Community Generation Projects in Alberta

By: Nigel Bankes

PDF Version: Community Generation Projects in Alberta

Regulation and Decisions Commented On: Small Scale Generation Regulation, Alta Reg 194/2018 and five decisions of the Alberta Utilities Commission (AUC): (1) AUC Decision 24857-D01-2020, Three Nations Energy GP Inc., Fort Chipewyan Solar Generation Facility (Phase 2),  January 15, 2020; (2) AUC Decision 25236-D01-2020, Peavine Metis Settlement, 4.97-Megawatt Community Solar Power Plant, May 4, 2020; (3) AUC Decision 25459-D01-2020, Innisfail Solar Corporation, Innisfail Solar Project Time Extension and Community Generation Designation, May 21, 2020; (4) AUC Decision 24845-D04-2020, 2113260 Alberta Ltd., Community Generation Designation for Oyen Community Solar Project, June 17, 2020; and (5) AUC Decision 25471-D01-2020, 2181731 Alberta Ltd., Vulcan County Community Solar Project, June 25, 2020.

While the Kenney government declined to commit to new rounds of procurements to meet the target of 30% renewables by 2030 established by the Renewable Electricity Act, SA 2016, c R-16.5 (surprisingly, still in force), it has continued with a renewables incentive program provided for under the Small Scale Generation Regulation, Alta Reg 194/2018 (SSGR), including the concept of community generation projects designed to foster community sponsored renewables projects. This post examines the terms of that regulation as well as practice to date under the regulation.

The SSGR applies to three categories of small scale generation projects: (1) small scale projects (generally), (2) small scale community generation projects, and (3) small scale community generation projects that are located within an isolated community. The second and third categories are sub-sets of the first. None of these projects require any degree of self-supply in order to qualify as eligible projects.

Small Scale Generation Projects (Generally)

A generation project may qualify as a small scale generation project if it exclusively uses “renewable or alternative energy” and if it has “a total nameplate capacity that will not exceed the electric distribution system hosting capacity at the interconnection point” (SSGR, s 1(g)). (It should be noted that there is a separate regulation for micro-generation: Micro-generation Regulation, Alta Reg 27/2008, which applies to units of less than 5 MW that are principally designed to meet a customer’s own requirements.)

An application to qualify as an eligible generating unit under the SSGR is first made by the owner of the unit (s 2) to the relevant distribution facility owner (DFO). The DFO must then either determine that the unit qualifies or issue a notice of dispute, whereupon the matter is to be determined by the AUC whose decision “is final and is not subject to appeal” (SSGR s 2(5)). (Quaere, whether this and other similar provisions in the SSGR are consistent with section 29 of the Alberta Utilities Commission Act, SA 2007, c A-37.2.) Notice in each case is to be given to the Balancing Pool.

Where the DFO determines that a project qualifies as a small scale generating unit, it must then, within a reasonable time, connect the project to the distribution system and install an appropriate meter (s 4(1)). The DFO is also obliged to provide metering services and meter data manager services (s 4(2)).

The proponent of a small scale generation project is responsible for all the costs of connecting the unit as well as the costs incurred by the DFO in providing metering services and meter data manger services. The category of connection costs includes (SSGR, s 5(1)(a)):

(i) the cost of purchase and installation of the meter that may be required,
(ii) the costs of any electric energy transfer facilities that may be required in order to effect the connection, and
(iii) any other costs incurred by the distribution owner that may be required to enable the small scale generating unit

(A) to supply electric energy to the interconnected electric system, or
(B) within an isolated community.

The principal advantages that accrue to an operator of a small generation project that is not a community generation project relate to the terms of its participation in the power market. Section 6 of the SSGR provides that the unit will be deemed to have a standing offer of zero dollars “as if it were offered to the power pool” (emphasis added). Furthermore, unless the operator advises otherwise, section 7 requires the Balancing Pool (BP) to act as the electricity market participant on behalf of the operator in dealings with the ISO (Independent System Operator or Alberta Electric System Operator (AESO)), including financial settlement matters. This will reduce the administrative burden that would otherwise accrue to the operator. The BP is responsible for compensating the operator based on the hourly pool price, and the ISO must in turn compensate the BP (SSGR s 7(3) & (4)). These costs that would otherwise be borne by the project operator will be socialized across ISO rate payers.

Small Scale Community Generation Projects

A community generation project is a subset of the category of small scale generation projects. A small scale project qualifies as a community generating unit if it is “the subject of a community benefits agreement or a community benefits statement” (SSGR s 1(d)) (emphasis added) and has been accepted as such by the AUC (SSGR, s 3). A community benefits agreement is (SSGR s 1(b)):

… a legally binding contract in writing that

• • • is between a small scale power producer and a community group,
    • is in respect of a small scale generating unit, and
    • confers social, environmental or economic benefits to the community group.

A community benefits statement is (SSGR s 1(c)):

… a statement in writing that

• • • is made by a small scale power producer that is a community group,
    • is in respect of a small scale generating unit that is wholly owned by the community group, and
    • sets out the social, environmental or economic benefits that will be received by the community group … (emphasis added)

There are thus two modes by which a “community group” can participate in a community generation project. It can do so as the operator of a small scale generating unit provided that the unit is wholly owned by that community group. Or, it can participate more passively if approached by an operator that is prepared to execute a community benefits agreement. The Regulation defines “Community Group” broadly to mean: a cooperative, an education board, a board of a post-secondary institution, an Indian band, a Métis settlement, a municipal authority, a society, a religious institution, an irrigation district, an agricultural society, a condominium corporation, a corporation that is a registered charity, and a rural utility association (s 1(e)).

The incremental advantage to the proponent of qualifying a small-scale project as a community generation project is that the DFO must install and purchase the meter installed at the interconnection point between the generator and the distribution system (s 5(2)). The AESO or ISO is obliged to compensate the DFO for the AUC approved amount of the meter and recover that through an AUC-approved ISO tariff or fee. The operator remains responsible for all the other costs that must be assumed by the operator of ordinary small scale project as summarized above (s 5).

Small Community Generation Projects Located in an “Isolated Community”

To qualify under this head, a small scale project must be a community generation project located in an isolated community. An isolated community (see Isolated Generating Units and Customer Choice Regulation, AR 165/2003) is a community that is not connected to the Alberta integrated system (the grid). Such communities are principally served by diesel generation or in some cases by natural gas generation. The town of Jasper was an isolated community until recently, with a fuel mix that included natural gas and hydro, but in May 2019 it connected to the grid (see AUC Decision 22125-D01-2018, Alberta Electric System Operator, Needs Identification Document Application, AltaLink Management Ltd., Facility Applications, ATCO Electric Ltd., Facility Applications, Jasper Interconnection Project, May 4, 2018).

Given the potential for realizing both greenhouse gas emissions reductions as well as reductions in local pollution loads and the cost of diesel supply, the installation of renewable generation in off-grid communities offers significant benefits not only to those communities but to the system as a whole to the extent that the ISO customer base cross subsidizes energy costs in isolated communities. See generally, AANDC, Off-Grid Report (2011).

In the case of an isolated community project the SSGR obliges the DFO to cover not only the meter costs but also the cost of “system reliability upgrades that may be required to supply electric energy from the community generating unit to the distribution system” (s 3(3)).

Practice to Date with Respect to Community Generation Projects

One project, the Fort Chipewyan project, provides power within an isolated community. The table summarizes key elements of the projects including project size and AUC approved estimated metering costs:

Meter Costs and System Reliability Upgrades

When qualifying a project as a community generating unit, the AUC typically approves an estimate of the metering costs provided by the DFO (or the applicant) subject to a condition that requires the DFO to confirm the actual costs. The cost of system reliability upgrades (also the DFO’s responsibility in the case of a project in an isolated community) did not receive the same, or any, scrutiny in the Fort Chipewyan project (at paras 16 and 27). The decision in the Peavine project records a commitment by ATCO as the DFO that it will cover system reliability upgrades (at para 15) but this should have required some explanation since there is no suggestion in the decision that the Peavine project is within an isolated community. If it is not within an isolated community, the default rule is that the proponent is responsible for “the costs of any electric energy transfer facilities that may be required in order to effect the connection, and .. any other costs incurred by the distribution owner that may be required to enable the small scale generating unit to supply electric energy … to the interconnected electric system (SSGR s 5(1)(iii) & (iv) as quoted above.

Community Benefit Agreements or Statements

Most community benefits agreements (CBAs) have been negotiated with municipalities. The Peavine project appears to be an example of a project that is wholly owned by the Metis Settlement. Accordingly, the filed material includes a statement of the economic, environmental and social benefits expected to be realized by the project instead of an executed CBA. (Note that the link to this and other materials in this section require you to create an account (free) with the AUC.)

The proponent of the Fort Chipewyan project is Three Nations Energy, which is owned by the Athabasca Chipewyan First Nation, the Mikisew Cree First Nation, and Fort Chipewyan Metis Local 125 with funding from both the federal and provincial governments. Given this structure, one might have expected that the project would also be supported simply by a community benefits statement, but in this case the proponent filed a CBA between itself and its owners (i.e Athabasca Chipewyan First Nation, the Mikisew Cree First Nation, and Fort Chipewyan Metis Local 125).

The AUC’s review of CBAs and community benefit statements is surprisingly perfunctory. For example, in the case of the Peavine Project, the AUC suggests that it qualified the project as a community generating unit on the basis of a “signed community benefits agreement” (at para 26). That is not, in fact, the case (as the AUC seems to have acknowledged earlier in its decision at para 11) since the project, as noted above, came forward as a community-owned initiative and all that was filed in support (Exhibit 5) was a benefits statement signed by the administrator of the Settlement and two Settlement Council Resolutions. In such a case, the AUC ought to have focused on the wholly owned nature of the venture. The AUC’s decision does not expressly engage with that aspect of the project, despite the fact that the filed statement records that the actual economic benefits to be realized by the community will depend on the “equity structure of the project.” This suggests that the Settlement was still exploring different options and that if the project is not in fact wholly owned by the community, there would need to be an executed CBA, not just a benefits statement.

The review seems to have been equally perfunctory in the case of the Innisfail Solar Project. The Commission refers (at para 14) to a signed community benefit fund agreement as sufficing to qualify the project as a community generating unit yet, the referenced document is styled as a memorandum of understanding (MOU) and the substantive provisions are expressly stated not to constitute a binding agreement. In short, it is hard to see how the Commission could conclude in that case that the MOU amounted to a “legally binding contract in writing” as required by the SSGR.

In the other three cases the applications were supported by more formal executed agreements. In the case of the Chipewyan CBA referenced above, the principal economic benefits are said to arise by virtue of “profits generated by the Project, as determined by the Three Nations Energy Limited Partnership Agreement.”

The CBAs for each of the Vulcan and Oyen Projects follow a similar format, with community benefit payments to be calculated by reference to a formula. Unfortunately for those seeking guidance as to the typical terms of such arrangements, the elements of the formula are redacted in the two agreements as filed with the AUC. The Oyen agreement, however, does reveal that under no circumstances shall the community benefit payment be less than $50,000 annually. The similar clause was redacted in the Vulcan agreement, leading the AUC to inquire as to whether the value was greater than zero. On being assured that it was, the AUC felt able to conclude that the existence of the agreement allowed it to qualify the project as a community generating unit (at para 27). Both agreements contemplate that the community must apply for any available capacity funding under the Government of Alberta’s Community Generation Program (for details, see here) and must share at least some of any such monies received with the project. The degree to which the community shares such monies is one of the elements affecting the calculation of the community benefit payment.

The AUC does not make any independent inquiry as to the substantive benefits that may accrue to a community under the terms of a CBA. This is a reasonable approach, given the purely formal definition of a CBA in the SSGR. However, at a minimum, the AUC must satisfy itself that there is a binding contract that will confer at least some social, environmental, or economic benefit to the community group. By the same token, if the project seeks to qualify as a wholly community-owned project the AUC must, at a minimum, satisfy itself that the project is indeed wholly owned by the community. Absent such proof, the project can only qualify if supported by a legally binding community benefit agreement.

While the limited scope of the AUC’s review is fully consistent with the Regulation, it may well be appropriate to seek additional transparency with respect to the terms of CBAs and community benefit support statements, either by way of a change in AUC practice or, if necessary, by an amendment to the Regulation. This would enhance the accountability of the different “community groups” to their constituents and perhaps help establish benchmarks for what constitutes a reasonable sharing of benefits in return for community endorsement of the project. While confidentiality may benefit project proponents, it is not clear how it benefits sponsoring community groups or community groups generally seeking to explore the opportunities associated with community generation projects.

Conclusions

The demise of the renewable energy program (REP) put in place by the Notley government pretty much guarantees that Alberta will not reach its renewable target of 30% by 2030. Indeed, the AESO’s current projection (February 2020) is for a significant reduction in new renewables projects by 2030 (2625 MW vs 5850 MW). It is therefore important to note the continuation of the Small Scale Renewables Regulation as a scheme which offers some incentive for small scale renewable and alternative energy projects. Scale eligibility is determined by the ability to connect to the relevant DFO’s system. This will vary depending upon the distribution system, but in some cases the projects will be utility scale projects. Qualifying projects to date range between 2 MW and 22 MW. The principal incentive for such schemes is the ability of the project proponent to transfer market participant responsibilities to the Balancing Pool. Further incentives area available to a community based project, especially a project within an isolated community. It is an open question whether such incentives should be more generous especially in the context of isolated communities, given the co-benefits of such projects. Other jurisdictions such as Yukon have experimented with an avoided cost formula for incenting renewable projects for off-grid communities, and a similar scheme (or a scheme that provides proponents with the better of pool price or that of default generation) might provide additional certainty for developers in Alberta. Perhaps the AUC will shed more light on these issues when it releases its Distribution System Inquiry Report (Proceeding 24116).

Thanks to Michael Wenig and Anna White for comments on an earlier draft of this post.

This post may be cited as: Nigel Bankes, “Community Generation Projects in Alberta” (June 30, 2020), online: ABlawg, http://ablawg.ca/wp-content/uploads/2020/06/Blog_NB_CommunityGenerationProjects.pdf

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