November 2023 Alberta Electricity Newsletter: Transmission Green Paper

December 1, 2023
Christine Runge

On October 23, 2023, the Government of Alberta Department of Affordability and Utilities released its Transmission Policy Green Paper. This left industry scrambling to quickly put together comments on policy considerations that could shake the foundation of Alberta’s energy market. Those comments were due November 30, 2023.

The paper started off simply enough with a recap of the previous year’s consultation, focused on changes to Generating Unit Owner’s Contribution (GUOC), modifications to transmission line loss calculations, and non-wires solutions enablement.  For more information on the prior consultation, see Power Advisory’s August 2022 article.

The government is expected to move forward by removing the prescribed maximum for GUOC and setting the minimum at $0/MW (currently the minimum is $10,000/MW and the maximum is $50,000/MW).  Refundability is expected to be maintained. The decision to remove the maximum, instead of simply increase it, will create significant uncertainty until a GUOC calculation methodology can be consulted on by the AESO and approved by the Commission. It could be a couple years before industry has an understanding of the rates to be paid in congested areas. In the meantime, development efforts will continue by those brave enough to take on the blank cheque risk of an unknown GUOC but may slow in congested areas (this is not necessarily a bad thing if the transmission infrastructure is insufficient to meet the needs to those projects anyway). Projects sufficiently far along in their development will safely pay the current GUOC rates, but projects with ISDs farther out on the horizon will need to be warry.

A draft Transmission Regulation is also expected to change the transmission line loss calculation from one with different loss factors at each substation to a simple system average approach. Under this approach, generators will all be subject to the same rate, regardless of their location on the system. As loss factors can be highly volatile from year to year in areas with generation development, many generators will welcome this stability. It will make it much easier to plan a development project knowing, within a much smaller range, the loss factor which will apply over the life of the project. However, generators that have loss factors at their substations will see their monthly bills change from a credit to a charge, impacting their bottom line. As with all changes from the status quo, there will be winners and losers.

The government did not design its comment matrix to allow for further comments on the topics of GUOC and line losses except to the extent that they overlapped with other areas of consultation.  

The next set of changes will be relatively straightforward as the regulation is likely to simply include some language that enables the AESO’s use of non-wires solutions on the transmission system. This change dove tails with the amendments in Bill 86 which are passed but not yet proclaimed.

From here is where things get complicated as the government sought comments on what it coined “Broader Policy Considerations.” These are much more significant issues than the minor tweaks to GUOC and line losses.

First, changes are contemplated to the zero-congestion policy. This policy has been foundational to Alberta’s energy-only market, enabling free and open competition between generators and allowing load to pay for energy based on an uncongested system marginal price. Changes to this policy will impact every aspect of Alberta’s energy market and necessitate numerous conversations about other market rules that need to change or be created.

That being said, Alberta’s grid has been slipping farther and farther away from that congestion free ideal over recent years. The Transmission Regulation only requires the AESO to plan for a zero-congestion system in normal operating conditions, it does not hold the AESO accountable to operate a zero-congestion grid in real time. As transmission development takes significantly longer than generation development, there is some excuse for the AESO to fall behind; however, the AESO further exacerbates this problem by not reacting as quickly as it should under the prevailing zero-congestion policy.  If it were to follow the letter of the government policy, the AESO should be alleviating congestion on a planned basis. Instead, it waits until congestion occurs and then may further wait to see if that congestion is temporary before working to resolve it. For example, the AESO has stated an acceptance of ~0.5% congestion before triggering transmission system upgrades (see CETO status reports from AESO) despite the very clear guidance in the Transmission Regulation that it is required to plan to allow for 100% of in merit generation to flow on the transmission system.

Given the congestion that is being experienced on the grid, the government rightly asks how much real-time congestion is acceptable on the system before some policy changes are required, as part of its comment matrix. It also explores implementation of an optimal transmission planning approach, increasing the allowable level of congestion in the regulation, introduction of a locational marginal pricing (LMP) model, and uplift charges paid to generators.

The status quo seems impossible as the AESO has long since abandoned the intent behind zero-congestion policy and pushed the limits on what it should be able to do under such a policy. At the same time, incumbent generators invested into a market with an expectation that the zero-congestion policy would be maintained. Accordingly, as changes to the policy are contemplated, it will be important to consider fairness to generators. While the government’s goal is likely the lowest total delivered cost of energy to load, this goal is unlikely to be achieved if incumbent generators are bankrupt or if Alberta’s energy market is no longer an attractive place to invest.

While Alberta’s transmission costs are some of the highest in North America, Albertans also receive the benefits of congestion free price setting in the energy market. When congestion occurs and the next marginal unit is dispatched in order to supply power, instead of the system marginal pool price paid to all generators increasing to the offer of the new marginal unit (as would occur in other jurisdictions), the pool price remains unchanged and the only cost of congestion to load is the uplift payment paid to the marginal generator. Load saves a significant amount of money through this design; however, it will not make sense to continue with this design if the zero-congestion policy is abandoned, resulting in higher energy prices in hours with congestion on the system.

However, to the extent that there are concerns that we are overspending on transmission or that transmission is just too expensive, there is the potential to move to a model of compensated congestion. Providing constrained down payments to generators to make them whole for the lost energy market revenues at times when they are in merit but unable to generate due to transmission congestion allows the AESO to develop less transmission while being fair to generators who built into a zero congestion framework, continuing to enable competition in the energy market, allowing investor certainty to developers unsure of how to plan for how much congestion they will face, and ensuring the lowest total delivered price of energy to load by both allowing the market to clear at the uncongested price and only spending money on new transmission builds when they pass a cost benefit analysis.

The next major item of consideration was changes to the load-pays policy. This is likewise a foundational part of Alberta’s market design.  This policy was designed to ensure an unpolluted energy price (allowing consumers to clearly see the costs of generation separate from the costs of delivery on their bills), to prevent distortions into the energy market price that could result from different offer behavior if transmission was billed to generation on an hourly basis using variable charges, to ensure transmission costs are not a barrier to generation investment, and allows generators to locate in areas that maximize access to resources and give them the best chance to compete in the energy market.

Prior to the Transmission Regulation, which was passed in 2004, generation and load shared the cost of transmission 50%/50%. A return to that model is contemplated in the green paper, though no specific percentages are discussed. The paper also suggests the possibility of charging transmission system costs to generators at the time of connection or creating transmission rights, which would be auctioned off, with the proceeds of that auction offsetting transmission costs to load.

To the extent that the government moves away from the load-pays policy, how it chooses to do so will have a significant impact on generation. Incumbent generation will not be subject to any additional costs if the policy change is to allocate system costs at the time of connection. Development projects, meanwhile, may face charges so high that prevent them from moving forward. If upfront costs are too high and prospects to recover those costs in the energy market too grim, this policy could put a halt on development that could result in supply shortage issues. Even if it doesn’t go so far as to cause reliability issues, less supply available to serve the existing demand is still likely to increase energy market prices to load.

If, instead, the policy change is to move to an alternative cost sharing framework that would result in transmission costs charged to generators monthly through Rate STS, then all generators will pay this charge equally; however, to the extent that it is a variable $/MWh charge, the vast majority can be expected to be simply flowed through the energy market price to load.

The generators harmed by this policy are the price takers offering in at $0/MWh. Any generator submitting a marginal priced offer will simply add the cost of transmission to their offer. It is a cost to them in the same way gas and carbon taxes are costs, and these generators will not produce energy if they cannot recover those costs. Price takers, on the other hand, are relying on other generators to add the cost of transmission into their offers, and when the price clears below the cost of transmission, the price takers will be out of pocket.  This type of policy is, accordingly, likely to disproportionately harm renewable generation. While this government may not consider that to be negative, it is likely to make it more difficult to achieve any net-zero goals we may have.

Next, the government is considering changing cost allocation to ancillary services. These are likewise currently paid by load but could be paid by any party on the basis of cost causation in the future. If this policy changes, the creation of a new rate design structure may be complex.
Lastly, the government may look to increase clarity on intertie restoration timelines and future intertie development. Here the AESO is likely to focus on restoration of import capacity, but generators will want to also see restoration of export capacity to the extent this moves forward.