On November 10, 2016, the Alberta Electric System Operator (AESO) released a draft summary of terms for its Renewable Electricity Support Agreement (RESA) for review and comment. The comment period runs until December 9, 2016.
As noted in our November 2016 Blakes Bulletin: Details of Alberta’s Renewable Electricity Program: Program to Add 5,000 Megawatts of Capacity by 2030, the Alberta government is moving forward with the implementation of a Renewable Electricity Program (REP), the purpose of which is to encourage the development of 5,000 megawatts of renewable electricity generation capacity in Alberta between now and 2030.
The REP provides that successful bidders with eligible projects (known as Generators) will each enter into a RESA with AESO consisting of two periods — a development and construction period followed by a 20-year support period.
This bulletin identifies key issues for developers and lenders under the draft RESA terms as presented, with a particular focus on how the RESA terms differ from those in other key Canadian markets.
1. Pre-Construction Requirements
Under the RESA, a Generator will be deemed to have commenced construction only once it has satisfied the specific requirements set forth therein. This has important ramifications given the RESA’s parallel requirement that construction commence by a certain date and the rights given to the AESO to terminate the RESA (and draw upon the Generator’s performance security as liquidated damages) if construction is not in fact commenced by a longstop date (anticipated to be December 2019 for the first procurement, subject to extension for Force Majeure (as defined in the RESA) or certain changes in law). Commencement of construction of a facility will be deemed to have been achieved at the point when (as subsequently confirmed by the AESO in writing) the Generator has:
a. Obtained key Alberta Utilities Commission (AUC) and other environmental, assessments, permits, licences and approvals
b. Delivered a statutory declaration to the AESO confirming the Generator has secured financing sufficient to complete development, construction and commissioning of the facility, procured or entered into arrangements for long-lead equipment and materials that are necessary for the construction of the facility and commenced construction activities at the site of the facility
c. Delivered a copy of its financial model to the AESO
These requirements — particularly those regarding equipment and materials — are stringent and go beyond those in place in other jurisdictions.
2. AESO Security
Notably, the RESA contemplates the AESO taking a security interest over the entire project to protect against default by the Generator. While detailed provisions have not been provided in this regard in the summary of terms provided to date, understanding the genesis and scope of the proposed security to be held by the AESO, its rights to enforce such security in the event of a generator default and its interaction with third-party lender rights will be key to getting Alberta renewable energy projects financed. While some of the language under the heading “Financing and Consequences of Default” used in the term sheet reads in a similar fashion to the analogous provisions of the Ontario Feed-in Tariff (FIT) and Large Renewable Procurement (LRP) contracts, it is unclear exactly what terms the RESA will contain. Similarly, prospective financiers will be keen to see the prescribed form of consent and acknowledgment agreement that will accompany the RESA in order to see that it provides the usual protections that funders would be used to seeing in renewable energy projects in other markets.
Significantly, the RESA does not provide Generators with a right to seek compensatory payments if they are directed by the AESO to dispatch off, irrespective of generating ability. This is a position unlike that of developers currently under LRP contracts in Ontario and similar agreements in British Columbia, where a risk-sharing approach to economic curtailment has been implemented in order to assure the financial viability of projects. Coupled with an outright prohibition on Generators selling ancillary services, this lack of compensation poses a real economic risk to developers of renewable projects where there is no offsetting reduction in fuel costs to offer partial relief during curtailments. It remains to be seen whether concerns over curtailment will affect the viability of certain kinds of projects.
4. Force Majeure
The scope for claims by the Generator for Force Majeure specifically excludes the inability to procure feed stock or fuel for the facility; any appeal of the permits and licences for the project (unless the Generator is ordered to cease construction); and the inability to obtain any required consent or approval of the AESO required pursuant to the terms of the RESA. While relief in the form of additional time during construction is possible under the Force Majeure heading on the grounds of inability to obtain or renew permits (unless caused by the Generator), certain representations required to be made by Generators in the RESA itself may, as a practical matter, limit claims in this regard given the requirement that the event giving rise to the Force Majeure claim be reasonably unforeseeable. Prior to the commercial operation date (COD) for a project, an event of Force Majeure will provide the Generator with additional time for construction and relief from default. However, if an event of Force Majeure occurs post-COD that impacts the project’s ability to produce power, there is no extension of the term of the RESA and accordingly the associated revenues expected to be received from the AESO will be forgone. We do note that either party may terminate in cases of any single event of Generator-invoked Force Majeure that lasts 18 months (or multiple events that last 24 months in aggregate). While the Force Majeure regime proposed for the RESA does not differ significantly from that in the FIT or LRP contracts, all of these considerations will have to be taken into account in developer timelines, economic projections and financing plans.
The RESA will include a change-in-law regime that will allow the Generator to claim additional time or payment adjustments in a variety of circumstances, including due to a change to Independent System Operator rules that materially affects the Generator’s economics, or due to changes in the market structure. Relief is also planned to be made available due to certain discriminatory changes in law (including amendments to the RESA required by Alberta) that materially delay the development and construction of a facility or that increase costs a Generator would reasonably expect to incur (but we note that a reference to decreased profits is not included). The RESA terms provide that relief will not be provided where the Generator had prior notice of a change or where the change is permitted by the RESA. Of note, however, is that changes to conditions in regulatory permits or licences will not be considered to be changes in law unless, and to the extent, the applicable statutory regulatory provisions change. Furthermore, a change in law will not qualify to the extent that it only applies (or applies earlier) due to the Generator’s conduct. Where it is available, compensation is expected to be provided on a “no better and no worse” basis. Seeing the final drafting on these change-in-law provisions will be key to developers evaluating opportunities in the Alberta market, particularly given the Alberta government’s recent stance on change-in-law clauses in legacy power purchase agreements.
6. Facility Modifications
Consistent with the position taken by governments elsewhere in Canada, a Generator under a RESA will not be permitted to materially modify, vary or amend the specifications or features of the subject facility (as set out in the specifications attached to the RESA) without the AESO’s consent. It remains to be seen in the final documentation in what circumstances the AESO would be entitled to exercise discretion here, and this could impact the ability of Generators over time to adapt facilities to new technologies.
7. Termination for Convenience
The AESO maintains a unilateral right to terminate the RESA for convenience that applies both pre-construction and post-construction. For terminations prior to construction commencement, the compensation payable to the Generator includes only qualifying pre-construction costs — the extent of which will need to be better understood. Furthermore, there appears to be a cap on such costs in an amount to be determined in the final RESA. No other amount, including return on equity returns or debt, would be compensated. After construction commencement, it is clear that in addition to decommissioning costs related to winding up the project, project finance debt and termination and breakage costs would be repaid, plus a return on equity to that date. However, it is noteworthy that on a termination for convenience, equity will not be compensated fully for the expected return over the life of the project). This termination risk and the nature of the payments received is something developers will need to understand as it is fundamentally their risk.
8. AESO Fee
The RESA terms provide that Generators will be required to pay an administration fee to the AESO to cover the AESO’s REP development, implementation and administration costs. It remains to be seen whether or not this fee is significant enough to affect project economics.
9. Dispute Provisions
Unlike other power purchase agreements in Ontario and British Columbia, which contain dispute resolution provisions requiring arbitration, the RESA terms provide that in the event of a dispute that is not resolved within 10 days by the parties’ representatives, either party may commence litigation.
10. Timeline and Administrative Resource Issues
Alberta’s proposed schedule to achieve COD for the projects being procured in the REP’s first round is very ambitious. The request-for-proposal stage where winning bidders will be awarded a RESA is expected to last two to three months during Q4 2017. Accordingly, it will not be possible for those looking to participate in the Alberta market to begin substantial development and planning work based on an assured contract until 2018. As noted above, the draft RESA terms require that projects forming part of the first round of procurements commence construction in 2019, but achieving that milestone carries with it significant deliverables on the part of Generators, all of which would need to be confirmed by the AESO concurrently with submissions being made under other projects forming part of the first round. The AESO will need to commit significant resources in order to process the number of deliverables contemplated by the REP.
Similarly, the COD date must be confirmed by the AESO with review of a variety of items as a prerequisite to confirmation of COD. Timelines for the proposed projects have to take all of these factors into account. The REP requires projects to be in service in 2019 (subject to the 18-month longstop default). The AESO’s six-stage process of interconnection (which it targets to take a cumulative 24 months) will be an impediment to potential Generators meeting this tight schedule. As a result, the successful projects in the REP’s first round will likely have to be those which have already received AUC and AESO approvals or have substantially progressed through the AESO interconnection process.
In an effort to accelerate implementation of the REP and have projects in service by the government’s target date of 2019, Alberta is only consulting with stakeholders regarding the draft commercial terms of the RESA until December 9, 2016.
While the industry awaits the final form of the RESA, it will also be monitoring the other recent announcements from the Government of Alberta in the power sector, including its plan to switch to a “capacity” market by 2021. In principle, this concept should not interfere with the development and project financing of renewable energy projects and is likely to be well received by developers and lenders. However, more details will need to be known, including the impacts on the market design generally and with respect to the REP.