Report. Yours truly, Erica Hamilton SS/dg Enclosure cc: Registered Interveners (FEI-PBR-2014-18-RI)


October 10, 2012 British Columbia Utilities Commission 6th Floor, 900 Howe Street Vancouver, BC V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: Re: FortisBC Energy Utilities1 (“FEU”)

2012 and 2013 Revenue Requirements and Natural Gas Rates Application (the “2012-2013 RRA”) - British Columbia Utilities Commission (“BCUC” or the “Commission”) Decision dated April 12, 2012 and Order No. G-44-12 (the “Decision”)

BCUC Uniform System of Accounts (“USoA”) Report

On May 4, 2011, the FEU filed their 2012-2013 RRA. After a comprehensive regulatory review process including an oral public hearing, on April 12, 2012, the Commission issued its Decision. On pages 141-142 of the Decision, and in Appendix A, page 11, Summary of the Commission Panel’s Directives, item no. 63, the FEU were directed to investigate the cost of fully converting to the BCUC USoA and to file a proposed plan for conversion. Attached please find a Report on the USoA. If you require further information or have any questions regarding this submission, please contact the undersigned. Yours very truly, on behalf of the FORTISBC ENERGY UTILITIES Original signed:

Diane Roy Attachment

1 Comprised of FortisBC Energy Inc., FortisBC Energy (Vancouver Island) Inc., FortisBC Energy (Whistler) Inc.,

and FortisBC Energy Inc. Fort Nelson Service Area.

Diane Roy Director, Regulatory Affairs - Gas FortisBC Energy Inc.

16705 Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) 576-7349 Cell: (604) 908-2790 Fax: (604) 576-7074 Email: [email protected] www.fortisbc.com Regulatory Affairs Correspondence Email: [email protected]

A2-13













dguest

FEI-2014-2018RR

FortisBC Energy Inc.

BCUC Uniform System of Accounts Report

October 10, 2012

FORTISBC ENERGY INC. BCUC UNIFORM SYSTEM OF ACCOUNTS REPORT

Page 2

Table of Contents

1 INTRODUCTION .................................................................................................................. 3

2 THE FEU’S PROPOSAL TO ADOPT THE UNIFORM SYSTEM OF ACCOUNTS .............. 5

3 BACKGROUND ON THE BCUC UNIFORM SYSTEM OF ACCOUNTS .............................. 5

4 THE O&M SECTION OF THE USOA ................................................................................... 6

4.1 Objectives of USoA for O&M .................................................................................. 8

4.2 Comparisons of BCUC USoA for O&M .................................................................10

4.2.1 BCUC USoA for O&M versus New Code of Accounts ..................................10

4.2.2 BCUC USoA for O&M vs. other USoAs for O&M ..........................................11

4.3 Conclusion on BCUC USoA for O&M ...................................................................12

5 IMPLEMENTATION PLAN TO MEET BCUC OBJECTIVES ..............................................13


Page 3

1 INTRODUCTION

On April 12, 2012, after a comprehensive regulatory review process including an oral public

hearing to review the FortisBC Energy Utilities’1 (the “FEU”) 2012-2013 Revenue Requirements

and Natural Gas Rates Application (“2012-2013 RRA”) which was filed on May 4, 2011, the

British Columbia Utilities Commission (“BCUC” or the “Commission”) issued its Decision and

accompanying Order No. G-44-12 (the “Decision”).

On pages 141-142 of the Decision, and in Appendix A, page 11, Summary of the Commission

Panel’s Directives, item no. 63 (the “Directive”), the FEU were directed to investigate the cost of

fully converting to the BCUC Uniform System of Accounts (“USoA”) and to file a proposed plan

for conversion within 180 days from the Decision:

“The Commission Panel understands that the FEU’s Code of Accounts was approved

by the Commission in Order G‐153‐07. However, the Panel does not believe it is

appropriate to relieve the Utilities of the responsibility to report “granular” account level

details of their O&M accounts on a comparable basis because it restricts the ability of

the Commission to fully analyze the information provided. The Commission Panel finds

this particularly relevant given the FEU’s move from a PBR to a Cost of Service rate

setting mechanism over the 2006‐2011 timeframe.

The Commission Panel believes that the use of the USoA for reporting purposes would

require consistent and comparable information at an account level. We also note that if

forecasting for a future RRA followed this same system of accounts, it would provide

further clarity of forecast to actual results at an account level. Given these advantages,

the Commission Panel believes there would be considerable benefit to the regulatory

process if the FEU were to fully adopt the USoA. In addition, the Commission Panel

believes the use of consistent reporting would enhance transparency, comparability and

understanding of costs of the FEU as they move forward with new initiatives and

projects.

Therefore, the Commission Panel directs the FEU to begin investigating the cost of fully

converting to the USoA and to work with Commission staff to develop a plan that will

allow the FEU to fully adopt the USoA prior to filing their next RRA with the Commission.

A proposed plan for conversion within the timelines presented should be discussed with

Commission staff and filed with the Commission no more that 180 days from the date of

this Decision. The filing should identify any cost deferral account mechanism needed to

facilitate the changeover.”

Although the FEU have not prepared a plan to fully adopt the USoA, the FEU respectfully

submit this report on the USoA (the “Report”) to address the underlying concerns of the

Directive. The FEU request that the Commission find that the FEU’s proposal contained in this

1 Comprised of FortisBC Energy Inc., FortisBC Energy (Vancouver Island) Inc., FortisBC Energy (Whistler) Inc., and

FortisBC Energy Inc. Fort Nelson Service Area.


Page 4

Report meets the objectives of the Commission’s Directive or, in the alternative, provide further

guidance to the FEU based on the contents of this Report.


Page 5

2 THE FEU’S PROPOSAL TO ADOPT THE UNIFORM SYSTEM OF ACCOUNTS

To address the Commission’s Directive, the FEU outline the following proposal that meets both

the utilities’ business requirements and provides consistent and comparable information that

would enhance transparency, comparability and understanding of the FEU’s costs.

The FEU propose to continue to use the current reporting. Under the current reporting, the FEU

believe it is fully meeting the reporting requirements of the USoA except for the departure in

operating and maintenance (“O&M”) reporting which was approved by the BCUC in 2007 in

Order No. G-153-07. The FEU had requested the departure in order to adopt a structure that

appropriately reflected its business requirements and that could be adapted in the future to meet

changes in operational activities, eliminating the need to maintain different views of O&M for

management purposes and for BCUC reporting purposes. In section 4 of this Report, the FEU

demonstrate how the current method of O&M expense reporting is similar to that outlined by the

USoA and meets the requirements for granularity of information.

Under this proposal, the FEU anticipate no incremental conversion costs, avoiding potentially

significant costs to customers that would result from converting back to the original BCUC

USoA. In addition, by continuing to utilize the current O&M reporting, the FEU are able to

provide comparable O&M information back to 2006, when O&M information by activity-based

and resource-based views was first available. Switching back to the original USoA for O&M

reporting would limit the comparability of information to information going forward.

The FEU emphasize that there is no intention with this request that the utilities be relieved of

providing granular account level details of O&M. Instead, the goal of the FEU is to ensure that

the information that is provided is useful in analyzing trends over time, by allowing for

meaningful variance analysis on a comparable basis. To this end, the FEU propose to work

with the Commission staff to review and adapt the current O&M reporting to fully address any

concerns the Commission may have to ensure that information provided is comparable,

transparent, and understandable.

3 BACKGROUND ON THE BCUC UNIFORM SYSTEM OF ACCOUNTS

The BCUC USoA was established in 1961 and ordered to be adopted by gas utilities in the

province of British Columbia from January 1, 1962. Although some minor updates to the USoA

were made in May of 1980, it has, for the most part, remained unchanged since 1961.

In response to a BCUC Information Request in the AES Inquiry, FEI explained how using the

O&M reporting in place presently meets the USoA requirements:

“…FEI does not conform exactly to the Commission’s USoA for Gas Utilities, which was

developed in 1961 and updated in 1980. As approved by the Commission, FEI has

made the following departures:


Page 6

172 Preliminary Survey and Investigation Costs

Due to changes to comply with Generally Accepted Accounting Principles, some

of the amounts previously captured in this account are now expensed as per

Commission Order No. G-141-09.

105 Accumulated Depreciation – Gas Plant

As approved through Commission Order No. G-141-09, the removal costs and

asset gains and losses for gas plant in service are charged to a deferral account

rather than accumulated depreciation for 2010 and 2011.

620 through 889 O&M Expenses

As agreed to by the Commission in Order No. G-153-07, Appendix A, pages 3

and 4, FEI has departed from using the USoA for reporting and tracking of O&M

expenses.

In addition, there have been some changes to capital vs. expense classification

as approved by the Commission (for example training and inspection costs), and

some numbering of the accounts in FEI’s internal accounting records may be

slightly different than the USoA due to current system requirements or numbering

conventions; but these accounts have been mapped to the correct USoA

numbering system for purposes of reporting to the Commission.”

There are elements of the USoA (excluding O&M) that could be modified to reflect changes in

policies and technologies that would allow it to be more relevant. If modifications are made by

the Commission, the FEU will make those modifications in its system to continue to comply with

the USoA.

4 THE O&M SECTION OF THE USOA

On October 5, 2007, FEI (then Terasen Gas Inc.) filed its advance information for its 2007

Annual Review, as required by the terms of its 2004 – 2007 Multi-Year Performance Based

Rate settlement agreement. In the 2007 Annual Review, FEI requested approval to depart from

using a portion of the USoA for recording its O&M in Accounts 600 to 999 and to prepare

reports using the New Code of Accounts, providing both a resource-based view (“Resource

View”) and an activity-based view (“Activity View”).

An excerpt from Attachment A5 (the Commission letter) commenting on FEU’s proposal is

included below:

“On February 28 and March 15, 2007, the TGVI, TGW, TGI and Commission staff

Working Group (the “Working Group”) reviewed the “Operation and Maintenance Code

of Accounts”, with the goal of developing a revised code of accounts (“New Code of

Accounts”). The New Code of Accounts would allow reporting for both an activity-based


Page 7

view and a resource-based view and relationship mapping to the Commission’s Uniform

System of Accounts. The information presented does not mirror exactly the BCUC

Uniform System of Accounts but does attempt to provide relevant and consistent

information for both annual reporting and revenue requirements. Since the New Code of

Accounts is based on how the Terasen Utilities are currently internally planning,

recording and reporting their costs, the New Code of Accounts may in the future need to

be adapted to meet changes in operational activities. An example of potential future

changes could be the reporting, coding and recording of CustomerWorks charges or

Shared Services Agreement charges. The reporting requirements do not limit the

detailed information that should be kept by the utility. The utility should be able to

provide a detailed “drill-down” of amounts that are reported in the code of accounts.”

In Order No. G-153-07, the Commission approved the request to depart from using a portion of

the USoA for recording FEI’s O&M in Accounts 600 to 999 and to prepare reports using the New

Code of Accounts, providing both a resource-based view and an activity-view. The differences

between the USoA and the New Code of Accounts are discussed in detail in section 4 and

Attachment 3 of this Report.

In the FEU’s 2012-2013 RRA, in BCUC Information Request (“IR”) 2.12.4, the Commission

requested:

“…please provide, for every item of O&M cost identified for 2012 and 2013, the

applicable organizational department, lowest level cost element, and lowest level activity

code. Provide the equivalent lowest level department, cost element and activity code

data for 2006 through 2013 in order to achieve more comparable information in each

year from 2006 through 2013 for each O&M item identified in 2012 and 2013. This much

more granular data analysis will result in a longer process but will allow the Commission

Staff to analyze the requested increases in the context of the historical data.”

In response, the FEU stated:

“The FEU note that providing more granular analysis than this does not achieve more

comparable information, as suggested in the question. In fact, the more granular the

analysis is, the less comparable it becomes due to changes in organizational structures

and accounting policies.

Attachment 12.4 provides a fully functioning excel file containing actual and forecast

activity view of O&M for the combined FEU, along with variance explanations for 2012

and 2013 where the variance is greater than 10% and is greater than or equal to $250

thousand.

The FEU note that the use of cost drivers to explain changes in O&M levels in the RRAs

for 2010 through 2013, has been done to demonstrate the impacts of the many new and

emerging challenges faced by the utilities. The analysis of O&M by activity codes or

resource codes over time is not able to convey this same level of understanding, and


Page 8

therefore is not as useful for demonstrating required changes to levels of O&M funding in

revenue requirement applications.”

Finally, in the 2012-2013 RRA Decision, the Commission issued the Directive to develop and

file a Conversion Plan that will allow the FEU to fully adopt the USoA prior to filing their next

RRA. This Report is in response to the Directive.

4.1 Objectives of USoA for O&M

The FEU recognize that the Commission Panel’s concern is primarily with receiving information

that is comparable, transparent, and understandable. In a province with two primary gas utilities

and two primary electric utilities, none of which can be easily compared to each other due to

differences in size and accounting policies, the goal can only be to allow a comparison of a

utility’s accounts over time, rather than allowing comparison of one utility to another. This is at

odds with the situation in some other Canadian jurisdictions (like Alberta and Ontario) where

there are many service providers, and a standardized USoA for all the service providers is

required.

The objectives of the Commission Panel as expressed in the Directive are fully met with the

FEU’s New Code of Accounts. That is, the New Code of Accounts provides for consistent

reporting that enhances transparency, comparability and understanding of costs.

Transparency

The New Code of Accounts provides both a Resource View (a breakdown of the O&M accounts

into the types of costs that are incurred including categories such as internal labour, external

labour and non-labour), and an Activity View (accounts showing a breakdown of the types of

activities undertaken by the utilities, rolling up to the categories of transmission, distribution,

general operations and administration). When these two views of the O&M accounts are taken

together with a written description of the contents of each account, this allows for transparent

reporting to the Commission of the various resources employed and activities undertaken by the

utilities.

Comparability

The Activity View is designed so that each cost centre in the FEU’s SAP system has a

responsible cost centre owner, and cost centres are grouped under one account that has a

common activity. Since the SAP system is set up to restate a cost centre’s history when the

cost centre is mapped to roll up to a different activity or reporting relationship, the comparability

of costs under the Activity View is maintained over time, despite changes in management

structure and reporting relationships. The Resource View is designed so that each cost element

in the SAP system is grouped under an account that has a common resource type. Since the

types of resources employed by the utilities are not expected to change significantly over time,

the Resource View also allows for comparability of costs over time.


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Understanding

Understanding is provided by both transparency and comparability. Since the Activity View is

designed to be aligned with FEU’s management of O&M costs through responsible cost centre

owners, variance explanations and analysis at either the Activity View account level or the more

detailed cost centre level can be provided as required.

In reaching this conclusion, the FEU would like to clarify its response to BCUC IR 2.12.4 where

it was requested to provide, “for every item of O&M cost identified for 2012 and 2013, the

applicable organizational department, lowest level cost element, and lowest level activity code”.

The FEU had already provided O&M reporting under its New Code of Accounts in both a

Resource View (extract provide in Attachment 1) and an Activity View (extract provided in

Attachment 2) for the years 2006 through 2013 in Appendix D-2 of its 2012-2013 RRA. In the

response to BCUC IR 2.12.4, the FEU were also able to provide the variance analysis at that

level of detail. In order to fully respond to the information request, the FEU would have had to

analyze a combination of approximately 350 cost centres (departments) and 320 cost elements.

Although the FEU did have this level of information available to them, it would have required an

extraordinary investment of time and effort to gather and summarize the information in one

spreadsheet. The resulting information would not have been meaningful due to its sheer

volume and the inability to restate information to be comparable at that level of detail in a limited

amount of time. The FEU continue to believe that providing a significantly lower level of

granularity than set out in the New Code of Accounts does not provide any further

understanding of changes in the business over time. As stated in the response to BCUC IR

2.12.4, “The FEU note that providing more granular analysis than this does not achieve more

comparable information, as suggested in the question. In fact, the more granular the analysis

is, the less comparable it becomes due to changes in organizational structures and accounting

policies.”

The objectives of the USoA are served by providing information at the agreed-upon level, which

for the FEU has been comparable over time since the adoption of the New Code of Accounts in

2006. The New Code of Accounts provides 50 different accounts in the Activity View and a

further 12 accounts in the Resource View, compared to a total of approximately 50 comparable

accounts in the BCUC USoA for O&M. For any accounts where an issue is identified through

the Activity View, the FEU are able to provide the further analysis. For example, in the FEU’s

2012-2013 RRA, in response to BCUC IR 2.21.1, the FEU provided a detailed listing of all field

service delivery cost centres, description of major category (i.e. leaks repairs), description of

sub-category or Maintenance Activity Type (“MAT”) (i.e. DP main, IP main, LP main, Services,

etc.), forecast (“plan”) dollars for 2011-2013, actual dollars for 2006-2010, activity count where

applicable and unit cost where applicable for each line item. The spreadsheet provided had 122

individual lines of data (excluding totals). Other than the referenced BCUC IR 2.12.4, the FEU

are not aware of any other IRs where the requested level of detail was not provided. No

interveners representing customer groups indicated that they were concerned with the level of

granularity provided in the Application or the detail provided in response to IRs.


Page 10

The adoption of any USoA that differs from the New Code of Accounts will not enhance the

transparency, comparability and understanding of costs. To support this statement, the FEU

have compared both the New Code of Accounts and other USoAs against the BCUC USoA.

4.2 Comparisons of BCUC USoA for O&M

4.2.1 BCUC USOA FOR O&M VERSUS NEW CODE OF ACCOUNTS

In Attachment 3, the FEU have provided a line by line comparison of the BCUC USoA for O&M

accounts to the New Code of Accounts. Based on this analysis, the FEU are able to conclude

that there are no significant differences between the two in terms of the information provided. At

a high level, the detailed comparison provided in Attachment 3 is summarized below in terms of

any differences that were found.

There are accounts where the New Codes of Accounts provides less information, and these

accounts are primarily those where the FEU do not separately manage activities at the BCUC

USoA level of detail, so that meaningful information cannot be provided. The main areas where

this occurs are:

Transmission Supervision and Distribution Supervision accounts – The FEU do not have

individuals that separately manage the Maintenance vs. Operations of these two areas as

this would not be an efficient way to operate the utility. Accordingly, any allocation of FEU

supervision between maintenance and operations would be arbitrary and unexplainable.

Communication, and Measuring and Regulating accounts – With an integrated system and

current technology, it is no longer possible to draw a clear line in these areas between

transmission and distribution and the monitoring of those systems. Accordingly, any

allocation of these accounts between transmission and distribution would be arbitrary and

unexplainable.

Engineering accounts – The FEU do not separate engineering activities between

transmission and distribution. Accordingly, any allocation of these costs between

transmission and distribution would be arbitrary and unexplainable.

There are accounts where the New Code of Accounts provides more information, reflecting how

the FEU manage these activities at a more granular level and are therefore able to provide this

information in a meaningful way. The main areas where this occurs are:

Right of Way and TPIP accounts provide additional detail not provided elsewhere.

Much greater granularity provided compared to the BCUC “Other General Operations”

account where the FEU provide six separate accounts instead of one.

Much greater granularity provided compared to the BCUC “Administration Expense” account

where the FEU provide 12 separate accounts instead of one.


Page 11

The FEU provide 12 separate accounts in the Resource View that provide information over

and above the requirements of the BCUC USoA; the BCUC USoA is more similar to an

activity view of operations.

For all of the accounts in the New Code of Accounts, whether the Activity View or the Resource

View, the FEU are able to provide a lower level of analysis than shown (cost centre level for the

Activity View and cost element level for the Resource View), although as stated above, the

comparability over time decreases as more granularity is provided. For example, if an entire

cost centre is moved to report to a different account to align with a reorganization or a change in

business activities, the SAP system can restate the historical comparatives for the requested

reporting period.2 Managers remain assigned as responsible for that cost centre and are able to

provide analysis of the changes in the activities and costs of that cost centre over time. At any

level of reporting below the cost centre level, there is no data readily available from the SAP

system, and there is no individual manager responsible to explain those costs. Historical

information cannot be reconciled at a lower level of detail.

However, the FEU acknowledge that the New Code of Accounts as filed in its 2012-2013 RRA

was not fully aligned with changes in business activities that had occurred since 2007, and also

needs to be updated to reflect the insourcing of the Customer Care function. The end result of

this review and update would be an Activity View that is fully aligned with the written

descriptions of the forecast and historical O&M changes that will be provided in future RRAs.

For example, Account 900-13 Finance and Regulatory Affairs would show exactly the same

figures as are provided in the tables included in the narrative for the Finance and Regulatory

Affairs department in the RRA.

4.2.2 BCUC USOA FOR O&M VS. OTHER USOAS FOR O&M

The FEU also considered that alternate USoAs for O&M may provide a level of reporting that

more fully meets the objectives of the Commission. The FEU undertook a high level

comparison of the O&M section of the BCUC USoA against that of the Ontario Energy Board,

the United States Federal Energy Regulatory Commission (“FERC”) and the Alberta Utilities

Commission.

The Ontario Energy Board (1996) and the Alberta Utilities’ Commission (1963) USoA for O&M

accounts for gas utilities appear to be almost identical to the BCUC USoA.

The FERC USoA for O&M accounts, from which the BCUC USoA was developed, remains very

similar to the BCUC USoA with some additional accounts. The FEU note that the separate

accounts for “Communication” do not exist in the FERC USoA, consistent with the New Code of

Accounts.

2 Although there will still be some situations where a cost centre is split into two or more new cost centres that map

into different activities, the FEU have been able to manage these situations through manual adjustments to align

the history as closely as possible.


Page 12

The FEU conclude that none of the other USoAs provide more meaningful information than that

provided by the New Code of Accounts.

4.3 Conclusion on BCUC USoA for O&M

In addition to undertaking the reviews of the BCUC and other USoAs for O&M, the FEU have

met with Commission staff and the other major utilities in BC regarding this issue. Our view and

our understanding of the views of the other utilities is that a certain amount of flexibility is

required for the O&M section of the USoA, with the objective of allowing comparability of

individual utility data over time while avoiding unnecessary costs. This is because the O&M

section is unique to each utility and should reflect its requirements to manage the business

effectively.

Although big buckets can be expected to remain fairly static over time (distribution,

transmission, general operations and administration), specific O&M categories within those

buckets reflect changes in technology, changes in management and changes in reporting

relationships within the utility, and can change over time. The 1961 BCUC USoA for O&M

accounts no longer reflects how each utility operates its activities.

The FEU understand that each of the utilities in BC is at a different starting point today in its

adoption of the BCUC USoA or an alternate USoA.

The New Code of Accounts continues to be relevant and appropriate for the FEU whereas a

different code of accounts may be better suited to another utility.

The FEU expect that the adoption of a “one size fits all” approach to O&M accounts will

result in significant costs3, both one time and ongoing. This expectation is based on the

adoption of a USoA for electric utilities in Alberta, which has resulted in both costs to make

system changes4, and costs to support the provision of variance explanations for this

alternate view of O&M. This requires an additional step over and above the ongoing

variance analysis and management of expenses that would otherwise occur in the utility,

and would require the assignment of responsible managers for each of the new accounts.

For example, to capture the amount of time spent by transmission managers on operating

as opposed to maintenance activities, separate coding blocks would be added to the

system, then managers would be required to code their time on an hourly basis to these two

types of activities, and would then be required to provide variance explanations to support

the changes in those activities over time. The FEU believe that this process would require

an undue amount of the transmission managers’ time and would not be cost effective.

3 In the Alberta Energy and Utilities Board Decision 2007-017, cost estimates of fully adopting a USoA were provided

by the affected utilities and ranged from a low of $300 thousand to a high of $17.8 million for implementation, and

up to $2.8 million in annual operating costs. 4 An alternative adopted by some utilities in Alberta was to create an additional coding block in their accounting

system, requiring employees in the field to complete additional fields to derive the information required on an

ongoing basis.


Page 13

5 IMPLEMENTATION PLAN TO MEET BCUC OBJECTIVES

As stated above, the FEU believe they are currently fully meeting the reporting requirements

with the 1961 BCUC USoA for all accounts except for the approved departure for O&M.

As stated in section 4, the FEU adopted the New Code of Accounts for the O&M portion of the

BCUC USoA in 2007. The FEU have reviewed other USoAs and continue to believe that their

existing New Code of Accounts approach provides more meaningful and comparable

information than the USoAs, and at no additional cost to customers.

As a result, the FEU propose to undertake a project to:

1. Work with Commission staff to review and modify their New Code of Accounts to more

fully address Commission’s concerns with receiving information that is comparable,

transparent, and understandable;

2. Provide the Commission with an updated description of the Activity View of the New

Code of Accounts prior to filing its next RRA;

3. Implement the required revisions to the New Code of Accounts (Activity View and

Resource View) into the SAP accounting system with no incremental cost to customers;

4. Provide test year information and 5 year historical information in future Revenue

Requirement filings that includes the modified New Code of Accounts;

5. Provide tables in its written descriptions of the forecast and historical O&M changes in

future Revenue Requirement filings that reconcile to the Activity View of the New Code

of Accounts;

6. Provide ongoing updates to the Activity View of the New Code of Accounts to the

Commission as required; and

7. Continue to report using the Activity View and Resource View of the New Code of

Accounts (in combination with the 1961 USoA for the remaining accounts) in its BCUC

Annual Reports.

The FEU propose to implement these changes in its next RRA. If the Commission Panel finds

that the information provided is not adequate to meet its objectives, at that time the FEU will

review alternate approaches to the USoA. If an alternate approach is ultimately required, an

adequate period of time to develop and implement this alternate USoA would be required. For

the electric utilities in Alberta, there was an approximate two and a half year window for

implementation of a full USoA.

The FEU propose this approach because:

1. Other than O&M accounts, the FEU are already meeting existing 1961 USoA

requirements;


Page 14

2. Full implementation of a new USoA would result in additional costs being borne by

customers with no guaranteed improvement in understanding or comparability;

3. For O&M accounts, flexibility is required amongst the utilities in BC to determine a

method that meets the objectives of comparability, transparency and understanding of

results over time;

4. The FEU already have a fully reviewed and agreed-upon New Code of Accounts that

meets those objectives; and

5. The FEU have reviewed the BCUC and other USoAs for O&M and have concluded that

none of the ones reviewed would provide a measurable improvement over the existing

New Code of Accounts.

For the above stated reasons, the FEU believe that the proposed approach to undertake a

project to implement changes in the next RRA as described above will help identify and provide

clarity to the Commission Panel’s concerns and address them in the most cost-effective and

efficient manner. This will result in alignment between the BCUC and the FEU in the

understanding of changes in O&M costs over time.

The FEU request the Commission find that the FEU’s proposal meets the objectives of the

Commission’s Directive or, in the alternative, provide further guidance to the FEU based on the

contents of this Report.

Attachment 1

RESOURCE VIEW

Line

No. Particulars 2006 2007 2008 2009 2010

Projection

2011

Forecast

2012

Forecast

2013

(1) (2) (3) (4) (5) (6) (7) (8) (9)

1 M&E Costs 40,312$ 44,601$ 42,244$ 44,495$ 47,051$ 52,316$ 58,567$ 60,697$

2 COPE Costs 22,591 22,074 23,134 25,677 28,717 31,237 36,133 38,131

3 COPE Customer Services Costs 11,824 11,177

4 IBEW Costs 24,428 24,593 25,761 26,631 27,748 30,839 33,159 34,931

5

6 Labour Costs 87,331 91,268 91,138 96,803 103,516 114,391 139,683 144,935

7

8 Vehicle Costs 4,871 5,362 5,626 5,516 4,312 4,045 4,484 4,544

9 Employee Expenses 3,836 3,961 4,854 4,777 6,375 4,688 6,172 6,351

10 Materials and Supplies 5,021 5,556 6,844 7,123 7,878 6,593 8,117 8,490

11 Office Furnishing & Equipment 47 - - - 19

12 Computer Costs 8,944 8,021 7,890 8,417 10,773 11,124 14,734 15,306

13 Fees and Administration Costs 42,476 33,862 36,689 34,359 41,131 40,383 74,264 79,629

14 Contractor Costs 57,763 59,169 62,484 64,806 68,661 69,807 23,920 26,386

15 Facilities 12,517 13,405 13,161 14,227 15,164 15,544 18,511 16,344

16 Recoveries & Revenue (16,435) (15,489) (15,520) (15,994) (19,892) (18,244) (28,758) (28,220)

17

18 Non-Labour Costs 119,040 113,846 122,029 123,231 134,422 133,942 121,444 128,831

19

20 Total Gross O&M Expenses 206,371 205,115 213,167 220,034 237,938 248,333 261,127 273,766

21

22 Add: Shared Corporate Services

23 Add: PST Savings 730

24 Less: O&M Difference from Allowed - - - - 1,379

25 Less: Vehicle Lease Reclass (2,100) (2,008) (1,988) (1,804) -

26 Less: Capitalized Overhead (32,034) (32,470) (32,718) (33,365) (33,510) (34,857) (36,558) (38,327)

27

28 Total O&M Expenses 172,237$ 170,637$ 178,461$ 184,865$ 205,806$ 214,206$ 224,569$ 235,438$

FORTISBC ENERGY INC (COMBINED)

OPERATION & MAINTENANCE EXPENSES - RESOURCE VIEW

($000)

Attachment 2

ACTIVITY VIEW

Line

No. Particulars Reference 2006 2007 2008 2009 2010

Projection

2011

Forecast

2012

Forecast

2013

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

1 Distribution Supervision 100-11 9,695$ 10,769$ 10,970$ 11,688$ 11,846$ 11,259$ 13,305$ 13,825$

2 Distribution Supervision Total 100-10 9,695 10,769 10,970 11,688 11,846 11,259 13,305 13,825

3 Operation Centre - Distribution 100-21 6,445 6,187 6,514 6,556 11,099 11,323 12,743 13,443

4 Asset Management - Distribution 100-22 1,415 970 1,052 1,355 1,762 2,302 3,259 4,587

5 Preventative Maintenance - Distribution 100-23 1,774 1,810 2,486 3,146 2,324 2,555 3,202 3,483

6 Distribution Operations - General 100-24 5,369 5,580 5,944 5,432 6,790 6,926 7,003 7,355

7 Emergency Management 100-25 6,974 6,701 7,855 7,277 5,445 6,380 5,938 6,134

8 Distribution Operations Total 100-20 21,978 21,248 23,851 23,766 27,421 29,486 32,145 35,002

9 Distribution Corrective - Meters 100-31 1,096 1,356 1,431 1,554 2,102 1,822 1,886 1,945

10 Distribution Corrective - Propane 100-32 46 36 37 21 2 5 - -

11 Distribution Corrective - Leak Repair 100-33 942 1,180 1,136 1,195 1,445 1,276 1,374 1,415

12 Distribution Corrective - Stations 100-34 450 598 768 647 643 678 773 793

13 Distribution Corrective - General 100-35 473 445 396 310 466 430 638 987

14 Distribution Maintenance Total 100-30 3,008 3,616 3,767 3,727 4,659 4,210 4,671 5,140

15 Distribution Total 100 34,681 35,633 38,588 39,181 43,925 44,955 50,121 53,966

16 Transmission Supervision 200-11 1,889 2,194 1,841 2,924 3,205 4,502 5,497 6,453

17 Transmission Supervision Total 200-10 1,889 2,194 1,841 2,924 3,205 4,502 5,497 6,453

18 Pipeline Operation 200-21 1,789 2,860 3,578 4,549 3,451 1,650 3,622 3,766

19 Right of Way 200-22 1,939 1,386 1,514 1,566 1,706 536 730 808

20 Compression 200-23 2,329 2,389 2,228 2,451 2,900 915 2,171 2,239

21 Gas Control 200-24 1,939 1,848 1,905 2,471 2,611 3,132 2,848 3,000

22 Transmission Pipeline Integrity Project (TPIP) 200-25 4,065 3,284 4,202 4,285 2,722 3,240 2,611 2,797

23 Transmission Operations Total 200-20 12,062 11,767 13,427 15,322 13,391 9,473 11,983 12,610

24 Pipeline - Maintenance 200-31 639 252 483 499 710 3,594 2,830 2,684

25 Compression - Maintenance 200-32 1,296 972 1,712 1,073 958 2,714 1,624 1,764

26 TPIP - Maintenance 200-33 435 877 338 899 869 954 1,567 1,587

27 Transmission Maintenance Total 200-30 2,370 2,101 2,533 2,471 2,537 7,263 6,021 6,035

28 Transmission Total 200 16,322 16,062 17,801 20,717 19,132 21,238 23,502 25,098

29 LNG Plant Operations 300-11 524 781 720 845 1,368 2,126 2,780 2,937

30 LNG Plant Operations Total 300-10 524 781 720 845 1,368 2,126 2,780 2,937

31 LNG Plant Maintenance 300-21 291 198 254 255 431 760 797 824

32 LNG Plant Maintenance Total 300-20 291 198 254 255 431 760 797 824

33 LNG Plant Total 300 815 980 974 1,100 1,799 2,886 3,577 3,761

34 Measurement Operations 400-11 3,633 3,955 3,788 4,142 4,594 4,252 4,951 5,261

35 Measurement Operations Total 400-10 3,633 3,955 3,788 4,142 4,594 4,252 4,951 5,261

36 Measurement Maintenance 400-21 3,404 2,326 2,288 2,396 2,197 3,367 2,539 2,601

37 Measurement Maintenance Total 400-20 3,404 2,326 2,288 2,396 2,197 3,367 2,539 2,601

38 Measurement Total 400 7,037 6,281 6,075 6,538 6,791 7,619 7,491 7,861

39 Facilities Management 500-10 6,516 6,266 6,813 7,545 7,966 7,504 10,433 9,451

40 Shops & Stores 500-20 2,807 3,233 3,405 3,747 4,016 3,907 4,677 4,783

41 Operations Engineering 500-30 5,791 6,143 6,288 6,930 9,067 9,297 10,621 11,092

42 Property Services 500-40 881 760 1,011 991 1,204 1,283 1,411 1,453

43 System Integrity 500-50 1,981 2,141 2,243 2,415 2,449 2,774 2,567 2,608

44 Environmental Health & Safety 500-60 1,162 1,066 1,191 1,457 2,365 2,404 2,893 3,057

45 Operations Governance 500-70 1,159 1,351 1,464 1,445 1,660 1,899 1,649 1,705

46 General Operations Total 500 20,298 20,960 22,416 24,530 28,727 29,068 34,251 34,149


OPERATION & MAINTENANCE EXPENSES - ACTIVITY VIEW

($000)

Line

No. Particulars Reference 2006 2007 2008 2009 2010

Projection

2011

Forecast

2012

Forecast

2013

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

1 Energy Efficiency 600-10 1,556$ 1,599$ 1,740$ 1,624$ (7)$ (0)$ 0$ (0)$

2 Marketing - Supervision 600-20 562 1,174 553 1,326 780 (825) (807) (785)

3 Corporate & Marketing Communications 600-30 3,540 2,533 3,147 3,126 3,270 2,975 3,887 4,103

4 Marketing Planning & Development 600-40 686 607 568 565 626 531 955 981

5 Marketing Total 600 6,344 5,913 6,009 6,641 4,669 2,682 4,035 4,298

6 Customer Care - Supervision 700-10 735 724 878 1,474 1,504 2,205 2,793 2,883

7 Customer Contact 700-20 49,190 49,982 51,128 51,325 53,014 54,601 45,431 48,917

8 Bad Debt Management and Administration 700-30 10,853 4,927 5,446 6,255 3,718 5,871 5,445 5,494

9 Customer Management & Sales 700-40 3,274 3,456 4,195 4,278 6,740 7,049 8,189 8,545

10 Customer Care Total 700 64,052 59,088 61,647 63,332 64,975 69,726 61,859 65,839

11 Business & IT Services - Supervision 800-10 1,858 1,857 1,011 1,568 999 1,194 0 -

12 Application Management 800-20 6,676 8,172 8,313 9,610 11,329 12,888 16,540 17,297

13 Infrastructure Management 800-30 5,472 5,675 5,270 5,494 6,026 7,108 8,760 9,154

14 Procurement Services 800-40 674 681 670 700 821 864 1,265 1,412

15 Business & IT Services Total 800 14,681 16,386 15,264 17,372 19,176 22,053 26,564 27,863

16 Administration & General 900-11 3,352 3,025 4,375 723 5,950 3,691 2,566 3,450

17 Insurance 900-12 5,734 5,797 5,380 5,444 5,271 5,561 5,437 5,257

18 Finance and Regulatory Affairs 900-13 7,519 8,189 8,972 9,882 9,491 10,335 11,564 11,892

19 Shared Services Agreement 900-14 8,780 9,168 8,768 9,009 9,640 9,103 11,277 11,234

20 Corporate Administration Total 900-10 25,385 26,180 27,496 25,058 30,353 28,690 30,844 31,833

21 Forecasting 900-20 1,184 1,025 934 968 1,721 1,696 3,036 3,335

22 Public Affairs 900-30 1,468 1,537 1,567 1,883 1,850 2,030 2,253 2,309

23 Business Development 900-40 1,194 982 1,017 1,253 2,013 3,808 3,979 4,113

24 Human Resources 900-50 4,041 4,724 4,540 5,519 6,551 6,947 8,152 8,457

25 Other Post Employment Benefits (OPEB) 900-60 8,870 9,364 8,841 5,942 6,257 4,935 1,464 883

26 Administration & General Total 900 42,141 43,812 44,394 40,623 48,745 48,107 49,727 50,930

27 Total Gross O&M Expenses 206,371 205,115 213,167 220,034 237,938 248,333 261,127 273,766

28 Add: Shared Corporate Services

29 Add: PST Savings 730

30 Less: O&M Difference from Allowed 1,379

31 Less: Vehicle Lease Reclass (2,100) (2,008) (1,988) (1,804) -

32 Less: Capitalized Overhead (32,034) (32,470) (32,718) (33,365) (33,510) (34,857) (36,558) (38,327)

33 Total O&M Expenses 172,237$ 170,637$ 178,461$ 184,865$ 205,806$ 214,206$ 224,569$ 235,438$


OPERATION & MAINTENANCE EXPENSES - ACTIVITY VIEW (CONT'D)

($000)

Attachment 3

COMPARISION OF BCUC UNIFORM SYSTEM OF ACCOUNTS

TO ACTIVITY VIEW

US of A Code Expense Expense Description

Activity Based

View Code Expense Expense Description

Differences noted from

FEU compared to BCUC

64X Local Storage - Operation 300-XX LNG Plant649 Other Local Storage - Operation Includes the cost of labour, supplies and expenses incurred in the

operation of local storage facilities not includible elsewhere

300-11 LNG Plant Operations This account includes salaries and expenses for planned maintenance of the LNG plant in

Delta. No significant differences noted.

84X Local Storage - Maintenance 300-XX LNG Plant849 Other Local Storage -

Maintenance

Includes the cost of labour, supplies and expenses incurred in the

maintenance of other local storage facilities not includible

elsewhere.

300-21 LNG Plant Maintenance This account includes salaries and expenses for unplanned corrective maintenance of the LNG

plant in Delta. No significant differences noted.

66X Transmission - Operation 200-XX Transmission 660 Supervision Includes the cost of labour, supplies and expenses incurred at a

division, district or similar field office in the general supervision of

the operation of the transmission system facilities.

200-11 Transmission - Supervision Includes the cost of labour, travel, supplies and other expense for the VP, Gas Supply and

Transmission and all transmission management personnel.No significant differences noted. Supervision of both transmission

operation and transmission maintenance combined together for

FEU; splitting would be an allocation exercise since there is only

one management group

663 Transportation of Gas by Others Includes the cost of transportation charges paid to others where

such charges are separate and not included as part of the delivered

price of gas.

N/A N/A N/A - FEU do not have third party transportation costs that are part of the delivery charge

Not applicable

664 Communication Includes the cost of labour, supplies and expenses incurred in the

operation of facilities used wholly or predominantly in connection

with the transmission communication system.

EXAMPLES:

Direct supervision

Microwave equipment, power generators

Securing authorization for changing frequencies

Cleaning and lubricating equipment

Radio crystals and other radio equipment

Expenses such as use of automotive, traveling and

employees subsistence

N/A N/A N/A - these costs are not separated out

These costs are included in 200-24 Gas Control and also 800-30 IT

Infrastructure. With an integrated system and current technology,

there is no distinction in the FEU's system between

communications related to transmission and communications

related to distribution, or the monitoring of these. Any split would

be arbitrary.

665 Pipe Lines Includes the cost of labour, supplies and expenses incurred in the

operation of transmission system pipe lines and facilities.

200-21 Pipeline Operation Costs incurred to manage planned maintenance of the lower mainland and interior pipeline

transmission lines.

No significant differences noted.

666 Compressor Includes the cost of labour, supplies and expenses incurred in the

operation of transmission system compressor stations and facilities.

200-23 Compression Costs incurred to manage planned maintenance of all compressor stations. Compressor

stations in the interior include Savona, Armstrong, Kingsvale, Hedley, Midway, Warfield and

Kitchener A and B compressor stations. The Langley compressor station is the only station in

the lower mainland.


667 Measuring and Regulating Includes the cost of labour, supplies and expenses incurred in the

operation of transmission system measuring and regulating stations

and facilities.

200-24 Gas Control Costs associated with planned maintenance around monitoring and/or controlling: the flow of

gas in the system; the odorization system; the operation of the compressor, regulator and

valve stations in the system; the operation of the line heaters in the system; pressure in the

system; and flow imbalances. Includes costs related to monitoring the security system,

responding to alarm conditions, preparing gas load requirements, maintaining the SCADA

system and adding and deleting points to SCADA. Includes costs related to ongoing telemetry

communication costs for SCADA to connect to various field devices. These include backbone

WAN, wireless communications, several radio systems, satellite systems, regular phone lines

and 4-wire lease lines.

This account is not separated between transmission and

distribution or for operations vs. maintenance. The system is

operated as an integrated whole and any allocations would be

arbitrary. All costs are held in the gas control account

669 Other Transmission Operation Include the cost of labour, supplies and expenses incurred in the

operation of transmission system facilities not includable

elsewhere.

200-22 Right of Way Costs to manage all rights of way associated twith transmission lines to ensure that all

transmission lines are clear of vegetaion and are available for easy access. Additional detail provided by FEU to split out ROW program

BC Utilities Commission (BCUC) FortisBC Energy Utilities (FEU)

Page 1


Activity Based





200-25 Transmission Pipeline Integrity

Program

Costs of planned maintenance activities, for mainline transmission operating plant assets

including development and maintanence of an integrity management plan and asset

assessments to demonstrate and ensure asset integrity and for future integrity plans.Additional detail provided by FEU to split out TPIP program

67X Distribution - Operation670 Supervision Include the cost of labour, supplies and expenses incurred in the

general supervision and direction of the operation of the

distribution system facilities.

100-11 Supervision - Distribution Cost of labour, vehicles, travel, supplies and other expenses incurred in the general

supervision and direction of distribution facility operations. Includes expenses associated

with:

• Regional Managers, Field Managers, Field Operations Assistants, and Clerical staff in

regional locations

This account also includes third party costs to conduct customer satisfaction surveys, risk

assessments and environmental audits.

100-22 Asset Management - Distribution Salaries, supplies and other expenses for the distribution asset management group. This

group is responsible for the systems and processes used to manage the distribution assets. A

key responsibility is determining the frequency of preventative maintenance.

671 Load Dispatching Includes the cost of labour, supplies and expenses incurred in

dispatching and controlling the supply and flow of gas through the

distribution system.

500-80 Energy Supply & Resource

Development

Includes costs for management oversight, planning, and performance monitoring of the

Energy Supply &Resource Development group.

Includes management of transpotation and marketing services on FBC pipeline system.

Oversee on-system gas transportaion and industrial, commercial and marketer agent services,

providing customer service and support to shippers and marketers.

Includes costs for gas supply infrastructure planning and major capacity and sustainment

initiatives management function. Identifying an ddeveloping new regional projects and

system infrastructure projects within the Company's current service areas, including pieline,

compressor, and storage projects.

No significant differences noted. Again, this activity is performed

on an integrated system wide basis and these costs are not specific

to the distribution system.

673 Removing and Resetting Meters

and House Regulators

Includes the cost of labour, supplies and expenses incurred in

connection with removing, resetting, changing, testing and servicing

customer meters and house regulators.

400-21 Measurement Maintenance This account includes costs related to corrective maintenance, including:

• unscheduled corrective maintenance of prover system and the equipment used to repair

the meters

• general troubleshooting to resolve meter or prover issues not directly related to a specific

meter or device

• unscheduled field repairs associated with the Lower Mainland measurement customers

(primarily AMR customers)

• manually reading the meters located at our lower mainland AMR customers

• repairing industrial measurement equipment and AMR equipment

• repairing the hardware and software used to collect and process data from our AMR

customers

• responding to and resolving trouble calls at lower mainland line-break and stations, Tilbury

LNG facility, muster stations, lower mainland SCADA, telemetry and mobile radio stations

• repairing portable instrumentation that has come in earlier than the planned maintenance

date

• Meter Management System (“MMS” - a module of SAP) repairs

No significant differences noted. The total of 400-21 and 400-11

and 100-23 will be the equivalent of 673 and 677 but the

breakdown between them will not be exactly the same. Overall

the FEU have three accounts vs. two in the BCUC USofA.

100-23 Preventative Maintenance –

Distribution

Costs associated with scheduled or routine operational work and minor repairs as they relate

to (i) individual meter sets that require less than 30 minutes for single run sets and less than

60 minutes for double run sets; (ii) propane equipment; and (iii)stations including testing,

calibration and minor housekeeping that require less than 30 minutes for single run sets and

less than 60 minutes for double run sets, as well as scheduled heater overhauls.





674 Service on Customers' Premises Includes the cost of labour, supplies and expenses incurred in work

on customer premises other than expenses includable in account

No. 673, "Removing and Resetting Meters and House Regulators",

including the cost of servicing customer-owned appliances when

the cost of such work is borne by the company. Damage to

customer equipment by employees of the company whether

incidental to the work or the result of negligence, shall be charged

to the job on which the employee was engaged at the time of

damage.

100-25 Emergency Management Costs associated with:

• responding to gas odour calls

• responding to carbon monoxide investigation calls

• responding to fire, explosions and other customer safety calls

• responding to industrial premise calls

• first response standby time

• restoring full service to customers and restoring normal business functions


No significant differences noted. Supervision of both distribution

operation and distribution maintenance combined together for


one management group; however asset management is separately

identified.

Page 2


Activity Based





675 Mains and Services This account shall include the cost of labour, supplies and expenses

incurred in the operation of distribution system

mains and services.

100-24 Distribution Operations – General Costs incurred for:

• leak surveys of mains and services (including intermediate pressure)

• audits

• land slippage

• any survey in advance of local municipal improvements including paving and repaving and

any survey by request

• inspecting the meters for ice or snow

• transmission pressure laterals (included in distribution plant) surveys

• filling of bulk odorant facilities

• inspection of odorizer facilities including measurement of product in storage, minor

adjustments calibrations or repairs requiring less than 15 minutes that can be completed

during the inspection, and odorant surveys

• identification, recommendation or urgent action necessary to prevent activities which could

endanger the pipeline

• activities to identify maintenance or system integrity concerns

• replacing line markers and warning signs

• attending/monitoring low pressure problems (i.e. water in the lines)

• winter valve configuration and survey recorder operations

• inspection of facilities where leaks are suspected or gas odour has been detected

• recording pressures and changing charts


676 Compressor This account shall include the cost of labour, supplies and expenses

incurred in the operation of distribution system compressor

stations and equipment.

N/A N/A N/A - FEU do not have compressor stations in the distribution network - only in transmission.

N/A

677 Measuring and Regulating This account shall include the cost of labour, supplies and expenses

incurred in the operation of the distribution system measuring and

regulating stations.

400-11 Measurement Operation This account includes costs associated with research and development for any work related to

modifying existing equipment; procedures or changing environmental or regulatory

requirements; Operational support provided for meter set design and equipment issues;

Purchases of non-inventoried meter parts for service work.

Costs incurred by the meter shop related to planned maintenance, including: travel, office

supplies and administrative labour; parts and labour associated with the repair of rotary,

turbine and diaphragm meters 800 cu ft/hr and larger; meter sampling program; and

preventative maintenance and labour costs involved in the ongoing upkeep of the meter fleet,

as well as general meter shop maintenance.

Costs related to instrumentation and communication services, and data acquisition such as:

annual and recurring field maintenance checks performed for lower mainland measurement

customers (primarily for Automated Meter Reading (“AMR”) customers - rates 5, 7, 22, 25 and

27), lower mainland line-breaks and stations, the Tilbury LNG facility, lower mainland SCADA

and the telemetry and mobile radio systems; scheduled calibration checks on industrial

measurement equipment and AMR equipment; processing the consumption data from AMR

customers; and planned portable instrument maintenance activities (calibration checks).





679 Other Distribution Operation This account shall include the cost of labour, supplies and expenses

incurred in the operation of other distribution facilities not

includable elsewhere.

100-23 Preventative Maintenance –

Distribution

Costs associated with scheduled or routine operational work and minor repairs as they relate

to (i) individual meter sets that require less than 30 minutes for single run sets and less than

60 minutes for double run sets; (ii) propane equipment; and (iii)stations including testing,

calibration and minor housekeeping that require less than 30 minutes for single run sets and

less than 60 minutes for double run sets, as well as scheduled heater overhauls.


68X General - Operation 500 / 800 General Operation / Business

and IT Services684 Communication This account shall include the cost of labour, supplies and expenses

incurred in the operation of the facilities used wholly or

predominantly in connection with the general communication

system.

N/A N/A N/A - the only "facilities" that the FEU have that are used wholly or predominantly in

connection with a communication system are the radio towers. O&M costs related to these are included in 400-21 and 400-11 and

are not separately tracked.

685 System Operation and

Engineering

This account shall include the cost of labour, supplies and expenses

incurred at the general offices of the company for the operation

and engineering of the gas system.

500-30 Operations Engineering Cost of labour and other expenses for the department managers and system planning

engineers. Department managers are responsible for project management and professional

services to meet the requirements of asset managers throughout the project lifecycle

including (i)Front End Engineering and Design (FEED), (ii) project justification, (iii) design and

construction; and (iv) operation and maintenance.

Engineering is not split between operations and maintenance type

of activities; any such allocation would be arbitrary

Page 3


Activity Based





688 Other General Operations This account shall include the cost of labour, supplies and expenses

incurred in general operations and not includable elsewhere.

500-10 Facilities Management Costs for the management of various facilities, including:

• maintenance of coastal buildings

• renting, operating and maintaining interior buildings

• labour and other expenses incurred in the general supervision and direction of the Facilities

group

• telecommunications management

• rental and storage of office furniture and files

• maintenance of office equipment (lower mainland and interior offices)

• mailroom/reception

• printer consumables – toners/papers

• courier and postage costs

• centralized office supplies in the Surrey mailroom500-20 Shops and Stores Cost of labour for the Shops, Stores and Warehousing Manager as well as the expenses for the

overall business unit manager and any inventory adjustments arising out of cycle counts.

Shops and Stores encompasses manufacturing services, trucking and warehousing.

500-40 Property Services Costs related to managing all land rights and land tenure issues, including property taxation,

acquisition and disposal, leases, right of way agreements, environmental reviews and First

Nations negotiations. Property services is responsible for the maintenance and security of all

pipeline rights of way; this includes third party crossing permits and inspections, sub-division

approvals, vegetation management, right of way patrol, public awareness and encroachment

removal.

500-50 System Integrity Costs incurred for developing and maintaining a comprehensive integrity management plan

for the gas distribution and transmission operating plant assets. The system integrity group

provides risk-based integrity management services related to operating plant and surrounding

natural hazards, principally focused on material defect, corrosion, geotechnical and hydro-

technical risks.

500-60 Environmental Health and Safety Cost of labour and other expenses incurred in providing environmental and occupational

health and safety governance; carrying out public and corporate safety activities; and

emergency planning.

500-70 Operations Governance Cost of labour and expenses of the Vice President Human Resources and Operations

Governance and his/her direct reports. Includes costs associated with Engineer in Training

program and the Governance Engineer role which is responsible for administration of the

internal Standards Maintenance process, monitoring the external Regulations and Legislation

as they apply to the technical side of the business (not including environment, health and

safety), coordinating and participating on investigation teams, and other technical

governance related activities as they arise.

689 General Operations Transferred

(Credit)

This account shall be credited with general operations costs

transferred to other accounts, such as costs transferred to overhead

during construction.

N/A N/A N/A There is a separate account for all overheads capitalized - there is

no split in the overhead rate between operations, maintenance

and administration

70X Distribution Sale Promotion - Operation N/A700 Supervision This account shall include the cost of labour, supplies and expenses

incurred in the general direction and of sales activities, except

merchandising, jobbing or work.

600-10 Marketing - Supervision Cost of labour, telecommunication and other expenses incurred in the general supervision

and direction of marketing activities. No significant differences noted.

701 Advertising This account shall include the cost of labour, supplies and expenses

incurred in advertising, which is designed to promote or retain the

use of utility service.

600-30 Corporate & Marketing

Communications

Cost of labour and expenses incurred for:

media monitoring

logo stationery

web communication and research

lifestyle campaigns

directory listings

advertising design and production

managers' forums

customer newletters

writing and editing services

crisis communication


709 Other Sales Promotion Expense This account shall include the cost of labour, supplies and expenses

incurred in connection with sales activities, except merchandising,

which are not includable

600-40 Marketing Planning & Development Cost of labour and expenses for other customer management activities not included

elsewhere No significant differences noted.

No significant differences noted. The FEU provide much more

detail than the USofA would required

Page 4


Activity Based





71X Distribution Customer Accounting - Operationexcept merchandising, which are not includable elsewhere. 700 Customer Care

710 Supervision This account shall include the cost of labour, supplies and expenses

incurred in the supervision and direction of the customer account

and collecting activities.

700-10 Customer Care - Supervision Cost of salaries and expenses for (i) contract administration, negotiation and review/audit; (ii)

bad debt administration, credit and collections, review and audit costs; and (iii) customer

communication including: “Get Comfortable” newsletters, Equal Payment Plan, heating

season and rate change advertising.

Costs include non-capitalized portion of Customer Contact Centre labour (CAFÉ front end).


711 Customers' Contracts and Orders This account shall include the cost of labour, supplies and expenses

incurred in work on customer applications and contracts.

712 Meter Reading and Bill Delivery This account shall include the cost of labour, supplies and expenses

incurred in reading customers' meters, and delivering gas bills.

713 Customers' Billing and

Accounting


incurred in the accounting of, and the billing to, gas customers.

714 Credit and Collection This account shall include the cost of labour, supplies and expenses

incurred in collecting and investigating customers' accounts.

718 Uncollectible Accounts This account shall be charged with amounts sufficient to

provide for, or to write off, losses from uncollectible accounts,

applicable to gas distribution operations. Concurrent credits shall

be made to account No. l45, "Allowance for Doubtful Accounts" or

account No. l40, "Accounts receivable - Trade" as applicable.

700-30 Bad Debt Management and

Administration

Costs associated with Rate 1-3 bad debt provision expense, recoveries and collection agency

commissions. Includes costs incurred, net of recoveries, in conducting lock offs for arrears,

vacant premises, seasonal, final reads and disconnect diversions to prevent unauthorized

consumption, as well as “Cap and Plug” activities as per instruction from Gas Safety Branch or

other agencies.

Includes costs incurred to:

• remove locks from locked off meters, vacant premises, seasonal, final reads and relighting

appliances, during and after work hours

• investigate complaints due to high bills

• identify/verify meter numbers corresponding to correct address and usage

• investigate customer calls relating to a switch, stopped, non-registering or noisy meter.


719 Other Customer Accounting

Operation


incurred in customer accounting not includable elsewhere.

700-40 Customer Management and Sales Cost of labour and expenses related to Rate 14 account management and recovery fees, one-

on-one management and liaison of large key account customers, energy use consultation,

new tariff code development. This account also includes the bad debt provision and credit

and collection for Rate 4 customers and above.


72X Administrative and General - Operation 900 Corporate Administration721 Administration Expense This account shall include the cost of salaries, supplies and expenses

incurred in connection with the general administration of the

company, which are assignable to specific executive, administrative

and general departments and are not chargeable to a specific

operating function.

900-11 Administration and General The expenses in this account include (i) salary, travel and other expenses for the President’s

cost centre; (ii) organizational costs such as Canadian Gas Association membership dues; and

(iii) other administrative/general costs not otherwise defined in the code of accounts. No significant differences noted.

Customer Contact700-20

No significant differences are expected once the mapping is

complete; more granularity is expected than what is currently

required in the US ofA

N/A currently - the FEU are working on a mapping of the cost centres that have been created

for the newly insourced customer care centre to accounts that are the same or similar to the

USofA accounts

Page 5


Activity Based





900-13 Finance and Regulatory Affairs Cost of labour, travel, supplies and other expenses incurred by the Finance and Regulatory

Affairs department in providing the following services:

• financial accounting and reporting

• asset accounting

• accounts payable

• regulatory reporting

• regulatory application preparation and filing

• budgeting and planning

This account also includes items such as BCUC assessment fees and external audit fees.

900-14 Corporate Centre and Shared

Services Fees

This account includes (i) management fees paid for services provided by any of the FEU

entities; and (ii) management fee received from any of the FEU entities for services provided

by the affiliated utility.

900-31 Community Relations Cost of labour and expenses incurred for community, municipal, government and aboriginal

relations/liaison.

Costs include corporate donations and sponsorships related to the environment, education

and community development.

900-40 Business Development Cost of labour and expenses for identifying and developing new business opportunities.

900-50 Human Resources Cost of labour and other expenses for human resource governance, administering payroll and

benefits, providing advisory services, recruiting and temporary staffing.

600-10 Marketing - Supervision Cost of labour, telecommunication and other expenses incurred in the general supervision

and direction of marketing activities.

600-30 Corporate & Marketing

Communications

Cost of labour and expenses incurred for:

media monitoring

logo stationery

web communication and research

lifestyle campaigns

directory listings

advertising design and production

managers' forums

customer newletters

writing and editing services

crisis communication

900-20 Forecasting Cost of labour and expenses for the employees involved in the development of annual and

long-term forecasts for customer additions and use rates.

800-10 Business & IT Services - Supervision Cost of labour, travel, office supplies, and other expenses incurred in the general supervision

and direction of business and information technology services operations

800-20 Application Management Costs for the overall data and application architecture for Terasen Gas, including:

SAP application

Click scheduling application

CAFÉ application

AM/FM and DCRS

Forecasting information system

WIN Gas Connect

middleware

Business intelligence applications such as BW

Intranet and internet

800-30 Infrastructure Management Cost of managing the overall technology environment and infrastructure architecture

including:

maintaining communication sites and overseeing radio site rentals

security and virus protection

network costs

LAN and WAN

server services

server hardware costs

maintenance of peripheral devices

application services such as e-mail and Citrix

800-40 Procurement Services Cost of labour and expenses related to the purchasing of goods and services including tender

development, contract maintenance, purchase order processing, inventory and supplier

management, training and general administration.

No significant differences noted. The FEU provide much more

detail than the USofA would required

Page 6


Activity Based





722 Special Services This account shall include the fees and expenses of professional

consultants and others for general services not applicable to a

particular operating function.

See resource view Contractor Costs See Resource ViewThis account would be more of a resource view than an activity

view. The account "contractor costs" provides this information.

723 Insurance This account shall include the premiums payable to insurance

companies against any loss which may be sustained by the

company. Where the company provides self-insurance, the reserve

accruals shall be charged to this account and credited to account

No. 290, "Insurance Reserve".

900-12 Insurance Cost of insurance coverage.


724 Injuries and Damage This account shall include all expenses (except legal expenses)

incurred in settlement of injuries and damage claims, including

losses not covered by insurance.

See resource view Fees and Administration Costs See Resource View This account would be more of a resource view than an activity

view. The account for this type of expense is a subaccount of the

"Fees and Administration Costs" account and is available if

required. Amount is immaterial for separate reporting in the

resource view.

725 Employee Benefits This account shall include payments or contributions to provide

pension in respect of past or current services of employees and

amounts paid or contributed including expenses incurred for the

relief or welfare of employees.

If the company has instituted a pension trust fund and/or a welfare

fund the contributions shall be charged to this account and

transferred to the fund.

If the company does not institute a pension or trust fund but makes

provision for a reserve against pensions and/or welfare, the reserve

accruals shall be charged and credited to account No. 29l, "Welfare

and Pension Reserves".

900-60 Other Post Employment Benefits Actuarial cost of providing other post employment benefits to retirees.

The full amount of employee benefits expensed is available

through the "resource view" and is not applicable to an activity

view. Benefits are recorded in a number of subaccounts within the

Labour Costs resource lines.

728 Other Administrative and

General Expenses

This account shall include the expenses incurred in connection with

the general management of the company not provided for

elsewhere, even if not allowable as an operating expense for

regulatory purposes.

N/A N/A N/A

All expenses are captured above

729 Administrative and General

Expenses Transferred (Credit)

This account shall be credited with the amounts of administrative

and general expenses which are allocated to other accounts or to

overhead charged to construction. The method and basis of

allocation shall be maintained in

subsidiary records.

N/A N/A N/A

There is a separate account for all overheads capitalized - there is


and administration

86X Transmission Maintenance

860 Supervision This account shall include the cost of labour, supplies and expenses

incurred at a division, district or similar field office in the general

supervision of the maintenance of the transmission system

facilities.

200-11 Transmission - Supervision Includes the cost of labour, travel, supplies and other expense for the VP, Gas Supply and

Transmission and all transmission management personnel.No significant differences noted. Supervision of both transmission

operation and transmission maintenance combined together for



864 Communication This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of facilities used wholly or

predominantly in connection with the transmission communication

system.

N/A N/A N/A - the only "facilities" that the FEU have that are used wholly or predominantly in

connection with a communication system are the radio towers. O&M costs related to these are included in 400-21 and 400-11 and

are not separately tracked.

865 Pipe Lines This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of transmission system pipe lines and

facilities.

200-31 Pipeline Maintenance This account collects the costs to manage the corrective maintenance of the lower mainland

and interior pipeline transmission lines.

This account also includes the costs associated with corrective maintenance around gas

control including:

• repairing faults with communication systems

• repairing faults with SCADA system

• modifying SCADA screen displays



incurred in the maintenance of transmission system compressor

stations and facilities.

200-32 Compression Maintenance This account includes the purchase of materials and cost of labour associated with the

compressors, engines, and ancillary equipment such as valves, transmitters, switches and

other such items that require repair or replacement.


Page 7


Activity Based






incurred in the maintenance of transmission system measuring and

regulating stations and facilities.

200-24 Gas Control Costs associated with planned maintenance around monitoring and/or controlling:

the flow of gas in the system

the odorization system

the operation of the compressor, regulator and valve stations in the system

the operation of the line heaters in the system

pressure in the system

flow imbalances

This account is not separated between transmission and

distribution or for operations vs. maintenance. The system is

operated as an integrated whole and any allocations would be

arbitrary. All costs are held in the gas control account

869 Other Transmission Maintenance This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of other transmission facilities not

includable elsewhere.

200-33 TPIP Maintenance This account includes all work done when a TP or IP pipeline is excavated for repair as a result

of defect indications found during inspections but excludes excavations where defects were

neither indicated nor found.No significant differences noted.

86X Distribution Maintenance870 Supervision This account shall include the cost of labour, supplies and expenses

incurred in the general supervision and direction of maintenance of

the distribution system facilities.

100-11 Supervision - Distribution Cost of labour, vehicles, travel, supplies and other expenses incurred in the general

supervision and direction of distribution facility operations. Includes expenses associated

with:

• Regional Managers, Field Managers, Field Operations Assistants, and Clerical staff in

regional locations

This account also includes third party costs to conduct customer satisfaction surveys, risk

assessments and environmental audits.

No significant differences noted. Supervision of both distribution

operation and distribution maintenance combined together for



872 Structures and Improvements This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of structures and improvements for

the distribution system.

100-34 Distribution Corrective Maintenance

- Stations

This account includes cost of overhauls, determined at time of operational checks, as well as

repairs to buildings, structures, regulators, reliefs, valves, piping and associated equipment. No significant differences noted.

874 Equipment on Customers'

Premises


incurred in the maintenance of equipment owned by the company

on customers' premises, such as automatic water heaters and

conversion burners. See account No. 576, "Rent from Company

Equipment on Customers' Premises".

N/A N/A N/A - the FEU do not have this type of equipment on customers' premises

N/A for the FEU

875 Mains and Services This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of mains and services for the

distribution system.


- Leak Repairs

Costs incurred in pinpointing and repairing a gas leak, including (i) leaking valves, where the

leak is on a TP (transmission pressure), IP (intermediate pressure), DP (distribution pressure)

or LP (low pressure) main; (ii) leaks on a service; and (iii) leaks that are not repaired by cutting

off and abandoning a section of unused main or by carrying out a renewal of main over 6

meters.



incurred in the maintenance of compressors for the distribution

system.

N/A N/A N/A - the FEU do not have compressor stations in the distribution network - only in

transmission. N/A for the FEU


incurred in the maintenance of distribution system measuring and

regulating and facilities.


- Meters

Meter sets - Costs related to (i) inches, instrument drives, and OFM meter set overhauls which

are determined during operational checks, (ii) miscellaneous meter maintenance such as:

raise, code violations, inspecting and testing meter sets and alterations to bypass assemblies;

and (iii)relighting a residential meter set after maintenance work completed (incurred only

when an additional call is required for relight).

Meter devices - Costs related to (i) duties performed to make repairs to the automatic meter

reading devices and electronic/control equipment; (ii) troubleshooting and repairs on

portable instruments used to evaluate or test system operations; and (iii)repairs and repair

contracts for SCADA (Supervisory Control and Data Acquisition) - system that Gas Control uses

to monitor, control and manage the transmission system.

878 Meters This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of meters for the distribution system.

No significant differences noted; one group looks after

maintenance of both the measuring equipment and the meters

Page 8


Activity Based





879 Other Distribution Maintenance This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of other distribution system facilities

not includable elsewhere.


- General

Includes costs incurred in:

• resetting or replacing valve boxes

• replacement of stem packing, o-rings, valve stops and road box height adjustment

• paving repair

• main clearing operations

• maintaining main ditches, bell holes and other street cuts

This account also includes other general maintenance related to the distribution system not

specifically described in accounts 100-31 through 100-34.


88X General Maintenance884 Communication This account shall include the cost of labour, supplies and expenses

incurred in the maintenance of facilities used wholly or

predominantly in connection with the general communication

system.

N/A N/A N/A

These accounts would be captured within the General Operations

categories and there is no split of acitivities between maintenance

vs. operations for these items

885 System Maintenance and

Engineering


incurred at the general offices of the company for the maintenance

of the gas system.

N/A N/A N/A These accounts would be captured within the General Operations



888 Other General Maintenance This account shall include the cost of labour, supplies and expenses

incurred in the general maintenance of the gas system and facilities

not provided for elsewhere.

N/A N/A N/A These accounts would be captured within the General Operations



889 General Maintenance

Transferred (Credit)

This account shall be credited with general maintenance costs

transferred to other accounts, such as costs charged to overhead

during construction.

N/A N/A N/A There is a separate account for all overheads capitalized - there is


and administration

Page 9





FACSIMILE: (604) 660-1102

Log No. 44029

PF/FEI/PBR 2014-2018/A2-14-BCUC Letter -Compliance Filing -FEU-Uniform System of Accounts Report






Commission staff submits the following document for the record in this proceeding: Commission letter dated December 3, 2012 – Compliance Filing - FortisBC Energy Utilities – BCUC Uniform System of Accounts Report. Yours truly, Erica Hamilton SS/dg Enclosure cc: Registered Interveners (FEI-PBR-2014-18-RI)


ERICA HAMILTON

COMMISSION SECRETARY

[email protected] site: http://www.bcuc.com

VIA EMAIL

[email protected]

Ms. Diane RoyDirector, Regulatory AffairsFortisBC Energy Inc.16705 Fraser HighwaySurrey, BC V4N OE8

Dear Ms. Roy:

December 3, 2012

SIXTH FLOOR, 900 HOWE STREET, BOX 250

VANCOUVER, BC CANADA V6Z 2N3

TELEPHONE: (604) 660-4700

Be TOLL FREE: 1-800-663-1385

FACSIMILE: (604) 660-1102

Log No. 41494

Re: FortisBC Energy Utilities2012 - 2013 Revenue Requirements and Natural Gas Rates Application

Decision dated April 12, 2012 and Order No. G-44-12 - Compliance FilingBCUC Uniform of Accounts (USoA) Report

On April 12, 2012 the British Columbia Utilities Commission (Commission or BCUC) issued its Decision, by way ofOrder G-44-12, on the FortisBC Energy Utilities (FEU) 2012-2013 Revenue Requirements and Natural Gas RatesApplication. Directive 63 of Order G-44-12 directs FEU to investigate the cost of fully converting to the BCUCUniform System of Accounts (USoA) and file a proposed plan for conversion.

On October 10, 2012 FEU submitted a compliance filing in response to this Directive. In the compliance filing,FEU stated that it did not prepare a plan to fully adopt the USoA as directed; rather it submitted a report on theUSoA to address the underlying concerns of the Directive and proposed an alternate approach.

The Commission has reviewed FEU's proposed alternate approach and accepts it for the next RevenueRequirements Application (RRA) only. In the next RRA the Commission will assess whether FEU is required toeither comply with Directive 63, continue with the alternate approach for further RRA's, or implement someother approach as the Commission finds appropriate at that time.

Yours truly,

~~:Erica Hamilton

CM/kbcc: Registered Interveners

(FEU-2012-13RR)

IP/Corr/FEU/12-03-2012JEU BCUC Uniform System of Accounts Report

A2-14

dguest

FEI-2014-2018RR





FACSIMILE: (604) 660-1102

Log No. 44029

PF/FEI/PBR 2014-2018/A2-15-FEU-Uniform System of Accounts Report - Response to IR No. 1






Commission staff submits the following document for the record in this proceeding: FortisBC Energy Utilities - Uniform System of Accounts Report – Response to Information Request No. 1. Yours truly, Erica Hamilton SS/dg Enclosure cc: Registered Interveners (FEI-PBR-2014-18-RI)


February 22, 2012 British Columbia Utilities Commission Sixth Floor 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Ms. Erica M. Hamilton, Commission Secretary Dear Ms. Hamilton: Re: FortisBC Energy Utilities1 (“FEU”)

2012 and 2013 Revenue Requirements and Natural Gas Rates Application (the “2012-2013 RRA”) - British Columbia Utilities Commission (“BCUC” or the “Commission”) Decision dated April 12, 2012 and Order No. G-44-12 (the “Decision”)

BCUC Uniform System of Accounts (“USoA”) Report

Response to the British Columbia Utilities Commission (“BCUC” or the “Commission”) Information Request (“IR”) No. 1

On October 10, 2012, the FEU filed the Report on the USoA in compliance with BCUC Order No. G-44-12. On February 13, 2013, the Commission responded with an Email containing BCUC IR No. 1. FEI respectfully submits the attached response to BCUC IR No. 1.

If there are any questions regarding the attached, please contact the undersigned.

Yours very truly, on behalf of the FORTISBC ENERGY UTILITIES Original signed by: Ilva Bevacqua

For: Diane Roy Attachment

1 Comprised of FortisBC Energy Inc., FortisBC Energy (Vancouver Island) Inc., FortisBC Energy (Whistler) Inc., and FortisBC Energy Inc. Fort Nelson Service Area.

Diane Roy Director, Regulatory Affairs - Gas FortisBC Energy Inc.

16705 Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) 576-7349 Cell: (604) 908-2790 Fax: (604) 576-7074 Email: [email protected] www.fortisbc.com Regulatory Affairs Correspondence Email: [email protected]

A2-15













dguest

FEI-2014-2018RR

FortisBC Energy Utilities ("FEU" or the “Companies”)

British Columbia Utilities Commission (“BCUC” or the “Commission”) Uniform System of Accounts (“USoA”) Report

Submission Date:

February 22, 2013

Response to British Columbia Utilities Commission (“BCUC” or the “Commission”)

Information Request (“IR”) No. 1 Page 1

FEU 2012-2013 RRA, Exhibit B-53, Undertaking No. 25, Communications related cost 1

elements by the ES&ER business area 2

http://www.bcuc.com/Documents/Proceedings/2011/DOC_28803_B-53_FEU-Undertaking-3

25.pdf 4

“...Please note that these costs elements reflect advertising costs incurred by the Utilities, 5

included in which are costs for publication of notices for regulatory applications and proceedings 6

as a result of Commission orders from time to time as required. 7

Undertaking No. 25 8

63303 Communications, Public Relations 9

63304 Communications Employees 10

63401 Advertising Media 11

63402 Advertising Printed Matter 12

63403 Miscellaneous Advertising” 13

1. Will the new COA have a separate activity or resource code for publication of notices for 14

regulatory applications and proceedings? FEU was unable to segregate these costs in 15

the last RRA. 16

17

Response: 18

The new COA will not have a separate resource code for publication of notices for regulatory 19

applications and proceedings. This is because the new COA tracks O&M expenses, and the 20

publication of notices for regulatory applications and proceedings is not recorded as an O&M 21

expense. These costs are instead recorded in the various deferral accounts relevant to the 22

application(s) in question. However, FEU is able to report on how much is spent on these costs 23

through separate tracking within the deferral accounts as requested. 24

25

26

2. Has FEU eliminated the use of cost Elements in new COA? 27

28

Response: 29

No. Cost elements are captured within the resource view form of reporting (one level below the 30

resource view) and the FEU will continue to use cost elements to capture costs, including the 31

five cost elements listed above. 32

http://www.bcuc.com/Documents/Proceedings/2011/DOC_28803_B-53_FEU-Undertaking-25.pdf

http://www.bcuc.com/Documents/Proceedings/2011/DOC_28803_B-53_FEU-Undertaking-25.pdf



Submission Date:

February 22, 2013



1

Biomethane Service Offering: PIR and Application, Exhibit B-4, Slide 27 2

http://www.bcuc.com/Documents/Proceedings/2013/DOC_33226_B-4_FEI-3

WorkshopPresentationMaterials.pdf 4

5

“Must continue to pursue an integrated customer education plan 6

• Bill inserts 7

• Direct Sales 8

• Website 9

• Promotions 10

3. The Biomethane customer education plan includes costs for bill inserts, direct sales, 11

website and promotions.; will the new COA be able to segregate these costs? 12

13

Response: 14

The FEU will continue to track total customer education costs for the company’s biomethane 15

service offering separately and have the ability to report these amounts as required, however, 16

the new COA will not show these four items segregated. 17

18

19

20

Account Code 300-14 Corporate Communications, Marketing and Public Affairs 21

• Safety Education 22

• Media Monitoring 23

• Web Monitoring 24

• Paid Media Design and Production 25

• Customer newsletters 26

• Crisis communications 27

• Social Media 28

4. Are there separate costs centres for Aboriginal, Community and Government Relations 29

in account code 300-14? 30

http://www.bcuc.com/Documents/Proceedings/2013/DOC_33226_B-4_FEI-WorkshopPresentationMaterials.pdf

http://www.bcuc.com/Documents/Proceedings/2013/DOC_33226_B-4_FEI-WorkshopPresentationMaterials.pdf



Submission Date:

February 22, 2013



1

Response: 2

No, each of these costs is not captured in a separate cost center. One cost centre that rolls up 3

to account code 300-14 holds the Aboriginal, Community and Government Relations costs as 4

well as all other public affairs activities. This is because employees in this business group share 5

a similar skill set and are therefore able to work with more than one stakeholder group. This 6

arrangement also allows the group to garner efficiencies through the sharing of resources for 7

the various activities. 8

9

10

11

5. Is there a method for segregating the various costs listed below in Corporate 12

Communications, Marketing and Public Affairs account code? 13

• 200 - 12 Customer Assistance – includes customer education 14

• 200 - 16 Customer Operations – includes customer education 15 16

Response: 17

No, they cannot be segregated as the various activities/ programs listed are not mutually 18

exclusive. For example, safety education could take the form of customer newsletters and paid 19

media, social media activity could encompass web monitoring, etc. 20

21

22

23

6. Customer education costs are included in the Customer Service accounts (200-XX), but 24

not in the Energy Solutions accounts (300-XX). Commission staff would like to track 25

customer education costs throughout FEU. Could account codes be created for 26

customer education costs in the Customer Service and Energy Solutions accounts? 27

28

Response: 29

Customer education encompasses a broad category of activities which is carried out through 30

various mediums and is not a distinct and mutually exclusive activity. For this reason, it cannot 31

be successfully and accurately segregated. 32

Within Customer Service, customer education is a component of Customer Assistance, not a 33

separate action. Most education happens when a customer contacts FEU with questions or 34



Submission Date:

February 22, 2013



concerns related to their service or their bill. As it is an integrated part of the service the contact 1

center provides to customers, it cannot be tracked separately as an independent cost. 2

Similarly, in Energy Solutions customer education is a daily integrated activity when staff 3

interact with both existing and potential customers, and therefore cannot be tracked separately. 4

5

6

7

7. The below is a list of some of the AES Decision Directives in Appendix H. Do you know 8

when the COA will be updated to reflect the requirements in the AES Decision? 9

10

• Biomethane Service is a Separate Class of Customer within the natural gas class 11 of service. 12

• CNG activities undertaken as Prescribed Undertakings, are to be structured as a 13 Separate Class of Service with the costs to be recovered from the traditional gas 14 utility ratepayers, to the prescribed limit. 15

• The FEU undertake CNG activities outside the Prescribed Undertaking in a Non-16 Regulated Business. 17

• LNG activities undertaken as Prescribed Undertakings are to be maintained as a 18 Separate Class of Service with the costs recoverable from the traditional natural 19 gas ratepayer. 20

• FEU participate in LNG activities outside the Prescribed Undertaking through a 21 separate Non-Regulated Business 22



Submission Date:

February 22, 2013



1

Response: 2

To assist in responding, FEI has categorized the above excerpts from the AES Inquiry Report 3

into Directives and Recommendations, with responses under each of the items. 4

Directives: 5

1. Biomethane Service is a Separate Class of Customer within the natural gas class of 6

service. 7

Since Biomethane Service is within the natural gas class of service, and the accounts to 8

capture the revenues from the Biomethane rate schedules already exist, no changes to the 9

COA are anticipated. 10

2. CNG activities undertaken as Prescribed Undertakings, are to be structured as a Separate 11

Class of Service with the costs to be recovered from the traditional gas utility ratepayers, to 12

the prescribed limit. 13

FEU will not require any changes to the COA to accommodate the Prescribed Undertakings, 14

since these activities can be accommodated within the existing COA. Costs associated with 15

the Prescribed Undertakings are will be tracked and reported separately through orders set 16

up in the SAP system. 17

3. LNG activities undertaken as Prescribed Undertakings are to be maintained as a Separate 18

Class of Service with the costs recoverable from the traditional natural gas ratepayer. 19

Same response as for #2 20

21

Recommendations: 22

1. The FEU undertake CNG activities outside the Prescribed Undertaking in a Non-Regulated 23

Business. 24

2. FEU participate in LNG activities outside the Prescribed Undertaking through a separate 25

Non-Regulated Business 26

The FEU have not made a determination on the impact of these recommendations yet, and 27

is instead focusing efforts on CNG and LNG activities under Prescribed Undertakings. 28

However, if FEI were to capture these activities as a separate Non-Regulated Business, 29

then this business would not be using the FEU’s COA so no changes to the COA would be 30

required. 31



Submission Date:

February 22, 2013



1

2

Resource View 3

2000 Employee Expenses 4

• Travel – tax deductible 5

• Meals– tax deductible 6

• Entertainment – tax deductible 7

• Conferences – tax deductible 8

• Travel - non-Tax deductible 9

• Meals – non-Tax deductible 10

• Entertainment- non-Tax deductible 11

• Conferences – non-Tax deductible 12

5000 Fees and Administration Costs 13

• Newspaper Advertising 14

• Television Advertising 15

• Radio Advertising 16

• Website 17

• Social Media 18

• Direct mail 19

• Bill inserts 20

• Printed Matter 21

• Display materials for exhibits 22

• Decals for CNG and LNG 23

• Advertising on transit vehicles, bus shelters, bill boards, posters, stadium and 24 building advertising 25

7000 Contractor Costs 26

• Consulting Fees- Legal 27

8. The Resource View in the draft COA shows nine major resource types (1000-9000). 28

Can resource codes listed below be added to the Employee Expenses, Fees and 29



Submission Date:

February 22, 2013



Administration, and Contractor Costs to provide a more detailed breakdown of the O&M 1

costs? 2

3

Response: 4

FEU use the following resource codes to capture costs: 5

2000 Employee Expenses 6

- Employee Travel (non-training) 7

- Employee Travel (training) 8

- Meals & Entertainment (non-training) 9

- Meals & Entertainment (training) 10

- Meals & Entertainment (restricted HST) 11

5000 Fees and Administration Costs 12

- Advertising – Media 13

- Advertising – Printed Matter 14

- Advertising – Miscellaneous 15

7000 Contractor Costs 16

- Legal fees & Retainers 17

These resource codes capture total costs to the organization (only some of which are O&M, 18

while others are capital or recoverable in nature). For major resource code groupings such as 19

Employee Expenses or Advertising, individual settlement accounts capture the recovery of the 20

non-O&M portion of the expenditure and therefore the O&M only portion can be separated out 21

and reported in the Resource View. Since FEU does not have individual settlement accounts at 22

the lowest level shown above, the O&M portion is not separately available at that level of detail 23

and cannot be provided as requested. If there is a requirement to know the total costs (O&M 24

and capital) at this level of detail, it can be provided in information requests, but the O&M 25

portion only is not known at this lower level and cannot be included as a resource view line. 26

FEU will need to update / create additional SAP reports in order to provide this detail. FEU will 27

be able to include the additional resource codes for Employee Expenses, Advertising and Legal 28

Fees/Retainers beginning with the 2013 Annual Report. 29

30

31

FortisBC Energy Inc. (FEI or the Company) Application for Approval of a Multi-Year Performance Based Ratemaking Plan for 2014

through 2018 (the Application)

Submission Date: November 27, 2013

Response to British Columbia Utilities Commission (BCUC or the Commission) Information Request (IR) No. 2

Page 222

FINANCING, TAXES, ACCOUNTING POLICIES AND DEFERRALS 1

308.0 Reference: FINANCING, TAXES, ACCOUNTING POLICIES AND DEFERRALS 2

Exhibit B-1, Tab C, Section 3.1.2, p. 122; Exhibit B-1-1, Appendix F6; 3 Exhibit A2-13; Exhibit A2-14; Exhibit A2-15; BCUC Order G-44-12 and 4 2013-2013 FEU Decision dated April 12, 2012, pp. 140-142 5

BCUC UNIFORM SYSTEM OF ACCOUNTS (USoA) 6

308.1 Four basic options for recording and reporting of O&M expenses for management 7 and for regulatory purposes are listed below; please provide a schedule that 8 compares and contrasts the advantages and disadvantages, and material costs 9 and benefits associated with each of these basic options, which are described as 10 follows: 11

12 a. use only FEU’s New Code of Accounts for recording and reporting of 13

O&M expenses for both management and regulatory purposes. 14 15

b. use only the BCUC USoA for recording and reporting of O&M expenses 16 for both management and regulatory purposes. 17

18 c. use only FEU’s New Code of Accounts for recording and reporting of 19

O&M expenses for management purposes. However, to enable 20 regulatory reporting, create a “mapping relationship,” which features 21 permanent links, created at inauguration, between the BCUC USoA for 22 O&M expenses and those in FEU’s New Code of Accounts. 23

24 d. use two completely separate accounting systems, one which requires use 25

of the BCUC USoA for O&M expenses, and one which uses the FEU New 26 Code of Accounts for O&M expenses. The former is used for recording 27 and reporting for regulatory purposes, whereas the latter is used for 28 recording and reporting for management purposes. 29

30 Response: 31

As stated in the BCUC Uniform System of Accounts Report included in Exhibit A2-13 (the Report), 32 the FEU continue to believe that their existing New Code of Accounts approach provides more 33 meaningful and comparable information than the BCUC USoA, which has not been substantially 34 updated since 1961, and at no additional cost to customers. In the Report, the FEU base this 35 conclusion on the following: 36

1. Other than O&M accounts, the FEU are already meeting existing 1961 USoA requirements; 37





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2. Full implementation of a new USoA would result in additional costs being borne by 1 customers with no guaranteed improvement in understanding or comparability; 2

3. For O&M accounts, flexibility is required amongst the utilities in BC to determine a method 3 that meets the objectives of comparability, transparency and understanding of results over 4 time; 5

4. The FEU already have a fully reviewed and agreed-upon New Code of Accounts that meets 6 those objectives; and 7

5. The FEU have reviewed the BCUC and other USoAs for O&M and have concluded that 8 none of the ones reviewed would provide a measurable improvement over the existing New 9 Code of Accounts. 10

11 The conclusion reached in the Report is also supported by the analysis provided in the following 12 table that was prepared in response to this IR. 13

Option Management Regulatory Advantages Disadvantages

a New COA New COA

* No incremental conversion or ongoing cost * Meets business requirements * Provides more information than what would be provided by the BCUC USoA * Already reviewed and approved Meets objectives: * Comparability - provides consistent information to 2006 * Transparency - detailed questions can be answered through drilldown to source document * Transparency - totals agree to business unit totals included in RRA narratives and tables * Flexible - adapts to changes in structure & business * Flexible - allows for modifications to achieve additional granularity required by the BCUC * Understanding - assigns responsible owners for the information provided that aligns with how the business is managed

* None

b BCUC USoA BCUC USoA

* None - no evidence that more information would be provided by BCUC USoA

* FEU is not able to manage its costs using BCUC USoA; therefore this is not an option as BCUC cannot mandate this for the FEU for management purposes.





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Option Management Regulatory Advantages Disadvantages

c New COA BCUC USoA (mapping)


* No current ‘mapping relationship’ exists between BCUC UsoA for O&M and FEU New Code of Accounts – an undertaking would be required to create such a mapping * Adds ongoing costs for ratepayers * Adds no incremental information beyond what is achieved with current reporting * Requires all users in the company to add another coding block to the existing source document entry * Requires manual judgement to set up cost allocations * Historical information not available so no comparability over time * No "drill down" available * No issue of comparability with other utilities in BC so no requirement for a standardized USoA * Previously found unworkable

d New COA

BCUC USoA (separate system)


* Adds significant costs for ratepayers - both one time and ongoing * Requires all users in the company to enter data into two different systems * Adds no incremental information beyond what is achieved with current reporting * Requires manual judgement to set up cost allocations * Historical information not available so no comparability over time * No "drill down" available * No issue of comparability with other utilities in BC so no requirement for a standardized USoA * This would be an unacceptable solution

1

As stated in the Report, the FEU proposed to continue with the New Code of Accounts, and to 2 undertake a project to implement a number of changes to respond to the Commission’s concerns. 3 The FEU restate here each one of these changes and what the status of each of them is. 4

1. Work with Commission staff to review and modify their New Code of Accounts to more fully 5 address Commission’s concerns with receiving information that is comparable, transparent, 6 and understandable; 7

Status: The FEU have met with Commission staff but did not receive any feedback on 8 modifications to the New Code of Accounts to address their concerns. To date, the 9 Commission staff has not articulated what concerns need to be addressed. The FEU are 10 unable to address the concerns since there has been no communication about what 11 additional information the BCUC USoA is expected to provide as compared to the existing 12





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New Code of Accounts. However, the FEU remain committed to modifying the New Code of 1 Accounts to meet those requirements once they have been communicated. 2

3 2. Provide the Commission with an updated description of the Activity View of the New Code of 4

Accounts prior to filing its next RRA; 5

Status: The FEU have provided the Commission staff with an updated description of the 6 New Code of Accounts in February 2013, April 2013 and again in May 2013, just prior to 7 filing this Application. 8

9 3. Implement the required revisions to the New Code of Accounts (Activity View and Resource 10

View) into the SAP accounting system with no incremental cost to customers; 11

Status: The FEU have implemented the changes into their SAP accounting system to 12 create the current versions of the New Code of Accounts with no incremental cost to 13 customers. 14

15 4. Provide test year information and 5 year historical information in future Revenue 16

Requirement filings that includes the modified New Code of Accounts; 17

Status: The FEU have provided the 2014-2018 and 5 year historical information in this 18 Application using both the Resource View and the Activity View of the modified New Code of 19 Accounts in Appendix F6 of the Application. 20

21 5. Provide tables in its written descriptions of the forecast and historical O&M changes in future 22

Revenue Requirement filings that reconcile to the Activity View of the New Code of 23 Accounts; 24

Status: The tables provided in Section C-3 of this Application reconcile to the totals 25 provided in Appendix F6. 26

27 6. Provide ongoing updates to the Activity View of the New Code of Accounts to the 28

Commission as required; and 29

Status: There have been no changes required to the Activity View of the New Code of 30 Accounts since the last version provided to Commission staff. 31

32





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7. Continue to report using the Activity View and Resource View of the New Code of Accounts 1 (in combination with the 1961 USoA for the remaining accounts) in its BCUC Annual 2 Reports. 3

Status: FEU will provide this information in BCUC Annual Reports starting with 2013. 4

5 6

7 8 In Exhibit A2-13, section 4.3, page 12, FEI states, “…the FEU have met with Commission 9 staff and other major utilities in BC regarding this issue.” (Exhibit A2-13, p. 12) 10

In Exhibit A2-13, section 4.1, page 8, FEI states, “…each cost centre in the FEU’s SAP 11 system has a responsible cost centre owner, and cost centres are grouped under one 12 account that has a common activity.” (Exhibit A2-13, p. 8) 13

308.2 Please name the major utilities in BC that FEU met with “regarding this issue.” 14 15

Response: 16

FEU met with FBC, BC Hydro and Pacific Northern Gas, and subsequently this same group of 17 major utilities met with BCUC staff regarding this issue. 18

19 20

21 308.2.1 Are any of these named major utilities in BC using an SAP system similar 22

to that used by FEU? If yes, please name them. 23 24

Response: 25

Both FBC and BC Hydro utilize the SAP system. However, SAP is not an “off the shelf” software 26 package. Each installation is customized to the individual entity. So while there will be some 27 commonality (such as the use of cost elements and cost centres), each company will have 28 implemented different modules and designed their reporting in a different fashion. Some systems 29 are extremely integrated while others may involve only certain modules of SAP and rely on other 30 systems to feed data into the SAP system. Therefore, the fact that SAP is used by other entities 31 does not result in the ability to perform the same task in the same manner or report on the same 32 information in the same way. 33





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1 2

3 308.2.2 In reference to the immediately preceding question, will/have any of the 4

named major utilities in BC adopted the BCUC USoA (with or without 5 customization) for the regulatory reporting of O&M expenses? If yes, 6 please identify them and indicate if a customization of the BCUC USoA 7 will be/was involved. 8

9 Response: 10

FBC reports its O&M Expenses using a customized version of the USoA in its Annual Report to the 11 BCUC. The Company does not use the USoA for any other purpose. 12

BC Hydro reports its O&M Expenses using a customized version of the USoA in its Annual Report 13 to the BCUC. BC Hydro also attached an appendix to its F12-14 RRA with the customized USoA 14 view for O&M. 15

PNG complies with the USoA in its regulatory reporting of O&M expenses without customization, 16 both in its Annual Report to the BCUC and its RRAs. 17

18 19

20 308.2.3 In reference to the immediately preceding question, is FEI able to 21

comment specifically on how these identified major utilities in BC will/have 22 achieved the adoption of the BCUC USoA for the regulatory reporting of 23 O&M expenses (e.g. through a one-time mapping process), and the effort 24 and the costs, which will be/were incurred as a result. If you are not able 25 to comment, please explain why. 26

27 Response: 28

FBC performs the necessary mapping manually once a year in order to complete its Annual Report 29 to the BCUC according to the USoA. FBC determined that the costs associated with the software 30 mapping function did not add value to the corporate reporting requirements. 31

BC Hydro’s SAP system facilitates the mapping to the USoA O&M accounts. BC Hydro was 32 directed to implement the USoA in its F09/F10 RRA Decision. As BC Hydro implemented its SAP 33 system, it incorporated the USoA using the SAP financial systems as well as manual procedures. 34





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PNG’s financial system was originally set up to accommodate the BCUC USoA and no 1 amendments have been made. 2

As the effort and cost associated with reporting using the USoA for O&M accounts will vary 3 depending on the management structure of the utility, the size of the utility, whether the 4 implementation is incorporated in the original design of a system, and the level of detail available, 5 among other factors, no conclusion should be drawn on the appropriate cost to implement. This is 6 supported by the wide range of costs reported by the various utilities in Alberta as summarized in 7 response to BCUC IR 2.308.3. 8

9 10

11 308.2.4 If any of these above identified major utilities in BC developed a 12

customized version of the BCUC USoA for regulatory reporting of O&M 13 expenses, is FEI able to comment specifically on which aspects of the 14 BCUC USoA were/will be customized and why. If you are not able to 15 comment, please explain why. 16

17 Response: 18

The FEU provide comments on FBC and BC Hydro, as both of these utilities developed a 19 customized version of the BCUC USoA for O&M for Annual Reporting to the BCUC. 20

FBC’s amendments to the O&M accounts were required for the following reasons: 21

� Impracticality of separating “operation” from “maintenance” functions in the USoA; 22

� Inability to accurately assign supervision, administration and some engineering functions 23 between transmission and distribution and between overhead and underground facilities; 24 and 25

� Some amendments to more accurately reflect organizational structure. 26

27 BC Hydro adopted the BCUC USoA, with amendments to reflect BC Hydro’s business 28 circumstances. These were discussed with BCUC staff in the process of developing the 29 customized USoA. The specific amendments made are as follows: 30

(i) Generally, BC Hydro is keeping costs that would otherwise require allocation to USoA functions 31 in individual USoA general or administration operating accounts for reporting alignment 32 purposes. 33





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Specific items that are treated in this manner are support activity costs; e.g., information 1 technology, materials management, fleet management, First Nations, properties management, 2 environmental and safety support, construction services support and legal support, that are 3 managed centrally and not associated with the specific core functions of generation or 4 transmission; and other support costs that are not currently centralized; e.g., engineering 5 support, finance and human resources. 6

Rationale: The support activity costs generally are managed centrally. For those areas that are 7 not currently centralized, the support area is still subject to centralized oversight and common 8 programs and strategies. BC Hydro believes that this structure provides for accountability for 9 management of these activities and related costs. 10

(ii) Indirect work activities (that is, costs other than maintenance or operating work attributable to 11 an asset) are classified as Supervision and Engineering within their appropriate functions, 12 unless the function performed is directly aligned with an existing BC Hydro USoA account. 13

Rationale: BC Hydro believes that retaining these costs under one account provides for 14 stronger accountability for the work. This is because the managers responsible for those 15 activities continue to have accountability for those costs, whereas the accountability would be 16 lost if the employees’ time and costs are reallocated to other work activities. 17

(iii) Stations and load dispatch activities are centrally managed on a combined basis and the 18 associated O&M expenses cannot easily be split between the transmission and distribution 19 functions. For administrative simplicity and in accordance with the major use, BC Hydro is 20 classifying stations and load dispatch activities as activities related solely to the transmission 21 function. 22

Rationale: With the re-integration of activities that were previously managed by BCTC, it is 23 administratively simpler not to distinguish between the transmission and distribution function of 24 its station assets for cost distribution purposes. BC Hydro assigns a portion of these costs to 25 the distribution function in the calculation of the OATT. 26

(iv) The costs of labour, inclusive of cash compensation, benefits, and time concessions are 27 distributed to work. Current service employee benefits are not reported separately. 28

Rationale: BC Hydro believes that the labour cost associated with work should include all 29 relevant direct costs, including benefits and time concessions. Reporting these employee 30 benefits separately will result in understating the cost of work. This is particularly relevant 31 where BC Hydro needs to determine whether it is beneficial to utilize contract labour. BC Hydro 32 continues to be able to measure and report the total amount of employee benefits, if this is 33 necessary. 34





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(v) Costs related to external energy purchases and to the allocation of capital costs are shown 1 separately, rather than being assigned to the appropriate USoA operating account. 2

Rationale: The costs of purchased energy are captured within an individual account. 3 Historically, BC Hydro has separated the cost of energy from operating costs. Therefore, the 4 BC Hydro USoA account for energy is not included in the operating cost schedule. 5

6 In reviewing these lists from FBC and BC Hydro, the FEU conclude these differences are very 7 similar to the list of differences provided in Attachment 3 to its Report that was filed with the 8 Commission. 9

10 11

12 308.2.5 Was there an opportunity to achieve “economies of scale” by having FEI 13

work together with any of these above identified major utilities in BC on, 14 for example, generic aspects of developing a BCUC USoA reporting view 15 for O&M expenses. If not, why not? 16

17 Response: 18

FBC, BC Hydro and PNG’s systems pre-date the FEI requirement. 19

The four utilities (FEU, BC Hydro, FBC and PNG) met with BCUC Staff on September 19, 2012 and 20 discussed USoA reporting issues. The utilities were of the view that efficiencies were not applicable 21 through economies of scale as the O&M section is unique to each utility and should reflect its 22 requirements to manage the business effectively. In addition, the utilities use different bases of 23 accounting. BC Hydro uses Prescribed Standards whereas the other utilities use US GAAP, so 24 comparisons between the utilities would be misleading on this basis alone. 25

26 27

28 29 In Exhibit A2-13, section 4.3, page 12 (including footnotes 3 and 4), FEI states, “ The FEU 30 expect that the adoption of a “one size fits all” approach to O&M accounts will result in 31 significant costs,3 both one time and ongoing. This expectation is based on the adoption of a 32 USoA for electric utilities in Alberta, which has resulted in both costs to make system 33 changes,4 and costs to support the provision of variance explanations for this alternate view 34 of O&M. 35





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Footnote 3: “…Cost estimates of fully adopting a USoA were provided by the affected 1 utilities and ranged from a low of $300 thousand to a high of $17.8 million for 2 implementation, and up to $2.8 million in annual operating costs.” 3

Footnote 4: “ An alternative adopted by some utilities in Alberta was to create an additional 4 coding block in their accounting system, requiring employees in the field to complete 5 additional fields to derive the information required on an ongoing basis.” 6

“For example, to capture the amount of time spent by transmission managers on operating 7 as opposed to maintenance activities, separate coding blocks would be added to the 8 system…”. “The FEU believe that this process would require and undue amount of the 9 transmission managers’ time and would not be cost effective.” 10

308.3 Please name the above affected utilities in Alberta and indicate the method (e.g. a 11 mapping process, separate accounting systems) each will/has used to develop a 12 USoA reporting view for O&M expenses. In addition, please also provide the cost 13 estimates for implementation and annual operating costs pertaining thereto. 14

15 Response: 16

Please refer to Attachment 308.3, which is Decision 2007-017 “EUB Proceeding - Implementation 17 of the Uniform System of Accounts and Minimum Filing Requirements for Alberta’s Electric 18 Transmission and Distribution Utilities”. This public document is the source for the FEU’s 19 information. The following table has been created from the information in that document (cost 20 estimate data taken from Table 2 in Attachment 308.3). 21

22

23

24 25

26

Electric Utility System Method Capital CostsAnnual Optg

CostsEPCOR Oracle Mapping 0.3 0.2ENMAX PeopleSoft New Chart Field 6.7 0.5ATCO Oracle Existing 0.4 0AltaLink SAP Special Ledger 17.8 2.8FortisAlberta SAP Profit Centre Acctg 15.6 1.6

40.8 5.1

($ millions)





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308.4 Please identify the above affected utilities in Alberta, if any, who are/will be using a 1 SAP system similar to that used by FEU. 2

3 Response: 4

Please refer to the responses to BCUC IR 2.308.3 and 2.308.2.1. 5

6 7

8 308.5 Please identify the utilities in Alberta who adopted the alternative of creating an 9

additional coding block in their accounting system. 10 11

Response: 12

From a review of the table provided in response to BCUC IR 2.308.3, the FEU conclude that Enmax 13 and AltaLink would have required an additional coding block to achieve the method indicated. 14 However, the FEU cannot confirm this. 15

FortisAlberta has created an additional ledger to accommodate the USoA for electric utilities in 16 Alberta that requires additional coding to meet the USoA requirements. 17

18 19

20 308.5.1 What type of accounting system did these utilities utilize? 21

22 Response: 23

Please refer to the response to BCUC IR 2.308.3. 24

25 26

27 308.5.2 Is FEI able to comment on the reasons why these utilities took the steps 28

to implement a process, which FEU judged “not to be cost effective”? If 29 not, please explain. 30

31





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Response: 1

The FEU understand that the adoption of the USoA was a result of a Board initiated process; it was 2 the Board that concluded these costs would add value based on the evidence in that process. The 3 Board’s discussion of the anticipated benefits is summarized in section 3.2 of the Attachment 308.3 4 provided in response to BCUC IR 2.308.3. An excerpt from that section is provided below. 5

“The EUB believes that the adoption and use of an activity-based USA similar to that used 6 by the United States Federal Energy Regulatory Commission will improve the ability to 7 compare financial information from year to year for a utility and, to the extent possible, 8 across utilities when testing the reasonableness of a utility’s filings and budgets. The EUB 9 and interveners will have greater confidence that the costs being considered are 10 comparable. This increased confidence, combined with MFRs based on information from the 11 USA, should result in more complete and comprehensive General Tariff Applications 12 (GTAs), a more efficient interrogatory process, and reduced cross-examination time at 13 hearings.” 14

The Board further stated in section 3.5: 15

“The Board has concluded that it cannot perform the usual quantitative analysis to compare 16 the dollar costs of the implementation of the USA and MFR with the expected dollar savings 17 associated with the benefits of having such a system. Therefore, the assessment must be 18 done on a more qualitative basis. 19

The Board is persuaded by the evidence that there are benefits to be gained through the 20 implementation of the USA and MFR. Moreover, the Board is reassured that the interveners 21 also consider there to be benefits to be achieved from the implementation of the USA and 22 MFR as they would not otherwise have been willing to participate in the USA-MFR 23 Committee or support this initiative in this proceeding. The Board also notes that although 24 the implementation costs at this stage are uncertain, customer representatives are willing to 25 pay the costs provided the implementation is done on a prudent basis.” 26

27 The FEU believe that there is more value to the adoption of a common USoA in Alberta than in BC. 28 This is because: 29

1. The order in Alberta was related to the adoption of a full USoA. BC utilities are already 30 compliant with all parts of the USoA except for O&M reporting, where three out of four of the 31 major utilities have made modifications to address the issues with the O&M section of the 32 USoA. This is because the O&M section of the BCUC USoA does not accommodate 33 current management practices (for example changes in Information Technology) or 34 accounting policies. Moreover, as the FEU have explained, the O&M section of the BCUC 35 USoA does not provide any more meaningful or understandable information than the FEU’s 36





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New Code of Accounts. The FEU are already able to compare financial information from 1 year to year and the BCUC USoA offers no improvements; the BCUC USoA will not improve 2 the ability to compare financial information from year to year, which was one of the main 3 benefits in the EUB’s case. 4

2. There are many more utilities in Alberta than in BC. The EUB order was applicable to all 5 electric transmission and distribution utilities that fall under the EUB jurisdiction. This 6 includes not only the five electric utilities listed in response to BCUC IR 2.308.3 but also any 7 smaller utilities such as the Cities of Lethbridge and Red Deer, and TransAlta unless they 8 sought an exemption. These five major electric utilities contrast to only two major electric 9 utilities in BC. Each utility manages its O&M differently in BC, and the adoption of the BCUC 10 USoA is unlikely to improve the ability to compare financial information across utilities, which 11 was one of the main benefits in the EUB’s case. 12

3. In Alberta, there has been a history of the Board, and now the Alberta Utilities Commission, 13 implementing standardized reporting requirements and processes across all the utilities it 14 regulates. For example, it was the Board in Alberta that led the IFRS project. In BC it was 15 the utilities that led the IFRS project. In addition, Alberta utilities follow a common code of 16 conduct. Since the Board, and now the Alberta Utilities Commission, has required 17 consistency of accounting and other policies by the utilities, a common method of reporting 18 would be more consistent across utilities in Alberta than it would in BC and would therefore 19 add more value. 20

4. The EUB also noted that customer representatives were willing to pay the costs in Alberta. 21 Given that no customer groups have taken issue with the FEU’s current reporting, the FEU 22 do not believe this has been established to be true in BC. 23

24 Overall, the FEU believe that there are differences between the regulatory environments in Alberta 25 and BC that makes the value proposition in BC significantly less. 26

27 28

29 308.5.3 How did the Alberta Energy and Utilities Board treat the implementation 30

and the annual operating costs related to the adoption the USoA by 31 affected utilities in Alberta? 32

33 Response: 34

The FEU understand these costs were recovered from ratepayers. 35





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1 2

3 4 In Exhibit A2-13, section 4, page 7, FEI states, “Since the New Code of Accounts is based 5 on how Terasen Utilities are currently internally planning, recording and reporting their costs, 6 …” 7

In Exhibit A2-13, section 4.1, page 9, FEI states, “…since the adoption of the New Code of 8 Accounts in 2006. The New Code of Accounts provides 50 different accounts in the Activity 9 View and a further 12 accounts in the Resource View…” 10

308.6 Are the statements in section 4, page 7, and section 4.1, page 9, still current? In 11 other words, does the information in the statements still apply in the present 12 environment given that the name has changed from Terasen Utilities to FEU? 13

14 Response: 15

The change of name does not impact the reporting. However, over the years since the New Code 16 of Accounts was developed, other changes in the business and reporting structure have resulted in 17 changes to the Activity View of the New Code of Accounts. 18

The full text of the quoted excerpt from 2007 was “…Since the New Code of Accounts is based on 19 how Terasen Utilities are currently internally planning, recording and reporting their costs, the New 20 Code of Accounts may in the future need to be adapted to meet changes in operational 21 activities. An example of potential future changes could be the reporting, coding and recording of 22 CustomerWorks charges or Shared Services Agreement charges...” [emphasis added] 23

Consistent with this statement from 2007, the FEU, with their changes to the New Code of Accounts 24 provided to the Commission staff and implemented in this Application, have specifically addressed 25 the insourcing of the customer service function, among other items. This demonstrates the 26 flexibility of the New Code of Accounts as compared to the BCUC USoA, which has not been 27 substantially updated since 1961. 28

29 30

31 308.7 If the internal planning, recording and reporting of costs processes are still 32

essentially the same, please provide a detailed description (also including 33 graphical illustrations would enhance the value of the information provided) of 34 same. In your detailed description, please include specific illustrative examples 35





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that demonstrate how transactions are processed/recorded, e.g. from the primary 1 input data such as an invoice, and “rolling up” to the highest level of consolidation 2 in an O&M account as per the New Code of Accounts. 3

4 Response: 5

FEI confirms that the internal planning, recording and reporting of costs and processes are 6 essentially the same as referenced in Exhibit A2-13. FEI also adds that both the Resource and 7 Activity view of reporting has been refreshed to reflect the most recent operational changes within 8 the organization. 9

In providing a detailed description of the same, FEI will reference a presentation made to BCUC 10 staff on February 5, 2013 titled ‘BCUC Activity View Reporting’, provided as Attachment 308.7. 11

In the presentation the FEU provide an overview of the New Code of Accounts which provides both 12 an Activity view (the ‘Why’) and Resource view (the ‘What’) of O&M reporting. 13

As demonstrated in the slide titled ‘Hierarchy of Activity View Reporting’, departments across the 14 organization are assigned activities such that the O&M summed for all activities within a department 15 will total to the department O&M (this was a specific undertaking of FEU referenced in Exhibit A2-16 13, Section 5, Implementation Plan to Meet BCUC Objectives, page 13). Activities are then 17 assigned to the various Cost Centers that operate in support of the Activity. The Cost Centre 18 becomes the lowest level of hierarchal reporting within the organization. Cost Centers are assigned 19 to Managers who are then charged with the planning, operational and reporting activities thereon. 20 Within SAP, Activities are assigned Internal Orders for tracking purposes. 21

This contrasts with the Resource view of O&M reporting whereby Resources are assigned to Cost 22 Elements in SAP with the objective of reporting costs by resource or cost type. 23

Within FEI, there exist approximately 275 Cost Centers. Collectively these roll up to 51 Activities in 24 the BCUC Activity View which in turn rolls up to 13 Departments. From a resource aspect there are 25 approximately 350 Cost Elements or expense types that roll up to 12 Resources in the BCUC 26 Resource View. 27

Invoices are coded to a Cost Centre to assign operational responsibility, they are coded to an 28 Internal Order to enable Activity View reporting, and are coded to a Cost Element to enable 29 Resource View reporting. 30

For BCUC reporting, the Activity view reporting is done at an Activity level while the Resource view 31 reporting is done at a company-wide level. 32

For internal management purposes however, this hierarchal view of reporting further enables 33 management to provide Activity reporting at a Cost Center level, and to provide Resource reporting 34





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(including the expanded Cost Element view) at the Department level, Activity level, as well as Cost 1 Center level. 2

FEI is of the view that the New Code of Accounts provides reporting that is more informative and 3 better aligned to the operational management than what the original USoA is capable of providing. 4

5 6

7 308.8 If the internal planning, recording and reporting of costs processes are not 8

essentially the same, please provide a full description of the changed processes in 9 the same manner as requested in the immediately preceding question, and in 10 addition, highlight the changes and provide explanations why the changes were 11 necessary. 12

13 Response: 14

The internal planning, recording and reporting of cost processes are the same. However, there 15 have been amendments to the New Code of Accounts to address changes in FEU’s business, such 16 as the insourcing of the customer service function. Please also refer to the responses to BCUC IRs 17 2.308.6 and 2.308.7. 18

19 20

21 22 In Exhibit A2-13, section 4, p. 6 and 7, FEI states, “The New Code of Accounts would allow 23 reporting for both an activity-based view and a resource-based view and relationship 24 mapping [emphasis added] to the Commission’s Uniform System of Accounts.” 25

In Exhibit A2-13, section 4.2.1, page 10, FEI states, “In Attachment 3 [Comparison of BCUC 26 Uniform System of Accounts to Activity View], the FEU have provided a line by line 27 comparison of the BCUC USoA for O&M Accounts to the New Code of Accounts. Based on 28 this analysis, the FEU are able to conclude that there are no significant differences between 29 the two in terms of the information provided.” 30

308.9 Please describe in detail the relationship mapping process referred to above. Your 31 description should provide very specific information about where the relational 32 mapping “linkages” were established (e.g. primary or sub O&M expense accounts 33 at individual cost center level). If an electronic model of the relational mapping 34 process is available, please provide it. 35





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1 Response: 2

This response addresses the responses to BCUC IRs 2.308.9 through 2.308.20. The questions 3 posed in this series of IRs all relate to the “relationship mapping” referred to in the FEU’s Report 4 and the time and cost required to implement the BCUC USoA view of O&M. 5

FEU has concluded from its review of this series of questions that the Commission has 6 misunderstood what was intended by the use of the term “relationship mapping”. The referenced 7 relationship mapping was provided by the FEU as Attachment 3 to its Report. The relationship 8 mapping is nothing more than the creation of this excel file; it appears the Commission has 9 misinterpreted the extent of mapping and concluded it is a relationship mapping that exists within 10 SAP. It is not. 11

As such, there were no incremental costs incurred in developing Attachment 3. FEU estimate that 12 internal staff spent approximately two weeks of time in developing the document. The document 13 can be updated annually with a minimal investment of time. 14

The FEU do not believe that this relationship mapping could be fully implemented in FEU’s SAP 15 system. This is because the USoA attempts to capture both the “what” (the resource) and the “why” 16 (the activity) in one account. FEI’s SAP system is not designed to capture both the what and why in 17 a single transaction. Instead, the resource view provides the what (the type of resource that was 18 used) and the activity view provides the why (the reason the resource undertook the work). The 19 issues with this are further described on a line item basis in the column “Differences noted from 20 FEU compared to BCUC”. 21

Attachment 3 was prepared expressly to demonstrate to the Commission that there would be no 22 more information provided through adopting the BCUC USoA or another USoA than what is being 23 provided today through the Activity View and the Resource View. FEU was able to demonstrate 24 that this is the case, and continues to believe there is no value to be gained from implementing a 25 different USoA than what is currently in place. 26

If the Commission directed the FEU to follow the BCUC USoA for O&M despite any evidence of the 27 benefits that would be obtained, then the FEU believe the Commission has a responsibility to first 28 review and revise the USoA from 1961 to bring it more up to date and in line with the way utilities 29 currently manage their business so that at least some value would be provided to ratepayers. FEU 30 also expects that this exercise would result in a USoA that is more consistent with FEU’s New Code 31 of Accounts than with the current BCUC USoA. Once this task was completed, the FEU would 32 pursue one of two options: 33

1. Implement an excel-based manual process to allocate costs to the BCUC USoA accounts 34 on an annual basis as is done by FBC. This could be accomplished utilizing internal 35 resources. FEU believes it could undertake to complete this process within three months of 36





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receiving a directive and a revised USoA from the Commission, depending on resource 1 availability. 2

2. Implement a combination of SAP mapping and manual procedures to allocate costs to the 3 BCUC USoA for BCUC Annual Report purposes as is done by BC Hydro. The work 4 undertaken in SAP would involve reviewing all O&M cost centres and associated settlement 5 rules, interviewing cost centre owners to provide allocation percentages for work that is 6 undertaken, reviewing each SAP O&M report to determine if it would be impacted by the 7 changes, implementing the changes and converting data, providing training, and 8 undertaking an annual review and updating of the rules. Even with this work, FEI believes 9 some customizations of the USoA will be required, similar to what was experienced by BC 10 Hydro. FEI estimates this would consume approximately $500 thousand, primarily operating 11 expenses, and take six months from receiving a directive and a revised USoA from the 12 Commission, depending on resource availability. This estimate assumes this task can be 13 accomplished solely by a review and update of the back end accounting processes. 14

15 As is the case with both FBC and BC Hydro, FEU would be unable to include this BCUC USoA view 16 in the body of its RRAs since there would be no drilldown capability or specific management 17 responsibility for the resulting line items. 18

The FEU restate that although the costs of implementing the BCUC USoA for O&M in this manner 19 may not be significant in comparison to the overall revenue requirement, incurring any costs at all 20 without a clear understanding of what benefits would be obtained would not be in ratepayers’ best 21 interests. FEU notes that no interveners representing customer groups have raised a concern with 22 the availability of information or the use of the New Code of Accounts. 23

24 25

26 308.10 What costs (one-time and annual recurring), if any, were/are still associated with 27

development and implementation of the “relationship mapping” process? 28 29

Response: 30


32 33

34





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308.11 Is the “relationship mapping” process referred to above, presently incorporated (i.e. 1 “hard wired”/programmed) in FEU’s SAP system? If not, why not? 2

3 Response: 4


6 7

8 308.12 If the “relationship mapping ” process is/were to be incorporated in FEU’s SAP 9

system would that then allow FEU to generate at any time, automatically or on 10 demand, a view of O&M expenses, which very closely adheres to the requirements 11 of the BCUC USoA? If not, why not? 12

13 Response: 14


16 17

18 308.13 Would FEI agree that the “relationship mapping” and more specifically, the 19

associated “linkages” would need to be made permanent at their inauguration to 20 ensure that consistency and comparability of information for regulatory reporting is 21 maintained over time (e.g. any subsequent changes in FEI’s organizational and/or 22 responsibility reporting structure should not normally cause these “linkages” to be 23 altered). If FEI does not agree, please explain why not? If FEI agrees, please 24 confirm that the associated “linkages” were/will be made permanent at their 25 inauguration. 26

27 Response: 28


30 31

32 308.14 Is Attachment 3 and the line-by-line comparison contained therein the result of the 33

“relationship mapping” process referred to above? Please discuss. 34 35





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Response: 1


3 4

5 308.15 With reference to Exhibit B-1-1, Appendix F6 - O&M Expenses – Activity View, is 6

FEI able to convert this O&M Expenses - Activity View to a BCUC USoA View of 7 O&M expenses, using the “relationship mapping” process illustrated in Attachment 8 3? If yes, please provide it. If not, why not? 9

10 Response: 11


13 14

15 308.16 If FEI is able to convert the O&M Expenses – Activity View in the manner 16

requested in the immediately preceding question, i.e. to a BCUC USoA View, 17 would it then still be possible to “drill down” to granular source data, e.g. invoices, 18 when starting from the rolled-up information in the BCUC USoA View? If not, why 19 not and what would need to be done to enable that “drill down” process? 20

21 Response: 22


24 25

26 308.17 What further refinements, if any, would still have be made to the “relationship 27

mapping” process to bring the comparison shown in Attachment 3 into a total 28 [Emphasis added] alignment with a BCUC USoA O&M expense reporting view. 29 Please discuss. 30

31 Response: 32






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1 2

3 308.18 How long would it take to complete such further refinements? 4 5

Response: 6


8 9

10 308.19 What would be the costs, if any, associated with such further refinements? 11 12

Response: 13


15 16

17 308.20 Please provide the estimated cost and timeline required for FEI to fully convert to 18

the BCUC USoA. 19 20

Response: 21


23





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309.0 Reference: FINANCING, TAXES, ACCOUNTING POLICIES AND DEFERRALS 1

2012-2013 FEU RRA Decision, p. 141; Exhibit B-11, BCUC 1.81.2, 2 1.101.1, 3

1.110.1, 1.127.3, 1, 1.129.1, 1.137.2, 1.138.2 4

BCUC USoA 5

“The Commission Panel believes that the use of the USoA for reporting purposes would 6 require consistent and comparable information at an account level. We also note that if 7 forecasting for a future RRA followed this same system of accounts, it would provide further 8 clarity of forecast to actual results at an account level.” (2012-2013 FEU Decision, p. 141) 9

“Finally, in years prior to 2010, some of the departments may not be strictly comparable due 10 to organizational changes that FEI was not able to restate.” (Exhibit B-11, BCUC 1.81.2) 11

“As such, information going back to 2010 provides for a trending which is more reflective of 12 the current business environment. The 2010/2011 and 2012/2013 expenditures have also 13 been examined in the two most recent RRA proceedings, and appropriate levels of 14 expenditure have been set by the Commission. While the information requested for 2007 to 15 2009 has been provided, this is not useful as a point of comparison.” (Exhibit B-11, BCUC 16 1.110.1) 17

309.1 Given that FEI was unable to provide 5-year comparable information in BCUC 18 1.81.2, 1.101.1, 1.110.1, 1.127.3, 1, 1.129.1, 1.137.2 1.138.2, and other IRs please 19 explain why FEU should not be directed to comply with Directive 63 from the 2012-20 2013 FEU Decision requiring “FEU to fully adopt the USoA.” 21

22 Response: 23

FEI did provide the information in the referenced IRs with the proviso that, in some cases, the 24 information was not comparable. The reasons that it was not comparable included: 25

1. Customer Service department was insourced starting in 2012; 26

2. Accounting policies changed, resulting in items being classified differently between O&M 27 and capital; 28

3. Organizational changes occurred at a lower level of reporting than was currently being 29 captured in the system; and 30

4. The operating environment evolved over the intervening period including changes in energy 31 policies, customer programs, codes and regulations. 32

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Had FEI adopted the USoA for O&M, the information would not have been any more comparable 1 than it currently is. A different method of grouping costs does not change the fact that accounting 2 policies have changed to required capitalization differences, or that data that was previously 3 captured at a higher level cannot be retroactively split to a lower level without considerable 4 estimation which makes the data unreliable, or that there have been changes in the environment 5 that drive costs and make O&M costs from 2007 not comparable to O&M costs from 2014. 6

FEI is concerned that there is a misunderstanding about what the outcome of adopting a different 7 USoA would be, and that there is an expectation it will resolve all comparability problems. This is 8 not the case. 9

In FEI’s view, adopting the USoA provides no incremental value and will tie up the utility’s resources 10 in a project, potentially incur incremental external costs, and require a reconciliation process each 11 year. FEI will not be able to provide accurate responses to questions on the resulting accounts 12 since much of the data would be created through a judgement-based allocation process. Finally, 13 the FEU does not believe that Directive 63 required the “FEU to fully adopt the USoA” as stated 14 above. Instead Directive 63 stated: 15

“The Commission Panel directs the FEU to begin investigating the cost of fully converting to 16 the USoA and to work with Commission staff to develop a plan that will allow the FEU to fully 17 adopt the USoA prior to filing their next RRA with the Commission.” 18

The FEU submitted the Report contained in Exhibit A2-13 in compliance with that Directive and 19 requested that “the Commission find that the FEU’s proposal meets the objectives of the 20 Commission’s Directive or, in the alternative, provide further guidance to the FEU based on the 21 contents of this Report.” 22

The FEU received a letter (Log No. 41494 filed as Exhibit A2-14) from the Commission that stated: 23

“The Commission has reviewed FEU's proposed alternate approach and accepts it for the 24 next Revenue Requirements Application (RRA) only. In the next RRA the Commission will 25 assess whether FEU is required to either comply with Directive 63, continue with the 26 alternate approach for further RRA's, or implement some other approach as the Commission 27 finds appropriate at that time.” 28

Based on the original report and the analysis and discussion provided in response to the BCUC IR 29 2.308 series, the FEU submit that the Commission should determine that it is in customers’ best 30 interests that the FEU continue with its existing approach of the New Code of Accounts. 31

32