ERCOT/PUCT strategic roadmap suggestions

A few weeks ago I published the article: “PUCT and ERCOT, big transmission problems are looming, especially for Houston, Generation siting requires big changes in market design”.? I received a lot of positive feedback, this article focused on the deliverability issues, which will only grow (supported by trend in Congestion Revenue Rights (CRR) and Generic Transmission Constraints (GTC)). ? Although the looming deliverability issues are very critical, there are other issues that should be addressed by ERCOT or the PUCT.? In this paper I will cover the different strategic threats, my view of them and potential solutions.? This paper in combination with my previous paper https://www.dhirubhai.net/posts/stefaan-sercu_bess-energystorage-ercot-activity-7272634970555260929-tnu2?utm_source=share&utm_medium=member_desktop could provide a roadmap for ERCOT.

Besides deliverability issues the main concerns are availability, capacity and commercial.? There are, of course, linkages between each of those and solutions for one could help the other.

Capacity versus reliability

Every year stakeholders, press and customers look anxiously to the winter and summer assessment of ERCOT and get comfort (or not) from the analysis.? The total system capacity is barely enough to cover the expected peak load and other systems have higher reserve margins (enforced through a capacity market).? Assuming ERCOT has a potential big capacity problem would be a tempting but wrong conclusion.

The low reserve margin manifests itself during the summer months, whereas the risk of extended load curtailment is a winter phenomenon.? The summer risks are very manageable, can be addressed relatively simple and have little operational impact on users.? The winter problems, which are an availability issue (enough generation is available but will it run?), are a complete different set of problems.

Summer capacity risk

Although historically the summer risk has gotten the most attention (until winter storm Uri hit) the risk is manageable and has limited consequences.? Small risk does not mean it cannot happen (ERCOT never had blackouts in the summer) but the load profile in the summer would mean that the duration of the outages would be short and for a very limited number of customers.

As mentioned above ERCOT never had big black outs in the summer (interruptible load was curtailed) and the likelihood of this happening is smaller than a distribution outage or an outage due to 4CP management by coops or munies. ? If it were to happen, the system would require a few 1000 MW’s curtailment for a few hours and with a good rolling blackout program (not curtailing critical infrastructure ) this would amount to a small probability for each customer to loose power for 1 or 2 hours per year.? Again this is much lower probability than the typical outage duration due to distribution losses or outages to manage 4 CP.? More batteries and the suggestions listed hereunder should eliminate almost all risk.

Suggestions

4CP: Transmission and distribution tariffs are set based on 4CP (4 highest coincident peaks) and the contribution of each user at that time.? The system peak load is used as a proxy for when the transmission system is the most heavily used.? Although an approximation as the supply and demand locations can impact this, historically it made sense.? As the transmission and distribution charges have a significant impact on the electric bill (and have been trending strongly upwards) some users, especially coops and munies, are monitoring this and manage their load accordingly by reducing demand when there is a high likelihood of a 4CP event.? This has several consequences: demand drops and participants in this reduce their bill and make the non participants pay for the annual cost of transmission and distribution.? Historically this was fine as it kept the system going and delayed potentially necessary upgrades.? With the influx of renewables, very often those events occur when the system is not stressed and offers not tangible benefit to the system.? A better option would be to use the net load (load - renewable generation) as the new 4CP metric.? Load management would occur when real supply versus demand is the tightest and voluntary curtailment at that time offers the most benefit.

Purists may disagree with this solution, however the old approximation was not perfect either and is replaced with an approximation that is relatively similar but offers a very significant system benefit (could in my opinion add up to 5% to the effective reserve margin).

Rolling black out program: rolling black outs as a last resort should have a better framework.? ERCOT should have a clear/transparent process and customers should know where they fall in the cascading order.? Except for a few 1000 MW’s due to forced outages most of this risk is quite predictable and clear communication is essential, a big worry for customers is knowing when the power will come back on and this should be easy to communicate in the summer.

Curtailed customers should be paid as economically they (forced) sold their MW’s to the grid and retail providers should pay them for the estimated avoided usage at the price cap.? It is interesting that during curtailments some retail providers are making enormous profits by selling back the power they hedged for their customers, not delivering to their customers and benefiting while the customers suffer.? This arbitrage together with the low credit requirements ERCOT has for retail creates a risk asymmetry between retail and generation and perverse outcomes (e.g. higher price caps lead to lower prices).

Other suggestions that would keep thermal generation around or incentivize new predictable generation were described in my other paper and would benefit the capacity concern.

Winter reliability risk

Although the system has enough capacity in the winter, availability is a big issue for most types of generation in ERCOT and a fix is not easy for longer duration cold spells, which are fortunately rare.

• Renewable generation suffers from icing/snow and although a lot of solutions have been presented none of them make a material difference.
• Thermal generation suffers from need of winterization (plants in colder climates are in a building) and fuel availability.? ? Winterization: ERCOT has focussed a lot on winterization but plants designed for a warmer climate need fixes to address weak spots, those weak spots only show up during the rare extreme events and a slight change in wind direction will highlight new weaknesses. ? I do believe that winterization makes sense but it shifts to burden too much to the thermal generation segment and avoids addressing more controllable and impactful actions. Fuel availability: during Uri but also previous cold spells gas availability has been an issue and even firm physical gas was cut (purposely in some cases?) and could be sold at higher prices (there is a current court case on this).? Texas is in a unique position as many lines are intra-state and under its control and coordination between power and gas is critical.? ISO New England has taken a very active role in understanding and firming up gas supply. Interaction between winterization and fuel availability.? During cold spells gas prices increase and a lot of generation would loose significant amounts of money starting up the plants early.? A warm/hot plant is less likely to have issues (startup is the hardest) and having a program to start up and compensate plants ahead of the cold would be helpful.

• Backup generation: a lot of backup generation can only be used during emergencies as it lacks the adequate solution control, it would be good for ERCOT to work with the EPA/TCEQ to have agreements in place so backup generation (where it makes sense) is started up ahead of the extreme cold.

• Given (fortunately) the rarity of prolonged cold spells ERCOT should come up with a drastic curtailment plan where critical infrastructure and at risk consumers are protected but where targeted curtailments make a difference, e.g. bitcoin farms, some data centers (to be evaluated) and non critical industry like LNG export terminals.? LNG export terminals make sense as it is a double effect, more gas availability while power consumption is reduced (gas compressors for e.g. Freeport LNG run on electricity).? The same comment as mentioned in the summer section on compensation is valid and curtailed consumers should be compensated.? I am still upset that my power was cut, my provider sold it back to ERCOT, making a ton of money, while I was cold and had to spend money fixing my indoor bursted pipes.

As can be seen from the above some actions can be taken but there is no magic bullet (the time and money to add enough indoor thermal generation with potentially oil back up is not realistic).? ERCOT and the PUCT should focus on how to improve the situation, especially integration with gas market, but also have the honesty to see how to deal with black-outs if they occur after all else fails.? In a worst case scenario a total system restoration would be required and it would be fair to communicated what that would entail so ERCOT and customers can prepare for it (how many months to restore?).

It seems that other ISO’s have more extended programs for black start which is surprising as they have more dual fuel units which makes black start easier versus ERCOT which does not have many dual fuel units.? The state of the market report does not assess this risk and compares how ERCOT compares to recover from a worst case scenario.

Commercial

Electric bills continue trend upwards, energy prices are not that different from 25 years ago but TDSP charges and ERCOT charges continue their trend upwards.? Several suggestions were made in my previous paper but some minor commercial actions should be taken.

Credit: It is disappointing that ERCOT abandoned the new credit endeavor as there is a clear credit asymmetry between retail and generation.? Generation has large investments backing up the bids and still has stringent posting requirements whereas retail has little investment.? Over the years I have seen this risk asymmetry where generation is concerned about forced outages and the higher the price cap the bigger this risk and the larger the unhedged portfolio versus retail willing to take the risk.? What is the worst that can happen for retail?? Curtailments which create a windfall or bankruptcy.? Given the relatively low investment this outcome looks quite good and creates an incentive to be under hedged in the forward, whereas day ahead trades at a premium versus realtime as generators fear forced outages at high prices and are under hedged. ? Higher credit requirements for retail (if not backed up by generation) should partly correct this.

CRR’s

Congestion revenue rights are a critical tool to manage the basis spread.? As there are a lot of points in the system the liquidity is relatively low and for people with sufficient analytical tools it creates an opportunity for arbitrage. ? In my view CRR’s were designed to facilitate the basis risk management for market participants, however a lot of the arbitrage seems to be done by people having neither generation or load.? In most markets I understand the value of speculators to provide liquidity but in an auction market organized by ERCOT I believe all value speculators make is to the detriment of either load and/or generation and ultimately at the detriment of the consumer.? CRR’s should be backed up by a physical position (either load or generation) to facilitate hedging.? It would be interesting to see who benefited historically from this product and if corrections are needed.

LMP’s

Current LMP’s do not adequately reflect the value of location (see previous paper)

Some other thoughts

The system is broken and a strategic roadmap is critical, I was surprised to read: “Leasing contracts that CenterPoint Energy signed for a fleet of mobile generators, at a cost of $800 million, cannot be canceled, company officials told the Public Utility Commission of Texas on Thursday — prompting regulators to say the company needs to consider subleasing or other options.”, it seems they will be moved to San Antonio, interesting.? Transmission utilities should not be in the generation business and a framework is needed (see previous paper for a potential framework).

System inertia: with the lack of thermal generation, system inertia will become a problem, I believe there are some theoretical solutions but have not seen yet how ERCOT is planning to handle system inertia and if existing generation will be paid the avoided cost versus the “new” solutions.

Conclusion

Being a long term resident of Texas and having been involved in many aspects of the ERCOT market I am concerned on the trends that are becoming clear.? Both reliability and cost are a major concern in this very dynamic environment.? I am not always sure the right issues are brought to the foreground (e.g. deliverability) and neither are the most cost efficient solutions and non political real leadership will be required to address them.? I hope this provides some food for thought and I look forward to y’alls feedback.

hashtag#ERCOT, hashtag#PUCT,hashtag#marketdesign, hashtag#renewables , hashtag#energytransition, hashtag#CREZ ,hashtag#transmission, hashtag#powergrid, #winter reliability, #black start