What is changing in WEM Reform?

We’re already in March 2023 and the scheduled “Go Live” date for WEM Reform of 1 October 2023 is fast approaching. So what is changing between the current Wholesale Electricity Market (WEM) and the new market design? The short answer is “a lot”, but in this post, we’ll just highlight the key changes to the WEM after October 2023.

The road to WEM reform

The original 2006 WEM design was modelled after UK and European market designs with a strong emphasis on bilateral contracting and a centrally cleared day-ahead market (the Short Term Energy Market). The state-owned generation company Verve Energy, which owned over 88% of generation capacity at market start, provided all real-time balancing and ancillary services.

By the start of 2012, new entrant generators had eroded Verve Energy’s share of generation capacity down to 56%. In July 2012, a mandatory gross-pool real-time Balancing Market was introduced, where all generators were now responsible for providing real-time balancing (not just Verve Energy’s portfolio). A Load Following Ancillary Services (LFAS) market was also introduced to allow for competition in frequency regulation services. Other real-time frequency control services such as Spinning Reserve and Load Rejection Reserve were still provided by Verve Energy.

Fast forward to the end of 2022 and Verve Energy (now renamed Synergy after merging with the state-owned retailer) now had a generation capacity share below 50%. At the same time, the share of renewable energy generation had increased to over 20% by capacity and 35% by volume of energy (MWh) generated over the preceding 12 months.

In 2018, there was an acknowledgment by the WA government that the current market arrangements were no longer fit for purpose in light of a rapidly transitioning power system, and the WEM reform process was started.

Real-time Balancing Market

The biggest change in WEM Reform is the design of the real-time Balancing Market, going from a largely unconstrained gross pool dispatch mechanism with a significant amount of AEMO discretion in fleet dispatch, to a Security Constrained Economic Dispatch (SCED) mechanism similar to that found in the NEM.

There were already pockets of constrained dispatch in the WEM with the Generator Interim Access (GIA) mechanism launched in 2018 by Western Power, but this only affected the newest wind and solar farms like Badgingarra, Warradarge and Yandin wind farms. All other generators in the WEM remain unconstrained and if system conditions required a generator’s output to be curtailed (or ramped up), they would be receive out-of-market constrained on/off payments.

SCED will effectively make all generators subject to security constrained dispatch. It will also more explicitly and transparently schedule and price Essential System Services (ESS) like Spinning Reserve and Load Rejection (which has been renamed to Contingency Raise and Lower reserves) via spot markets. These services are currently scheduled by AEMO as part of Synergy’s Balancing Portfolio and are administratively priced via the annual Ancillary Service Parameters process. In the new SCED, the scheduling of ESS will also be co-optimised with energy.

The most novel change in the WEM Balancing Market design is the introduction of a spot market for a rate-of-change-of-frequency (RoCoF) control service, where accredited participants can essentially offer inertia into the market. The SCED engine will then select the optimal mix of inertia and other frequency control services to provide system security at least cost.

Reserve Capacity Mechanism

The Reserve Capacity Mechanism (RCM) is retained with most elements of the RCM unchanged or only slightly modified. The key change is the introduction of Network Access Quantities (NAQ), which are basically network capacity rights and reflects the shift to security constrained dispatch in the real-time balancing market. In the past, reserve capacity credits were awarded without considering whether network congestion would limit the actual output of generation facilities in real-time. NAQs acknowledge that with SCED, generators may not be able to provide their full accredited output during peak times due to forecast congestion and a generator may receive a lower NAQ value to reflect this congestion.

The NAQ design preferences incumbent facilities ahead of new facilities by assigning NAQs in an ordered manner, i.e. incumbent facilities receive NAQs first followed by new ones.