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Price spikes vindicate ERCOT’s market design

Aug 21, 2019 5 MIN. READ
Significant price spikes in ERCOT validate the model of energy-only market design—and should invite new players to the table.

Major price spikes in ERCOT over the week of Aug 12-16 provided not just much-needed revenue for market participants, but also much-needed practical validation of ERCOT’s energy-only market design. Amidst hot weather, real-time prices hit the ERCOT price cap of $9,000/MWh over the course of nearly four hours in total. After another disappointing start to the summer, and growing skepticism about the potential for meaningful price spikes in general, buyers should be compelled to respond with stronger contract prices for electricity, and quickly, to keep the market healthy and incentivize new builds. This is a scenario we have been predicting for some time.

Proof of concept

ERCOT instituted the operating reserve demand curve (ORDC) and a $9,000/MWh price cap in late 2014. Since then, until last week, the market had only ever seen one fleeting glimpse of that glimmering unicorn, for ten brief minutes in January 2018. Yesterday’s events may not fully reverse the prevailing winds of skepticism in the forward market despite low reserve margins (which reached a nadir in July, when on-peak prices for August traded at less than $100/MWh and future years’ forward strips were similarly anemic), but the events of a single day need not accomplish that feat. At least the concept is proved -- when stressed, extended episodes of $9,000/MWh are possible. The unicorn is real.

Grid is still at risk

To keep the lights on Tuesday afternoon (August 13), ERCOT declared emergency conditions and deployed interruptible load resources (the ERS program). This was required despite wind at peak that was near expected levels and only ~2 GW of resources on outage status. The demand was slightly higher than forecasted (the projected peak was roughly 75.5 GW vs the CDR forecast of 74.8 GW), but overall, the situation was near the expected case. The presence of high scarcity prices during “normal” conditions indicates a grid at risk and short of capacity.

Variability in wind output alone can cause a 3.5 GW swing in reserves at peak. Had wind, outages, or weather been worse than expected, the grid would likely have experienced blackouts. It could still easily face these conditions either in the upcoming weeks of August 2019 or in 2020, especially with demand growth of 2-3% evident in the market. The grid needs to add 2 GW of firm capacity per year just to keep pace with demand growth, let alone resolve the present shortage. From a purely commercial aspect, it becomes clear that further price spikes can easily result.

Forward contracting needed

Bringing additional capacity online will require improved contract prices and a renewed willingness to invest. Weak summer prices have led to caution on the part of buyers (and would-be financiers of new plants) and created a heavily ‘backwardated’ futures market for power (lower prices over time).

Additionally, as we have noted before, there remains asymmetry in ERCOT market developments as the time required to bring a new plant online is much longer (a matter of years) than the decision to retire an existing plant (a matter of months) in response to a change in spot prices. The Public Utilities Commission of Texas noted this problem during the winter of 2019 and tweaked the ORDC towards producing price signals earlier in response to dropping reserves. This action, coupled with the practical validation of the price spike model seen on Tuesday, should provide the impetus to the market to improve contracting options and terms for new plants.

ERCOT’s model has already demonstrated its resistance to overpaying for excess capacity. The retirement of 5 GW of coal in late 2018 proved that the concept worked in practice. Now the model is proving its ability to compensate plants when capacity is absolutely needed—and we believe that need is clear today and in upcoming years.

Below you will find our 2018 blog post that discussed the potential for this type of event to occur in the ERCOT Market.

Two months ago, ERCOT’s Capacity, Demand and Reserves (CDR) report projected a reserve margin of just 9.3 percent going into 2018. Even though this figure is widely acknowledged to be well below both economical equilibrium and target planning levels, the power market has reacted only modestly. However, a close look at the situation this summer shows that the $9,000 price cap for energy in the market may be sustained over the summer peak this year, producing scarcity revenues far above what market forwards are showing and creating opportunities for owners and investors.

In markets with forward capacity market structures, this low of a reserve margin would yield very high prices ahead of time. In ISO-NE, a smaller system than ERCOT, the price would hit the maximum allowed price at 1.6 times Net Cost of New Entry (CONE). Even in PJM, a larger system, a 9.3% cleared internal reserve margin would yield the maximum capacity price at 1.5 times Net CONE. But the 2018 ERCOT market is not reflecting anything near these levels.

ERCOT relies on a real-time scarcity mechanism that does not pay resources in advance, and it’s more difficult to predict than simply mapping installed capacity against a demand curve. Yet the traded forward energy prices may be drastically underestimating the possibility of high real-time scarcity. The chart below shows the on-peak forward prices traded over February 7th for each month, and our estimate of the scarcity inherent in each:


On-peak Forward Prices Traded Over February 7th

Month

Peak Forward ($/MWh)

Scarcity Estimate ($/kW)

May

28.3

1.2

June

38.2

3.9

July

70.3

15.0

August

107.1

27.5

September

34.5

1.1

Total

48.7


Note: Scarcity is administratively added on to the SCED-cleared energy price. By subtracting what we project the cleared energy price will be (using forward gas prices and the ERCOT system), we estimate what the total scarcity adder would be over the on-peak period.

The total estimated scarcity in the forward curve for 2018 summer is only around $50/kW. This is striking: with a reserve margin well below what anyone estimates is needed for reliability, and further below what many estimate would provide market equilibrium returns, the scarcity estimate in the forward is not reflecting close to what many would consider Net-CONE levels.

Again, with such reserve margin, Northeastern forward capacity markets would be clearing in the $120-160/kW range. This is important because prices above Net CONE are a signal for new capacity entry and return on investment for existing resources.

Many believe the Operating Reserve Demand Curve (ORDC), the primary mechanism for producing scarcity prices in ERCOT, is inherently volatile and — since it has produced very little revenue since its adoption in 2014 — this summer may be no different. While we routinely write about the volatility of the construct, a closer look at the summer situation shows that the occurrence of high scarcity events is not just possible — it’s expected.

Here’s what ERCOT’s 2018 Summer Assessment (SARA) — seasonal report that looks at operating reserves and possible contingencies — might look like compared to 2017:


ERCOT Summer Assessment: 2017 vs. 2018 (Projected)

MW - Summer Reserve Capacity

Forecasted Case

90th Percentile Thermal Outage

90th Percentile Low Wind

Extreme (2011) Weather Load Adjustment

2017

5,506

3,632

2,471

1,813

2018 (anticipated)

1,037

(721)

(2,326)

(2,658)


ERCOT notes that any value below 2,300 MW indicates risk of EEA1, the point at which ERCOT begins to take emergency actions such as manual all-call of resources, deployment of interruptible load (ERS), and use of emergency interties. The real-time price at this point is likely at the $9,000/MWh price cap.

In the forecasted case, the peak hour reserves dip to 1,037 MW, which means a shortfall of 1,263 MW before ERCOT could avoid emergency conditions. Using recent load shapes, we estimate that on average, nine hours over the course of the year would be within 1,263 MW of the peak demand. If each of these hours were at the price cap, it would imply scarcity of $81/kW-yr just in those hours, and additional hours would see high prices as well, further raising scarcity. For comparison, we estimate no year since 2011 has seen scarcity higher than ~$30-35/kW, with 2015-2017 being below $20/kW-yr each. Further, this is just considering normal forecasted conditions, not accounting for possible contingencies.

We expect scarcity for the remainder of the year could be as high as $100-120/kW. Further, the forwards have only moved up to these levels recently (showing ~$50/kW of scarcity), with the January 23rd price spikes as a result of a delay in the day-ahead clearing mechanism, unrelated to any fundamental summer peak condition. The August peak forward for 2018 as of December 7th was just $88.1/MWh, vs. the $107.1/MWh as it stands in early February.

What could that mean? Forward prices tend to overweight recent historical outcomes and undervalue shifts in market fundamentals going forward. If the summer of 2018 materializes with very high scarcity, the forwards may again overreact, allowing savvy market participants to lock in forward contracts. Though not without risks, this situation presents a tremendous opportunity to generators to earn above-new-cost returns at a time when capacity market pricing elsewhere have been modest.