The Rate Treatment of the Costs of Acquisition of a Utility Distribution System |

PDF Version: The Rate Treatment of the Costs of Acquisition of a Utility Distribution System

Decision Commented On: AUC Decision 24405-D01-2019, Generic Proceeding to Review Rate Treatment of Distribution System Acquisition Costs Under Performance-Based Regulation, September 6, 2019

From time to time utility distribution systems change hands. In particular, in recent years we have seen investor owned distribution utilities purchasing municipally owned distribution systems and distribution systems owned by rural electrification associations (REAs) and gas co-operatives. The AUC convened this Generic Proceeding through Bulletin 2019-03 of March 12, 2019 to consider the rate treatment of the acquisition costs of a utility within the context of performance based regulation (PBR).

This post begins with brief summaries of PBR and the regulation of distribution systems. It then turns to examine the list of issues identified by the AUC in this proceeding.

Performance Based Regulation

In its Decision 2012-237, Rate Regulation Initiative Distribution Performance-Based Regulation, September 12, 2012, the AUC described PBR as a form of economic regulation that

… begins with rates established through a cost of service proceeding such as a rate base rate-of-return proceeding. Those rates are then adjusted in subsequent years by a rate of inflation (I) relevant to the prices of inputs the companies use less an offset (X) to reflect the productivity improvements the companies can be expected to achieve during the PBR plan period. Thus, adjusting rates by I-X, rather than in cost of service proceedings, breaks the link between a utility’s own costs and its revenues during the PBR term. In much the same way as prices in competitive industries are established in a competitive market, prices adjusted by I-X reflect industry-wide conditions that would produce industry price changes in a competitive market. Each company’s actual performance under PBR will depend on how its own performance compares to the industry‘s inflation and productivity measures. (at para 16)

Other factors in addition to the I and X factors are also typically included in PBR schemes. For example, there may be a Z factor “to deal with such significant events outside the companies’ control [e.g. a flood or an ice storm] that are specific to the industry and would not be reflected through the inflation factor (I).” A Y factor may be used to flow-through certain specified costs incurred by a utility such as AUC-approved charges of the Alberta Electric System Operator (AESO); a K factor is designed to provide for new capital investments; and a Q factor might provide for an adjustment based on changes in the number of customers served by a utility.

The AUC has applied PBR to all natural gas and electric distribution utilities under its jurisdiction since 2013. The Commission’s approach to PBR is based on five principles:

Principle 1. A PBR plan should, to the greatest extent possible, create the same efficiency incentives as those experienced in a competitive market while maintaining service quality.

Principle 2. A PBR plan must provide the company with a reasonable opportunity to recover its prudently incurred costs including a fair rate of return.

Principle 3. A PBR plan should be easy to understand, implement and administer and should reduce the regulatory burden over time.

Principle 4. A PBR plan should recognize the unique circumstances of each regulated company that are relevant to a PBR design.

Principle 5. Customers and the regulated companies should share the benefits of a PBR plan.

(AUC Decision 2012-237 at para 28)

PBR plans need to be re-based from time to time. The first PBR plans (with the exception of ENMAX) ran from 2013 – 2017. The current plans run from 2018 – 2022. There was some criticism by consumer advocates and others that the K factor or capital tracker scheme of the first generation PBRs was too generous to the utilities and provided insufficient incentive to manage capital costs. The Commission heard this criticism and accordingly developed a new approach to the treatment of capital builds for the second generation PBR plans: see AUC Decision 20414-D01-2016 (Errata), 2018-2022 Performance-Based Regulation Plans for Alberta Electric and Gas Distribution Utilities, February 6, 2017. The Commission summarized its new approach in the decision that is the subject of this comment at paras 52-53 as follows:

52. The 2018-2022 PBR plan differs from the 2013-2017 PBR plan in several ways, including the treatment of capital. Although the Commission accepted the continued requirement for a capital funding mechanism that reflects the unique circumstances of individual distribution utilities that may be in different phases of their capital programs and business cycles, it expressly determined that the vast majority of capital should be subject to the superior incentive properties of PBR. Accordingly, under the 2018-2022 PBR framework, the Commission divided capital into two categories: Type 1 capital and Type 2 capital. Type 1 capital was narrowly defined and this funding was to be managed using a modified version of the capital tracker approach from the 2013-2017 PBR plan. In circumscribing Type 1 capital, the Commission ensured that most of a distribution utility’s capital funding is managed under the Type 2 capital funding mechanism; i.e., Type 2 capital would be funded from base rates, which would grow at a rate of I-X and any incremental funding for Type 2 capital, if necessary, would be funded using the K-bar mechanism.

53. The K-bar mechanism (described by the Commission in Section 6.4.3 of Decision 20414- D01-2016 (Errata) and clarified in Section 5 of Decision 22394-D01-201859) is a formulaic mechanism designed to provide incremental funding based, in part, on a historical average of actual net capital additions over a specified period during the preceding PBR term (determined to be 2013-2016 for all of the distribution utilities except ENMAX, and 2015-2016 for ENMAX). As stated by the Commission in Decision 22394-D01-2018, the Commission’s intent in using this type of incremental funding mechanism for Type 2 capital was to “ensure that virtually all of the incremental funding available to the companies was subjected to the spending discipline that arises from PBR incentives.”

The Regulation of Distribution Systems

Electric distribution systems are established by the Hydro and Electric Energy Act, RSA 2000, c H-16 (HEEA). Section 25(1) provides that

… no person shall construct or operate an electric distribution system or alter the service area of an electric distribution system without the approval of the Commission, which approval shall include the designation by the Commission of the person’s service area.

Under section 30, no person who operates an electric distribution system “shall discontinue the operation of the holder’s or person’s electric distribution system or discontinue the distribution of electric energy in any area, except in a case of emergency or for repairs and maintenance, unless the holder or person has obtained authority in writing from the Commission to do so.” The HEEA also contains provisions for establishing the boundaries of service areas (section 28) as well as provisions for altering those boundaries (section 29). Section 29(2) provides that “When a local authority owns and operates an electric distribution system within its municipality, the Commission shall not reduce its service area without its consent.”

Section 32 of the HEEA expressly addresses electric distribution systems operated by an REA. It contemplates that where an REA has its service area reduced under section 29 or where an REA is authorized to discontinue operation of the electric distribution system, the AUC may “by order transfer to another person the service area or part of it served by the rural electrification association.” Such an order may “for the purpose of ensuring the continued distribution of electric energy in the service area or part of it that was served by the rural electrification association” provide for:

(i) the transfer of any facilities associated with the electric distribution system from the rural electrification association to another party, and

(ii) the operation of the electric distribution system or part of it by any party that the Commission directs…

The order may also provide for the payment of compensation.

Section 102 of the Electric Utilities Act, SA 2003, c E-5.1 (EUA) requires each owner of an electric distribution system to “prepare a distribution tariff for the purpose of recovering the prudent costs of providing electric distribution service by means of the owner’s electric distribution system.” The owner must seek the approval of the Commission for that tariff unless the owner is a municipality or subsidiary of a municipality or an REA. In these two cases the owner must apply for approval of the tariff to, respectively, the council of a municipality or the board of directors of the REA.

It follows from this that the AUC has no prospective rate setting jurisdiction for electric distribution systems that are owned by a municipality or an REA. The AUC does however have a limited “complaint” jurisdiction in these two cases. Section 43 of the Municipal Government Act, RSA 2000, c M-26 (MGA) provides that:

43(1) A person who uses, receives or pays for a municipal utility service may appeal a service charge, rate or toll made in respect of it to the Alberta Utilities Commission, but may not challenge the public utility rate structure itself.

(2) If the Alberta Utilities Commission is satisfied that the person’s service charge, rate or toll

(a) does not conform to the public utility rate structure established by the municipality,

(b) has been improperly imposed, or

the Commission may order the charge, rate or toll to be wholly or partly varied, adjusted or disallowed.

Under section 45 of the MGA and sections 139 and 140 of the EUA, a municipality may grant a franchise to the owner of an electricity distribution utility to distribute electricity within a municipality with the approval of the AUC. Section 45 of the MGA applies generally to the provision of utility services with the municipality and contemplates that:

45(1) A council may, by agreement, grant a right, exclusive or otherwise, to a person to provide a utility service in all or part of the municipality, for not more than 20 years.

(2) The agreement may grant a right, exclusive or otherwise, to use the municipality’s property, including property under the direction, control and management of the municipality, for the construction, operation and extension of a public utility in the municipality for not more than 20 years.

(3) Before the agreement is made, amended or renewed, the agreement, amendment or renewal must

(a) be advertised, and

(b) be approved by the Alberta Utilities Commission.

Sections 139 and 140 of the EUA are specific to electric distribution systems:

139(1) A right to distribute electricity granted by a municipality

(a) to an owner of an electric distribution system has no effect unless the grant is approved by the Commission;

(b) to a subsidiary of the municipality does not require Commission approval.

(2) The Commission may approve the grant of a right to distribute electricity when, after hearing the interested parties or with the consent of the interested parties, the Commission determines that the grant is necessary and proper for the public convenience and to properly serve the public interest.

140 The Commission shall not approve a grant under section 139 unless

(a) it is a term of the grant that the grant does not prevent the Crown from exercising that right,

(b) the person seeking the grant has satisfied the Commission that the proposed scheme for the distribution of electricity is reasonable and sufficient, having regard to the general circumstances, and

(c) the Commission is satisfied that the grant is to the general benefit of the area directly or indirectly affected by it.

The AUC has approved a template franchise agreement: see AUC Decision 2012-255, Town of Hinton New Franchise Agreement Template and Franchise Agreement with FortisAlberta Inc. The franchise provisions only apply to the distribution function. They do not apply to the retail function since this is a competitive function under the terms of the EUA (see EUA Part 8 and MGA section 45.1).

With this background out of the way we can now turn to consider the issues identified by the AUC in this proceeding.

The Issues

The Commission set down a list of six issues that it would address in the course of the generic proceedings. These issues were as follows:

1. Under the previous PBR framework, amounts paid by a regulated distribution utility for the acquisition of an REA may be treated by way of a Y factor when the acquisition was directed by the Commission. For the purposes of funding under the previous PBR framework, should the purchase of a municipally owned electric or gas distribution system be treated differently than the purchase of an REA?

2. For the purposes of funding under the 2018-2022 PBR plans, should the purchase of a distribution system (such as an REA or municipally-owned electric or gas distribution system) be treated differently than the purchase of an REA under the previous PBR framework and should different types of distribution systems require different rate treatment?

3. In light of the established 2018-2022 PBR plan framework and the five PBR principles, how should the amounts paid by a regulated distribution utility for the acquisition of an electric or gas distribution system from an REA, municipality or gas co-op be treated under that framework? In particular:

(a) Should these costs be considered for funding through a supplemental funding mechanism such as a Z factor or a Y factor?

(b) Alternatively, should the supplemental funding mechanisms such as a Z factor or a Y factor be unavailable to a distribution utility, given the presence of the capital funding mechanism under the 2018-2022 PBR plan?

(c) What is the relevance and effect of the Q factor in providing additional funding to PBR distribution utilities in instances where a distribution system is purchased?

4. With respect to the purchase of an REA, a specific Commission direction to the utility to acquire the subject assets is required to allow for Y factor treatment of the acquisition costs. What should the treatment be for the acquisition costs absent a Commission direction?

5. Consistent with the Commission’s prior correspondence in Proceeding 23961, Fortis and other interested parties may make submissions in this proceeding with respect to “the rate treatment of the acquisition costs of the Crowsnest Pass electric distribution system in light of the service area and transfer approvals received to date.”

6. Should a streamlined application process be developed to ensure that future transfers of gas or electric distribution system assets from co-operatives or municipalities receive regulatory approval in a timely manner? If yes, please detail the specifics of any proposed process. (at para 17; footnotes omitted)

While the generic proceeding had the potential to deal with both gas utilities as well as electrical utilities, very little evidence or argument was presented in relation to gas utilities. This led the Commission to conclude that:

While the Commission is of the view that, in general, its findings regarding the intent behind the 2018-2022 PBR plan apply to both electric and gas distribution utilities, it also recognizes that there are legislative and potentially other differences between gas and electric distribution utilities. However, the nature and extent of these differences and whether they might justify differential rate treatment for gas distribution system acquisitions was not adequately explored in this proceeding. Accordingly, the Commission finds that insufficient evidence was provided on the record of this proceeding to enable it to consider adequately the rate treatment of gas distribution system acquisitions and whether a distinction from electrical distribution system acquisitions is warranted. (at para 78)

The Commission did not organize its decision in quite the same manner as the list of issues identified above. Accordingly, the balance of this post is organized around the following headings: (1) Is there any basis for treating acquisition from a municipality differently from a purchase from an REA? (2) How did the AUC treat acquisition costs under the 2013-2017 PBR plans? (3) How should the AUC treat acquisition costs under the 2018- 2022 PBR Plans?

Is there any basis for treating acquisition from a municipality differently from a purchase from an REA?

It will be observed that the first two issues invited discussion as to whether any distinction should be made with respect to the rate treatment of an acquisition based upon whether the vendor of the electric distribution system was a municipality or an REA and specifically with respect to the question of whether the purchase should trigger “Y” factor treatment. The Commission concluded that “there is no sufficient legislative or principled basis to distinguish between the acquisition of a distribution system owned by an REA and one owned by a municipality, by an electric distribution utility, for the purposes of funding under the 2013- 2017 or 2018-2022 PBR plans.” (at para 32)

How did the AUC treat acquisition costs under the 2013-2017 PBR plans?

The Commission recognized that it had in fact authorized “Y” factor treatment for acquisition costs in certain cases on the basis that it was possible to characterize these costs in some cases as being incurred at the direction of the Commission. The Commission put it this way in AUC Decision, 2013-296, ATCO Electric Ltd. Rate Regulation Initiative Performance-Based Regulation Z Factor Adjustment Application August 9, 2013:

… to qualify under the Y factor exemption for Commission directed costs, an electric distribution company under PBR must be able to demonstrate that the REA acquisition occurred as the result of a specific Commission direction. Such a specific Commission direction could occur if the REA applied to the Commission for permission to cease to operate in its service area under Section 29(1) of the Hydro and Electric Energy Act or applied to discontinue operations of its electric distribution system under Section 30(1) of the Hydro and Electric Energy Act. Should the application under either Section 29 or Section 30 be granted, the Commission may, by order under Section 32(2)(a), provide for the transfer of operation of the REA electric distribution system and related assets to the electric distribution company, and for the payment of compensation. The Commission may also determine the amount of the compensation payable pursuant to Section 32(2)(b) if the parties are unable to agree. The Commission considers that a Commission order directing the transfer of facilities to an electric distribution company, the operation of the facilities by the distribution company and the payment of compensation to the REA may satisfy the requirements for a Commission directed Y factor adjustment as contemplated in paragraph 632 of Decision 2012-237. (at para 99)

The Commission acknowledged that pursuant to this decision it had granted “Y” factor treatment of acquisition costs to Fortis in relation to its acquisition of the Kingman and VNM REAs: AUC Decision 20818-D01-2015, FortisAlberta Inc., 2016 Annual Performance-Based Regulation Rate Adjustment Filing December 17, 2015 at paras 49-52:

49. Accordingly, in order to qualify for a Y factor adjustment to its PBR rates, Fortis must be able to demonstrate that the Kingsman REA and the VNM REA acquisitions occurred as the result of the specific Commission directions described above. It has done so. The Commission issued a direction under Section 32 of the Hydro and Electric Energy Act after having granted the Kingman REA’s and VNM REA’s applications to cease to operate in its service area under Section 29(1). Therefore, the Commission grants Fortis’ application to treat the Kingman REA and VNM REA acquisitions as a Y factor adjustment to its PBR rates.

50. While the Commission may, at some future time, direct that affected utilities should seek approval of Y factor eligibility in REA asset transfer proceedings, it has not yet done so, and declines to do so for the purposes of this decision. Consequently, the fact that Fortis did not elect to seek approval for Y factor treatment of these costs in the original transfer applications is immaterial to its current request. Fortis may recover the applied-for REA costs through a Y factor adjustment by virtue of the fact that they were incurred as the result of Commission directions.

51. Having approved Y factor treatment of the REA acquisitions, the rate implications of these treatments must now be considered.

52. Regarding the quantum of recoverable acquisition costs, the Commission notes that the purchase prices paid by Fortis for each of the Kingman and VNM REAs were previously considered by it and found to be prudent. The Commission also approved the continued use of the replacement costs new less depreciation (RCN-D) valuation methodology for REA purchases in the same decisions that determined the prudence of the purchase prices. The Commission finds that, despite the urging of CARG and the REA IG, these issues are not subject to reconsideration within the context of Fortis’ annual rate adjustment proceeding. (References omitted)

This discussion led the Commission to consider how it should treat Fortis’ acquisition of the distribution assets of the Municipality of Crow’s Nest. In this case the AUC had approved that acquisition (see AUC Decision 21785-D01-2018, FortisAlberta Inc. Sale and Transfer of the Municipality of Crowsnest Pass Electric Distribution Assets Municipality of Crowsnest Pass; and Permission to Cease and Discontinue Operations June 5, 2018) and was considering Fortis’ application for the rate treatment of this acquisition when the Commission decided to suspend that proceeding and commence this generic process. Opinion was divided in the current proceeding. Some took the view that the acquisition resulted from a voluntary agreement between the parties and was in no sense directed by the Commission. Furthermore, section 32 of the HEEA was inapplicable since the case did not involve an REA. In the view of these parties therefore the acquisition was not eligible for “Y” factor treatment. The Commission however took the view that Fortis had proceeded with this acquisition anticipating that it would be eligible for Y factor treatment, leading the Commission to rule that:

… for reasons of fairness and consistent with the Commission’s treatment of REA acquisition costs during the 2013-2017 PBR term, the Commission accepts the approvals issued in Proceeding 21785 as a Commission direction to Fortis to acquire the Crowsnest Pass system and the prudent costs paid by Fortis for the acquisition of that system (to be ascertained in Proceeding 23961) will be eligible for a Y factor adjustment. (at para 50)

The same reasoning led the AUC also to grandparent another ongoing acquisition by Fortis that had been out on hold during these proceedings, that being Fortis’ proposed acquisition of the distribution assets of the Town of Fort Macleod (at paras 79-84).

But how should these issues be treated on a going forward basis?

How should the AUC treat acquisition costs under the 2018- 2022 PBR Plans?

In introducing this discussion, the AUC noted that while the Commission had changed its approach to capital investments it had not changed its overall approach to the “Y” factor. Nevertheless, based on further reflection in this proceeding the Commission concluded that its overall approach to capital should prevail and that “the Commission’s overall goal and intention to extend the superior incentive properties of PBR during the 2018-2022 PBR term to the vast majority of capital spending, in a manner consistent with PBR principles.” (at para 63) Accordingly:

… the Commission no longer considers that any orders or approvals issued pursuant to the Hydro and Electric Energy Act in relation to a distribution utility voluntarily acquiring a REA or municipally owned distribution system or assets, constitute or provide the basis for a Commission direction. The Commission will also not, absent compelling reasons, direct a freely negotiated acquisition between a distribution utility and an REA or a municipality. This approach is consistent with the Commission’s intent in establishing the parameters for the 2018-2022 PBR term as previously expressed and its expectation that the funding provided using base rates and the K-bar mechanism be used to fund these types of acquisitions by a distribution utility. (at para 63)

The Commission did not completely rule out Y factor treatment in unusual and compelling circumstances:

The Commission remains prepared to consider an application for Y factor treatment where the acquisition of an electric distribution facility is proposed in compelling circumstances,

which might include an acquisition in response to a public emergency, natural disaster or bankruptcy of an electric distribution system and where the continuation of public service necessitated the acquisition. (at para 64)

Given that it would be generally be up to a utility to manage the costs of acquisition through its K-bar mechanism, the Commission considered that this should result in regulatory efficiencies insofar as the Commission would no longer need to approve the prudence of the purchase price (at paras 65-66 and 91-92) – absent assertion of special circumstances.

Conclusion

This decision illustrates several points. First, it provides an example of a Commission initiated generic proceeding to provide guidance on a common set of issues. Second, it shows the Commission continuing to work through the implications of PBR, seeking to maximize the incentive effects of this form of regulation (and minimize the costs of regulation). And finally, it illustrates how the Commission may be prepared to reconsider its approach to specific issues (the Y factor) in the context of broader principles (i.e. the general approach to capital) but taking care to ensure that a change in direction does not negatively impact those who have already entered into transactions anticipating a particular rate treatment based on earlier decisions.

This post may be cited as: Nigel Bankes, “The Rate Treatment of the Costs of Acquisition of a Utility Distribution System” (October 2, 2019), online: ABlawg, http://ablawg.ca/wp-content/uploads/2019/10/Blog_NB_AUC24405.pdf

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