Last week the Alberta Electric System Operator (AESO) released a document describing the key provisions that it proposes to include in the RESA (Key RESA Terms) Here. RESA stands for Renewable Electricity Support Agreement. It is the legal agreement that the AESO will execute with each successful proponent in this year’s 400 MW renewable electricity procurement that kicked off in Alberta last week (REP Round 1). Read our recent post here. The RESA will contain the terms by which the AESO will provide financial support to the winning projects. Accordingly, the RESA will be the principal agreement upon which successful proponents will finance their renewable electricity projects. Its terms are therefore critical to the success of REP Round 1.
The RESA is essentially a twenty (20) year contract for differences linked to the hourly Power Pool Price for electricity in Alberta. Payments under the RESA will be automatically adjusted so that as the hourly Power Pool Prices earned in Alberta by a successful proponent rise, the AESO financial support falls, and if the hourly Power Pool Prices rise above the strike price bid by the successful proponent in REP Round 1, the successful proponent must pay the difference (excess revenues) to the AESO. The intent is that a successful proponent will not bear Alberta’s Power Pool Price risk over the term of its RESA but, in return, the proponent foregoes windfall profits in times of high Power Pool Prices. Sounds fair, yes, but the devil is in the detail – the Ts and Cs of the RESA, shall we say.
The Key RESA Terms is actually an update of a document released for comment last November by the AESO. We assisted clients to comment on the earlier document, but did the AESO listen to them or to the other stakeholders who commented? As you might expect, the answer is a “yes” on some things and a “no” on other things. That makes sense given that the RESA is trying to balance the interests of both project proponents and the AESO – a risk allocation exercise. The AESO holds the pen on the RESA and therefore has the final say, but it has to be careful to properly allocate each risk (e.g. delays in construction, changes in law, inflation) over the term of the agreement to the side that is best able to manage that risk. If too much or the wrong risk is placed on project proponents, rather than the AESO, then REP Round 1 will not be successful because proponents will either decide not to bid their projects or to bid their projects at high prices that include significant risk premiums. Further, the terms of the RESA need to be such that the RESA is financeable or bankable, at reasonable interest rates, so that a project proponent can economically source the money needed to construct its renewable electricity project.
One big issue that the AESO has to address in the RESA is curtailment. At any moment in time a power project in Alberta can only sell its electricity if it receives a dispatch instruction from the AESO directing it to deliver its electricity to the grid. In addition to other requirements, a dispatch instruction will only be issued for a project if the transmission system to which the project is connected is working and has the ability or capacity to receive and transmit the project’s electricity. If that is not the case, then the AESO may issue a directive to curtail (not dispatch or dispatch down) generation from the project, even though the project is available (i.e. able to generate electricity) and in merit (i.e. bid price is such that project should be permitted to sell its power). ISO Rule 302 describes in detail how the AESO currently mitigates transmission constraints in Alberta.
Remember, however, that the RESA is in substance a contract for differences. Accordingly, a key component of the proposed RESA is that the AESO will only provide funding over the RESA twenty (20) year term for the metered electricity that a project actually generates and sells into the Alberta electricity market. Thus, unless the RESA provides otherwise, a successful proponent will not be compensated by the AESO under the RESA if its project cannot at any time generate and sell electricity because it is curtailed by the AESO.
The last version of the Key RESA Terms stated clearly that the project proponent would not be compensated by the AESO for the electricity that it could have produced, but did not, during any curtailment. However this changed in the version released last week, with the AESO now proposing to share the risk associated with a “transmission constraint”.
The new AESO proposal is that a successful proponent in REP Round 1 first assumes an annual threshold amount of transmission constraint risk (calculated based on 200 hours and the contract capacity under the RESA), and that the AESO then assumes the balance of the annual transmission constraint risk once, or if, the threshold is reached in any year. Every time a transmission constraint occurs, there will be a calculation of the notional amount of electricity that the renewable project would have generated and delivered to the grid but for the AESO issuing dispatch instructions or other directives that curtail or limit generation by the project due to that transmission constraint. The AESO calls this “Forgone Energy”. The proponent will be at risk up to the threshold amount of Forgone Energy in any year, but will be compensated by the AESO under the RESA for the balance of Forgone Energy in that year. There is no express definition in the Key RESA Terms for what will be considered a “transmission constraint”.
Some proponents will claim that even a sharing of transmission constraint risk (under the new proposal) is unfair because they are being asked to assume risk under the RESA for something that the AESO is legally responsible for under current legislation – the design and availability of a congestion free grid. Thus, the argument is that the AESO, and not a project proponent, is the best party to manage and bear transmission constraint risk in full.
These risk sharing and Forgone Energy concepts (along with many other parts of the Key RESA Terms) were borrowed from Ontario’s renewable electricity procurement documents. However in that province, proponents were only asked to assume 100 hours (not the 200 hours that the AESO is proposing) of transmission constraint risk per year, plus Ontario’s system operator included a total cap (a 2,000 hour maximum) over the term of its agreement rather than just an annual threshold amount like the AESO has proposed. The total cap was an important feature in Ontario for project lenders because they could quantify the total transmission curtailment exposure prior to lending to these projects.
There are also two important caveats in the Key RESA Terms for Alberta that should not be overlooked by stakeholders.
First, a transmission outage which results in the power project not being synchronized to the grid is excluded from the calculation of Forgone Energy. Further, even if such a transmission outage was an event of force majeure under the RESA, the Key RESA Terms do not permit an extension of the twenty (20) year RESA term if such a force majeure event occurs after COD. Thus, it appears to AlbertaPowerMarket.com that if the transmission system to which the project is connected goes out completely, as opposed to being partially constrained or congested, then there will be neither compensation paid by the AESO under the Forgone Energy calculations nor an extension of the RESA term for that transmission outage period. In other words, our reading is that transmission outage risk is to be borne 100% by the project proponent under the proposed terms for the RESA.
Second, there will be no compensation by the AESO under the RESA if pursuant to ISO Rule 202.5 the project is curtailed because at any time the supply of electricity at zero dollar ($0) bids (generally composed in Alberta of renewable generation and the minimum stable generation of the thermal plants) exceeds system demand. In other words, the successful proponent, and not the AESO, will bear the risk that over time Alberta procures more renewable electricity than the Alberta market requires to meet demand at any moment in time. Zero dollar ($0) Power Pool Prices happen infrequently now in Alberta, but over a twenty (20) year contract it is a risk that will need to be assessed by developers and their lenders. Again, many project proponents will criticize this proposed allocation of “project over build” risk because it is Alberta (through the AESO), rather than the project proponents, that will decide how much renewable electricity will be procured over time in the province.
In summary, the AESO has moved on the curtailment risk issue, but it has only agreed to accept some of the curtailment risk caused by a transmission constraint. Proponents have not received the broader curtailment protection that many requested, which was to be compensated if they were not dispatched or dispatched down (i.e. curtailed) by the AESO for any reason that was beyond their control. Unless the AESO agrees to move again on this issue, the proponents will have to assess and factor the transmission constraint and broader curtailment risk for their projects into their bid prices in REP Round 1. This is not fatal in our view to REP Round 1, but its importance should not be overlooked as it may result in bid prices for REP Round 1 that are higher than they otherwise would be in Alberta.
We encourage the AESO to spend some time at the upcoming information session on April 18, 2017 or at another session, to more fully explain its thinking on curtailment. This should include how the Forgone Energy, Change in Law and Force Majeure provisions to be included in the RESA will work together to address various potential curtailment scenarios. This will help to clarify the issues, and may allay some of the developer and lender concerns in respect of curtailment.
Curtailment is only one of many issues identified by AlbertaPowerMarket.com in the latest Key RESA Terms. We are also speaking to clients about the provisions in the Key RESA Terms dealing with AESO termination for convenience (especially the limit and cap on payments if done prior to the commencement of construction), early COD, pre-COD energy, change in law, facility modifications, and the sharing of government support payments. A full legal version of the RESA, and not just the high level terms that we got last week, will be released by the AESO in the RFP stage of REP Round 1. We will continue to monitor RESA developments and post commentary at AlbertaPowerMarket.com on this and other issues that are applicable to the Alberta power market.
Kent D. Howie and Joelle Dudelzak