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The Public Utility Commission met on January 12 to take up a number of items including discussion of the most recent winter storm, the proposed PCM market design, and a number of projects. The PUC did not take any formal action during this hearing. Chair Peter Lake noted the Commission will decide on recommendations for the legislature during their meeting on January 19. An archive of the hearing and the agenda can be found here.

 

This report is intended to give you an overview and highlight the various topics taken up. It is not a verbatim transcript of the discussions but is based upon what was audible or understandable to the observer and the desire to get details out as quickly as possible with few errors or omissions.

 

Items not discussed: 2, 3, 5, 9-13, 15-16, and 18.

 

Opening Comments

  • Lake – Primary purpose is to discuss market design, but have a few housekeeping items
  • Will receive a presentation from ERCOT on the winter storm that occurred over the holidays
  • Have motion for rehearing for Entergy case and consideration of some other items
  • Will meet in closed session to discuss personnel matters
  • Will then come back into open session to discuss market design

 

Item 1: Public Comment

  • No public comment

 

Item 14: Discussion and possible action on electric reliability; electric market development; power-to-choose website; ERCOT oversight; transmission planning, construction, and cost recovery in areas outside of ERCOT; and electric reliability standards and organizations arising under federal law.

Dan Woodfin, ERCOT

  • Winter Storm Elliot over the holidays was a non-event, but had lessons learned
  • Overviews the communications before the storm occurred
  • Are working on modeling and process improvements; prepared for a higher load than what the forecast models under projected
  • Used firm fuel supply service to maximize available generation
  • Set all-time winter peak at 74 GW
  • Had less wind and less thermal generation on Friday which lead to tight conditions
  • At no point did ERCOT need to declare an emergency or issue a watch
  • Many improvements made after the 2021 Winter Storm helped during this event
  • Were several units that tripped; inspection team has begun to investigate those
  • Will propose changes to firm fuel supply program
  • Will produce a more detailed report in the next few weeks
  • Some other areas in the nation had to go into emergency operations and FERC and NERC are investigating
  • Lake – The fact this was a non-event shows reforms are working
  • Lake – Grid and generators are reliable, but just need more of them; will discuss that later on
  • Lake – Had a clear demonstration of demand response; market forces delivered that
  • McAdams – Will be interesting to see your more extensive analysis; others across the nation are looking at our reforms like South West Power Pool
  • McAdams – What was the drop-off as temperatures abated?
    • Have not looked at that
  • McAdams – Country is re-learning that we cannot only look at summer peaks; as we become more dependent on wind, need to look at demand
  • Lake – Glotfelty predicted that exact phenomenon
  • Glotfelty – Discusses the demand as it relates to wind
  • Lake – Need to be more consistent in preparing
  • Glotfelty – Getting the right amount of information from generators or transmission facilities about outages? Will need to continue to look into this
    • Last year commission required quicker and more thorough reporting and made changes to outage schedule
    • Will look to ensure everyone met protocol obligations and will see if we need to do more; will be sending out RFIs
  • Cobos – Need to take the time to learn from each extreme weather event; need continued improvement in electric/gas coordination
  • Cobos – Know MISO was close to rolling outages; interconnectivity of Texas to other markets is something to keep in mind as states move to focus on net zero goals
  • Cobos – How many units of firm fuel were you using?
    • About 750, at peak was 950; some units generated with their own oil
  • Cobos – How many MW were forced out?
    • About 5.7 GW that went out; not all weather related, but will be looking into that
  • Lake – Firm fuel proved its work in that event; thanks Cobos for her work on that
  • Jackson – Root cause analysis is a good approach
  • Glotfelty – Hope in your report you focus on the swings and misses on the demand numbers; were off significantly

 

Item 4: Docket No. 52487; SOAH Docket No. 473-22-1074 – Application of Entergy Texas, Inc. to Amend Its Certificate of Convenience and Necessity to Construct Orange County Advanced Power Station.

  • Staff – Have a motion for rehearing for the commission
  • Cobos – TAC filed a motion for rehearing and was technically denied on January 9; we should extend the deadline to act on the motion
    • Motion to extend the deadline to act on the motion passes
  • Cobos – Motion to grant rehearing to delete items of fact 91, 92, and 99 regarding requests for proposals; would set bad precedent
    • Motion to grant rehearing to delete certain items of fact passes

Item 17: Project No. 54037 – Reports to the 88th Legislature.

  • Lake – Thanks staff for their help on producing this report
  • McAdams – Grateful for adjunct recommendations that were included in the report
    • Motion to approve the report passes

 

Item 22: Adjournment for closed session

  • Lake – Will meet in closed session and will reconvene in open session
  • The Commission did not take any action on items discussed in closed session

 

Item 19: Discussion and possible action regarding agency review by Sunset Advisory Commission, operating budget, strategic plan, appropriations request, project assignments, correspondence, staff reports, agency administrative issues, agency organization, fiscal matters and personnel policy.

Thomas Gleeson, PUC Executive Director

  • Overviews staff personnel changes

 

Item 6: Project No. 52373 – Review of Wholesale Electric Market Design.

Item 7: Project No. 53298 – Wholesale Electric Market Design Implementation.

Item 8: Project No. 54335 – Review of Market Reform Assessment Produced by Energy and Environmental Economics, Inc. (E3).

  • Lake – Are required by SB 3 to develop reliability service/standards; have met this through weatherization and other reforms
  • Lake – Are meeting today to ensure reliability during periods of low non-dispatchable power
  • Lake – Will call on E3, ERCOT, will ask commissioners to invite witness up to answer questions
  • Lake – Are only deliberating today and will not take any formal action
  • Lake – On the meeting of the 19th hope to recommend a reliability service to the legislature and will then stop that conversation
  • Lake – Will also determine on the 19th if we need some sort of bridge mechanism
  • Lake – Still believe PCM is the best option to meet the requirements of SB 3; sets a clear reliability standard and does not interfere/is completely separate from the existing market
  • Lake – A lot of the criticisms/feedback are technical in nature and will need to make such decisions if we get to that point
  • Lake – If we get feedback from the legislature, will be happy to support/implement a different path
  • Lake – If the PCM is not needed, then we will have adequate supply and the impacts on consumers would be negligible
  • Lake – Has low administrative overhead and less restrictions for market participants; will be centrally cleared in order to prevent market manipulation
  • Cobos – ERCOT grid is experiencing exponential load growth along with population/economic growth; Texas is leading in renewable growth and battery storage
  • Cobos – ERCOT has an aging thermal fleet that is under physical pressure
  • Cobos – Commission has already implemented changes to address extreme weather events; have kept the lights on during two artic blasts and a record-breaking summer
  • Cobos – Need to continue to plan for the future; need to evaluate near-term and long-term solutions; commission should consider a bridge
  • McAdams – Has been a long time coming; agree there are near-term and long-term solutions
  • Glotfelty – Encourage stakeholders to be highly involved in this; will be at this for a long time
  • Jackson – Appreciate all the written comment we have received; support PCM

 

Zach Ming, E3

  • Will provide commentary on some of the comments we have received from stakeholders
  • Will speak on clarifications on scope, technical issues of E3 analysis, broad market design themes, and the PCM
  • Overviewed how E3 analyzed market designs; were not directed to analyze other reforms like new ancillary service products or to develop an optimal mix of portfolio resources
  • Were comments that the report did not contemplate extreme weather; report uses 40 year weather record that has extreme cot/hot temperatures
  • Report does not include generator outages not to the magnitude as they were under Uri as they Commission has made a number of reforms since that storm
  • Were comments that the formulation ORDC was static and E3 did not update them; believe this topic has a minor effect on the conclusion of the report
  • Were many stakeholder comments that market equilibrium is based on the cost of new entry; is our perspective this is consistent with a long-run market equilibrium
  • Were comments that the reports finding of the retirement of 11 GW was unrealistic; that is not an assumption, is a technical output of the analysis
    • Assumption based on ERCOT projections of new resources by renewables on the system
  • PCM is self-correcting; different stakeholders may come to different conclusions on what ancillary products effect dispatchability of system
  • Another theme of stakeholders comments were raised based on too much/not enough of a particular resource; resources are not market designs
  • Report does consider a resource-specific subsidy – a resources dispatchable energy credit
    • Stakeholders noted the way we modeled these differently than what was described in McAdams’ memo
    • Were performing analysis under the PUC’s direction
  • Ancillary service markets are relatively small and are not designed to ensure there is a sufficient quantity total on the system or to meet a certain reliability standard
  • Received many comments on the definition of net load the report uses and the use of storage in that calculation
    • Net load does not play any role in the report; was just in a chat that shows net load
    • PCM uses hours of highest reliability risk; report is technology-neutral
    • Is still work to be done on metric to determine highest reliability risk
  • In report used an annual PCM framework with top 30 hours of highest reliability risk
    • Can formulate it in different ways; stakeholders had different wants in this area
    • Hours should reflect hours where the system has the largest reliability need
  • McAdams – Went through a process on analysis on DECs; was why the final product did not match my initial memo
  • McAdams – First iteration would have resulted in a large retirement of generation and the only net gain would be batteries
  • McAdams – Have personal goals for this market design; one is the incentivization or retention of long-duration generation
  • Lake – Notes this process has been iterative
  • Cobos – Some specifications about the backstop did not ultimately match what I had in my memo, but ultimately agree with your conclusion that it will help with reliability
  • Cobos – What is the impact of including RTC in ultimate cost output for PCM?
    • Analysis assumes real time prices; may be some impact on PCM prices, but is designed to fill the gap in the energy market for equilibrium levels
  • Lake and McAdams – Assumption is the RTC is to stabilize energy prices
  • Cobos – What would be the impact if RTC was not implemented with PCM
    • Would affect the clearing prices of performance credits
  • Lake – Can PCM have reliability we are looking for without RTC?
    • Yes
  • Cobos – Can you explain why you used that figure for cost of new entry?
    • Used the most recent model; with higher cost of new entry, expect potential deficits under cost of new entry would be larger
  • Cobos – Need to ensure we are plugging in updated figures into the ERCOT market; need to account for higher costs
    • Correct
  • Cobos – How many MW is the 1/10 reliability standards?
    • Somewhere about 70 GW; represents how much MW the grid needs in hours of highest availability risk
    • Would be a dynamic number that would be re-calculated every year
  • McAdams – Recommend net load not be used in any market design; what would you use?
    • Do not have a specific recommendation; should look at the hours of lowest incremental operating reserves
  • Lake – Whether it is PCM or not, will need additional analysis
  • McAdams – What constitutes a generator of PC? Loads?
    • Inherent incentive in PCM to reduce load in PC hours; is a cost-saving benefit
    • Question is does load need to reduce; do not want to unnecessarily curtail loads
  • McAdams – Does energy efficiency play into that?
    • Would play into natural load reductions as its inherently there
  • Glotfelty – Is a benefit to the system and prices as a whole if we capture energy efficiency
  • McAdams – Generation is in ancillaries; they are available and dispatched during high-risk hours and get PCs?
    • Correct, if they are available
  • Cobos – Confused as earlier you said ancillaries cannot meet reliability
    • Procurement of ancillaries is not used in any other market solely to total supply
  • Cobos – Say report is tech neutral, but resources that bid into the market need to be competent; assuming a penalty if you are not?
  • Lake – Same reason they do not show up in the day-ahead market
  • Glotfelty – See PCM stopping old units from retiring? Or incenting new builds?
    • Given all renewables/storage coming online (27 GW); challenge is a question of maintaining existing resources
    • If there is a large exit of coal due to environmental regulations, that might require new build to get to total quantity
  • McAdams – Notes older infrastructure cannot ramp like newer units
  • Lake – Dynamic would change as time goes on
  • Cobos – Wondering if generators who are larger would go after PC hours? Would be better looked at seasonally
    • Across the country seeing large-scale reliable events are forecastable
  • Glotfelty – Asks about disbatchabiltiy with PCs; would be penalized if you tripped?
    • Do not have to be dispatched to get a PC
    • If you tripped you would not get a PC, you would be penalized in two ways
  • Glotfelty – What is the difference between a PC/DEC; concerned about going out of the market
    • If the DEC were expanded to include all resources and the hours are shrunk to highest reliability risk hours per year, then yes
    • But it was not envisioned that way, is daily
    • DEC brings in new generation
  • Lake – PCM has two step process have to earn the credit and offer that credit into the PCM clearing house at a low enough price; difference is total amount of PCs consumed equates the entire demand of ERCOT plus reserves
    • If you do not clear the forward market, you could generate in the residual market
  • Glotfelty – Seems whether we have a DEC or PCM, are trying to fool economics; can only do so long
  • Glotfelty – Building/retirement decisions are based on more than PC price
    • PC market is only one of many market products; need to consider all revenues could earn in all markets
  • Glotfelty – Whatever this reliability becomes, it will be a third market
  • Cobos – Stakeholders have raised this point; what is the difference between ORDC and PCM?
    • Biggest difference is volatility; ORDC is designed to deliver unpredictably PCM is designed to produce volatility on a reliable basis
    • Performance credits in PCM can be moved up or down; is a lever
    • Could enhance the ORDC and keep injecting money into it; could lead to more volatility
  • Cobos – Need some level of volatility to drive new investment?
    • Generators do not need volatility, but need revenue certainty
  • Lake – Would say the opposite, but we are tasked to regulate
  • Lake – Fair to say key difference is ORDC revenue goes to whoever happens to be there while PCM would only go to those who could commit in advance
  • Glotfelty – Heard Lubbock Power and Light left SPP because resource adequacy requirements were too high; asks about geographic challenges
    • Report does contemplate a geographic dimension; would need to be worked out
  • Glotfelty – Think generators that are in the load pocket that got a PCM would give them incentive to fight transmission?
    • Is not more than what already exists today
  • McAdams – Reliability standard applies to the deliverability of power; should dictate policy on both sides
    • Agree
  • Cobos – Are you limited to what you actually offered versus what you offered before?
    • Is a detail that needs to be worked out; how much actual performance credits versus what was actually offered
  • Lake – Would be a decision point to be examined; would either restrict to what they offered or have a band of flexibility
  • Cobos – Need to ensure the competitiveness of the wholesale market
  • McAdams – In analysis assume demand curve was CONE or net CONE?
    • Net CONE
  • Glotfelty – Fuel component is the total risk of the generator?
    • Incentive for resources to procure the most reliable resources possible
  • Glotfelty – Some is easy to say and hard to do; wonder if that reduces number of total MW
  • Lake – Would incentivize resources not reliant on fuel; is a private sector problem to solve
  • Glotfelty – See any real difference between RMR and a backstop?
    • Yes; backstop is held out of the market and increasing scarcity and RMR is not
  • Cobos – Have been a lot of comments about holding outside of the market; see a key distinction that I would like to highlight later

 

Pablo Vegas, ERCOT

  • Overviews the current ERCOT system; is based on scarcity and does not focus on building dispatchable resources
  • Need to establish a clear reliability standard coupled with performance criteria
  • ERCOT supports adoption of the PCM; moves away from volatile energy-only market to one that rewards performance
  • Important modification of the E3 report needed: instead of taking just the top 30 hours of the system’s highest reliability risk per year
  • Should use a modified peak net load concept distributed across the year for retroactively settled requirement period
  • Some have said PCM is a novel and difficult to understand concept, but do not agree
  • Expect PCM implementation in total to take 2-3.5 years
  • Monetary cost to develop PCM would cost between $2-4m
  • Recommend investigating existing market tools in place for an interim solution
  • McAdams – Explain all ancillary services ERCOT will have by the end of 2023?
    • Will have new services including ECRS with different criteria than non-spin; looking to enhance firm fuel service and broadening those who can participate
    • Have current non-spin, emergency response services, and new services split out of fast frequency resources
  • McAdams – Firm fuel requirement would be separate from RRS?
    • Yes
  • Cobos – Will continue to rely on ancillary to maintain reliability until long term solution?
    • Yes and are operating more conservatively
  • Cobos – How much ECRS ERCOT will procure? Expect bucket filled on day one?
    • Estimating 1200 and 2800 MW
    • Have not gone through the qualification, but yes; purchasing estimated June 2023
  • Cobos – Want to make sure we get a good view of evaluation; ECRS bucket is the same resources bidding into RRS today
    • Correct
  • Cobos – Is adding more ancillary services going to cause more RUCing?
    • It could, if we carry more reserves, would possibly be less commitments from generators
  • McAdams – Is there a seasonal component to that?
    • RUCing tends to happen in middle loads in the market
  • Cobos – That RUCing will have an effect on long-term reliability?
    • Older units tend to be those RUCed; desire is to get to a market design mechanism that minimizes the requirement for continuous RUCing
  • Cobos – Believe PCM would incentivize new build that would replace those being RUCed?
    • Yes
  • Cobos – Goal is to RMR those that are being RUCed, but concerned continuous RUCing would cause damage so you cannot RMR?
    • During the transition want to keep those units, but the ultimate goal is to create a mechanism that enables a fluid reliable transition to newer generation
  • Cobos – Think we need a transitionary tool; cannot rely on RMR and RUCing; why I proposed BRS
    • Focus should be getting to the long-term solution as soon as possible
    • Mechanisms for backstop are different than firm fuel; cannot use for local transmission
    • Cobos – We could, would be a policy call
  • McAdams – Option is regionally based existing firm fuel
    • Need to figure out how to optimize near-term and long-term solutions
  • Jackson – Thoughts on the value of PCM in promoting demand response?
    • Will perform and be incentivized by PCM;

 

Kenan Ogelman, ERCOT

  • McAdams – How long will it take to implement RTC?
    • Are minor updated needed to be made and need to work within EMS freeze; looking at end of 2025-26 as delivery time
  • Lake – The current status?
    • Yes, if we start up on RTC?
  • McAdams – Would implementing PCM impact this timeline
    • No; PCM does not touch market/energy management systems
    • Would stand up a forward market; expectation it will be settlement-heavy
  • Cobos – RCT does go through EMS?
    • Correct
  • Cobos – Where are you on the settlement side?
    • Is the most finished out of the requirements; may need to incorporate some of the design later
    • Settlement team seen some release, but still some work needed to be done on firm fuel
  • Lake – Back to normal from overdrive?
    • Still busier than normal
  • Cobos – RTC and PCM are not necessary to be implemented together, but preferred?
    • All options work better with RTC
  • Cobos – Believe RTC will detract from what we are trying to do with PCM? Found a variety of generators with intent to build have noted they have concerns about this
    • No, reliability benefit to RTC especially with the new mix of resources including batteries
  • Lake – If we want to discuss whether or not we want to do RTC, is a discussion for another day
  • Cobos – Only brought it up due to ERCOT’s
  • Lake – Are you against RTC?
  • Cobos – No, want to make sure it is going to work together
  • Lake – EMS upgrade in 2027?
    • Yes, lose support from the vendor since so many things are changing
  • McAdams – Explain the modified note of the proposal?
    • Gave four options: net load and net peak load; only difference is what type of batteries
  • McAdams – New things are being built on net peak load; need to account for forced outages and to incent generators to maintain facilities so these go down
  • McAdams – Is there any consideration of net peak load minus forced outages?
    • Are looking at that; would like to engage E3 and stakeholders to look at this
  • McAdams – Any downside risks of increasing procurement of non-spin?
    • IMM has raised the issue, generally liquidity in ancillary services is something to examine carefully; is some uncertainty
  • Cobos – Can we get an update on the cost of RTC from a market standpoint?
  • Lake – Do not want to get down this rabbit hole, that needs to be a separate conversation
    • EMS upgrade stats in 2027, but likely would end in 2029
    • RTC creates improvement in RUC
  • Glotfelty – RMR contracts?
    • Have zero
  • Glotfelty – If RMR was used, protocol changes needed if used as a resource adequacy bridge?
    • Protocols modified in 2011 ERCOT could procure resources for capacity; if that was done would use RMR
    • Language currently says one or two seasons ahead look to see if there is a capacity need
    • Are not seeing any substantive rule change needs, but language might need additional clarification
  • Cobos – Costs incurred by RMR?
    • Staffing costs for fuel contracts; if ran, would be additional variable costs
  • Glotfelty – If was additional profit?
    • Would claw that back
  • Cobos – With the last RMR project ERCOT paid for upgrades, what happens after?
    • Plant is allowed to retire, if they want to return any fixed costs ERCOT paid them would be recovered from the owner
  • McAdams – MW withheld from the market, how deal with the reserve cadence?
    • Distinguish RMR for local issues versus system-wide; are different caps for each
  • Lake – Would owe RMR as needed? Could do under existing framework with timeframe tweaks?
    • Yes, is an outstanding question if backstop could be used for local if an RMR study needs to be done for each
    • Would not want to be limited to the $5k price if we needed that unit for local
  • Lake – RMR is something we are talking about a lot now and I do not like the notion of using RMR; is a notion of using it selectively
  • Glotfelty – Why would you not prefer?
  • Lake – If investors are retiring the unit, shows operator cannot sustain business
  • Glotfelty – See it differently
  • Lake – Resource adequacy RMR is not a good option
  • Cobos – When go through RMR does not ensure you will retain plant; is a possibility we lose units because of the RMR process
  • Glotfelty – If we find that happens, need to make a modification
  • McAdams – Woodfin, what do you think?
    • Woodfin – Cobos brings up a good point; need to ensure the process is flexible enough to consider this
  • Lake – If there were any issues with this, sure our board would be diligent on this

 

Warner Roth, Commission Staff

  • Staffed filed a memo and have the following recommendations/comments:
  • Most comments requested better defining the problem; either an operational problem or a resource adequacy problem
  • Those on the operational flexibility side recommended increasing procurement for ancillary products or new ancillary services
  • On the other side, commenters reliability standard and a market construct to incentivize investment to meet reliability standard
  • Staff sees both problems need to be addressed; each requires its own solution
  • Recommends reviewing Phase I enhancements to providing a holistic review of conservative operations
  • Recommends adopting one of the load side constructs studied in the E3 report
  • Staff believes the PCM meets requirements of SB 3 and Phase II
  • If commission moves forward, need to establish a reliability standard; recommends the commission looks at additional reliability metrics
  • E3 assessed risk-factors over an entire year; recommends removal of annual and daily assessments; monthly or seasonal approach is better
  • Commenters recommended using peak net load (load minus wind and solar) to identify risk hours; staff recommends this as well
  • Commenters agreed further refinements of PCM to work with IMM to create guardrails
  • Further refinement of ancillary services should be considered; recommend in conjunction with an additional proposal to serve as a bridge
  • Some commentors suggested a short-term backstop as a bridge; other suggested did not need a bridge as ERCOT already has tools to meet this gap
  • Commission could clarify RMR contracts for those needed to meet reliability standards
  • Recommends commission develop parameters/key principles before implementation
  • Recommends commission show ERCOT prioritization of implementation
  • Recommends clarity on if the previously considered mechanisms such as the dispatchable energy credit mechanism and the LSC are still on the table
  • McAdams – Believe concentration on retail generation is limiting options on PCM?
    • Any market design has risk for market-power abuse; would have to make sure processes are thoroughly robust
  • McAdams – Trying to comingle competing outcomes; need a standalone team within analysis to focus on this as we move forward through implementation at the PUC?
    • Staff – Would need a team focused on guardrails
  • Glotfelty – Affiliate restrictions something should be debated in that forum?
    • Staff – Yes
  • Cobos – Need to consider some suggested measures like allowing virtual transactions, must-offer obligations, etc.
  • Cobos – Need a higher penalty than $25k per day administrative penalty PURA; is a staff suggestion; would need to be addressed by the legislature
  • Lake – Is worth consideration; PCM would require measures that would eliminate self-dealing
  • Cobos – Clearing mechanism of the PCM would ensure no bi-laterals?
  • Lake – All transactions have to go through the clearinghouse; would be no bi-laterals
  • McAdams – Including voluntary forward?
  • Lake – Yes
  • Glotfelty – Analysis on how design would affect retail market? Important to determine if the design will concentrate the market more or not
    • No
  • Lake – Commission did not ask them to look at retail; agree with you, but that conversation will be included in the bucket of market manipulation; would discuss how much is too much
  • Cobos – Need to ensure we have adequate market mitigation measures and predictable costs
    • Staff – Did not take an analysis of the retail market, but considered competitiveness and compatibility in our recommendations
    • Staff – At the top of our list for next things to look at
  • McAdams – Ready to decide on when to calculate highest hour risk?
    • Recommendation aims to frame the discussion
  • Lake – That is a key question for implementation

 

Invited Testimony

Bill Berg, Constellation

Aaron Patterson, Northbridge Group

Daniel Booth, TexGen Power

Bryan Sams, Calpine

  • Lake – What incentives drive generation in other parts of the country?
    • Booth – Building new generation; amount you can borrow to make an investment is generally lower than what you can in other markets like PJM
  • Lake – Other markets have products that incentivize generation?
    • Booth – Yes, PJM data show
    • Berg – Seen new combined cycles grow substantially in PJM and have been able to maintain reliability standard
  • Glotfelty – Capacity payments are not surprising? That’s the expectation?
    • Berg – With PJM there is a viable path to get your money back
  • McAdams – What is the experience of ISO New England and ISO New York? Seen the same growth in those markets?
    • Berg – Yes; before ISO put in capacity market, had 70 RMRs
  • Lake – To be clear, not supporting a capacity market, just looking at what other incentives are out there
    • Patterson – New build investment decisions are long term decisions, 20 year assets; Investors look to see if there is a stable construct in place
    • For retirement it is the opposite scenario, is operation justified or not? Also a 20 year decision
  • Lake – So highest level, do incentives drive investments? does PCM as contemplated provide a similar incentive?
    • Berg – Yes & it begins with establishing reliability standard and building market design around it
  • McAdams – Is constellation going to build a power plant in Texas?
    • Berg – Have a unique opportunity to relocate an asset to Texas; whether that happens or not largely depends on what happens with the PUC
  • Cobos – Isn’t that very different from building a greenfield facility?
    • Berg – It is not cheap to dismantle a plant, ship it, and reconstruct it
  • Lake – I’ve been told that never happens but apparently it does
  • Cobos – I’ve heard of it
    • Berg – Actively being considered at the highest levels of our company
  • Glotfelty – When you say actively considered is that early stage of development? Or you’ve identified sites you might move it to, filed permits, sought water rights, etc.?
    • Berg – Have not entered the interconnection queue or sought permits; those are the two binding constraints
    • Opportunity and economics have been framed up internally
  • Cobos – Moving from PJM to ERCOT; what is the asset life after moving?
    • Berg – Asset is fairly new in terms of run-time
  • Cobos – What is the likelihood that you would continue build under a PCM, does this create a stable price signal to continue to look to build new plants?
    • Berg – Difficult to answer
  • Cobos – Parameters?
    • Pretty much have been laid out, is there an opportunity to recover investment, pathway forward, best place for capital, etc.
  • Cobos – Have always heard that Texas is an attractive investment state due to growth; asks Booth if TexGen has assets in both ERCOT and PJM?
    • Booth – No, we don’t
    • On the growth in TX, seeing explosive growth in wind & solar; question is if they can invest in an asset that will be able to earn reasonable, reliable revenue in a market that has massive renewable buildout
  • Lake – So what we’ve seen is investors are investing in renewables, not dispatchable, in TX
    • Booth – Correct; notes TexGen is only in Texas
  • Cobos – If we moved forward with PCM would replace Mountain Creek?
    • Booth – Would set on a path to re-power it in a way that needs to be done
  • McAdams – Will be PCM-funded competition for your facilities; does that put you over a cliff in terms of facilities competing with PC facilities, would create a scarcity issue?
    • Booth – PCM can provide a life-line to Mountain Creek; operationally having units be able to commit solves a significant portion of the RUC problem
    • If you want a unit that can compete for PCM credits, it is certainly not mountain creek, but this is a feature, not a bug & market shouldn’t rely on old facilities
    • Market should be able to establish a glide path that newer and better assets can be achieved
  • Lake – As an owner of an older resource, see that as a bridge?
    • Booth – If there is certainty a PCM is coming, that itself would be the bridge
  • McAdams – Not scared of Mountain Creek going down on you?
    • Booth – Would price in that risk
  • Jackson – Would you consider a new unit versus an older unit in terms of reliability?
    • Booth – Would be, it’s the RUCing hours you would be concerned about to commit
  • Cobos – What about monthly/daily settlements versus a lookback?
    • Booth – Daily settlement would have issues, but monthly/seasonal would be reasonable
    • Patterson – Design matches the settlement for whatever period you are analyzing performance over
  • Cobos – Filed comments that said RTC does not help resource adequacy, implementation would detract from you
    • Berg – If it is an enhancement you want to pursue, but not a resources adequacy mechanism
  • Lake calls up Bryan Sams, Calpine
  • Glotfelty – Is new transmission helpful or harmful to building on the PCM? Normally a nexus between generation, siting, and transmission, does this go away with PCM?
    • Berg – Distinct issues, when you are siting you are looking at overall market fundamentals, e.g. 37k megawatts construction would add transmission, new transmission would go into calculus on possible return
  • Lake – Could it be both positive and negative, depending on circumstances?
    • Booth – it’s one of many factors you could consider and it can be both
  • Glotfelty – So PCM is a factor that needs to be considered alongside others, so PCM may throw it over the top or it may not; is there fear that with so many renewables coming that you will get crowded out during peak hours? Transmission takes so long to build
  • McAdams – Good point, is that because of Security Constrained Economic Dispatch (SCED)?
    • Patterson – You can be forced down, so long as you are available; for dispatch the design would compensate you
  • Glotfelty – Whether you run or not
  • Lake – Well you’re online & available to qualify
  • Glotfelty – You can be backed down by ERCOT for something
  • Lake – If we have enough wind and solar to congest our lines we’re probably not in the tightest
  • McAdams – Depends on where you are
  • Glotfelty – I think it more as less wind, more solar, because of peak time of the day
    • Berg – Some of these issues are important, but talking about PCM is this the appropriate venue to consider how much transmission to build when interconnecting generators
  • Glotfelty – Transmission takes so much to build the economic impact on generators could change the decision
    • Sams – If PCM creates the right incentives for new generation, you may not need as much transmission
  • Lake – Do you think PCM creates the right incentives?
    • Sams – Yes
  • Cobos – If you’re going to build generation under PCM but transmission is being built in the area, will you still build?
    • Sams – Works into the variables for building something, part of decision on capital recovery
    • One of the great things about PCM is it starts with reliability standard and PUC controls, this is the aspect that gets generation built
  • Cobos – Reliability standard is required by SB 3 and Sunset, standard is taking into account the whole system
  • McAdams – Deliverability
  • Cobos – Has been a history of debate about building transmission in the Houston area & this is why I’m asking; want to ensure we are sending the right signals in the Phase II redesign; need to plan on system as a whole, will be building transmission because we need to
  • McAdams – Calpine sits on really nice real estate for power generation; does economic premise still work for Calpine with highly populated areas under a PCM?
    • Sams – Make continuous investment to bring more MW into the system; believes PCM provides incentives for that

 

Amanda Frazier, Vistra

Emily Jolly, LCRA

Bill Barnes, NRG

  • Cobos – Similar questions, want to understand the things that impact your interest and ability; both Vistra and LCRA submitted comments that RTC does not help with resource adequacy years ago, but now we have PCM, will your company build with an RTC in a PCM?
    • Frazier – Vistra filed comments years ago that RTC creates inefficiencies, but agree with former comments that purpose of resource adequacy mechanism is to offset those pressures
    • Presumably a properly-designed PCM would provide those mechanisms
  • Lake – Benefits of PCM would outweigh pressures of RTC?
    • Frazier – They would work together, concept of RTC is to work in tandem with the right price signals
  • Lake – And PCM would achieve the price signals and incentives to retain and attract dispatchable
    • Frazier – We think that properly designed, it would
  • McAdams – Theoretically RTC nets out and doesn’t take anything away?
    • Frazier – Don’t think of this as netting out, are two different mechanisms; will work in rhythm but aren’t direct net one against the other
    • Jolly – Did file similar comments in the past; supportive of moving forward with a PCM and RTC
  • Cobos – Are you currently co-optimizing? What benefit does RTC provide?
    • Frazier – Agree that focus should be on the resource adequacy mechanism, more commenting on if we have concerns about RTC driving inefficiencies
    • We can do some co-optimizing within our own fleet, RTC would give this some benefit over to ERCOT to co-optimize across entire ERCOT fleet
  • Cobos – Asks Barnes if he has anything to add
    • Barnes – On RMR, NRG had the last RMR contract, commission should avoid taking any path that focuses on RMR
    • RMR means you putting new dollars into the oldest, most inefficient resource on the grid; RMR should be temporary, last-ditch to keep a unit around
  • McAdams – Need a safety net ahead of that?
    • Barnes – RMR can do that, but would need to replace it as soon as possible
    • Mechanism like PCM only works when you need it
    • Retail DR is also important, NRG just invested in a retail DR company that will improve ability to load balance
  • Glotfelty – If you activate DR you reduce numbers of PCs you need?
    • Barnes – And the cost allocated to us, would utilize same concept from 4CP to create something under PCM; would create huge DR program & energy efficiency
  • McAdams – Do you have flexibility in our rules to accommodate this?
    • Barnes – Yes, we have programs currently that can deploy tech at site with fixed price
  • Glotfelty – But that is demand response, what about energy efficiency?
    • Barnes – Both similar as long as you reduce consumption
  • Glotfelty – With energy efficiency you upgrade insulation and reduce demand, doesn’t increase; DR is, on an hour-by-hour basis, you can control portions of demand and consumer gets paid for it every time
    • Barnes – Both important, with a PCM concentrating most of consumption during times when the grid needs it
  • Glotfelty – Could a consumer get a PCM if they upgraded efficiency on their house?
    • Barnes – Not under the existing mechanism, but they would avoid the cost; avoiding cost would be the equivalent
  • Lake – See avoiding the cost as another form of revenue; wind & solar are reducing cost by avoiding tax liability; would be up to the retailers on the customer’s preferred delivery of that, PUC doesn’t need to put that in rule, just put the incentive out there
  • Glotfelty – Would that incent you to go to customers and do energy efficiency?
    • Barnes – Would be on builders; would squeeze more out of EE by aligning incentives to response when the grid needs it the most
  • Cobos – Have read your comments, PCM will drive investment?
    • Barnes – Considering status quo or near status quo solutions, principles we see in PCM with reliability standard, providing direct financial incentives, and improving revenue stability; confident PCM will help us close on financing for development
  • Lake – So you’ve laid the groundwork of those investments, but cannot make them yet
    • Barnes – Not yet, some have been in the works for years, others we’ve filed for studies, etc., watching very closely along with investment partners
    • All feedback we’ve received says PCM will help move us closer to completion, but we’re all watching PUC
  • Cobos – Transmission build out affect siting?
    • Barnes – When there is enough of a reliability need, will end up getting built; environment is pro-transmission
    • In siting new generation, there is basis premium, but doesn’t persist; will go where you get best land, access to resources, etc.
    • Jolly – One of the positive things the Commission has done is changes to transmission criteria
  • Jackson – If the PCM moves forward do you think there will be a race?
    • Barnes – Could see that, DR is much quicker to bring to market, new resources take more time
    • From our perspective it was what we need to do to provide the most reliable, cost effective powers for customers
    • Signal from PUC that there is direction on resource adequacy position, you will see movement
  • Lake – As soon as you see regulatory certainty, you will start moving?
    • Barnes – Yes
  • Glotfelty – If there were affiliate restrictions, would that be a challenge?
    • Barnes – PCM structure mitigates certain concerns compared to FRM, e.g. forward procurement or forward showing
    • Retail market is so competitive it is difficult to know peak load months & years in advance
    • Seasonal aspect and granular bifurcation help reduce credit burden; recommended a day ahead offer in terms of PC eligibility
    • Frazier – Support centralized clearing, support transparency aspect; banning sales between affiliated companies may not be doable; you don’t want to over-mitigate as you end up with disfunction in the pricing
  • Lake – In a central clearing exchange you don’t know who you’re trading with, gives me a lot of comfort
  • Glotfelty – Gives me some

 

Carey Bivens, Potomac Economics

Catherine Webking, TEAM

  • Cobos – Market power mitigation? You’ve been a big proponent of virtual transactions
    • Bivens – Forward market would be voluntary, so you have uncertain quantity of credits available for purchase, in order for these to clear you will need other players in the market
    • Has benefit to clear the market for liquidity and allows for market power mitigation
  • Cobos – Need to consider this in the market power mitigation
  • Lake – If implemented
  • Cobos – Yes, just assume everything I say has “if implemented” at the back
  • Cobos – Speak on thoughts that a $25k admin penalty is not a sufficient deterrent
    • Bivens – If we make a finding of performance violation in the single hour, penalty could be $25k, but value earned would be many hundreds of thousands of dollars; mismatch between penalties and profits earned
  • Lake – Would require a statutory change, correct?
    • Bivens – That’s my understanding
  • Lake – In absence of status quo, would increase in penalty be warranted?
    • Bivens – Is a good idea either way
  • Cobos – As we evaluate Phase II, if we implement PCM, would we need to revisit VMPs currently on file?
    • Bivens – I don’t think they directly impact voluntary mitigation plans, issues you would face on performance credit hours would be physical withholding and voluntary does not affect this; doesn’t involve VMPs
    • With forward market, depends on how you would formulate this, mandatory market with must offer than probably do need to consider
  • Cobos – What about RTC?
    • Bivens – VMPs would need to be renegotiated with RTC
  • Cobos – ERCOT’s recommendation is to continue to RUC in the interim; do you have commentary on day ahead bidding; not in favor of RUCing for years, but trying to find potential bridges; do you have concerns about that & requests for fixed costs?
    • Bivens – Yes, primarily on fixed costs and make-whole payments, economic reasons this doesn’t make sense, no market does this, would increase incentives for people to want to be RUC’d
    • As far as allowing higher offers in day ahead, don’t have concerns conceptually but needs to be evaluated with RUC callback rules and how data is used
    • Automated dispute of exceptional fuel costs is a great idea, being used frequently
  • McAdams – After the discussions, do you still not like PCs?
    • Bivens – We still don’t support PC
  • Cobos – Do virtual transactions give you any comfort?
    • Webking – Yet to be understood completely, if forward market is voluntary, but have heard it would be mandatory
  • Lake – Mandatory for generators, not loads
    • Webking – Yes, but contemplation of virtual is completely voluntary on both sides; fundamental issue that makes market design two very different things
  • Lake – Probably a complex question for technical implementation if we get to that point
    • Webking – Seems more fundamental, is it voluntary or is it something where entity offering doesn’t have to offer full credits
  • McAdams – Commitment isn’t determined yet
  • Lake – Had a good discussion on contemplated PCMs and ORDC, if it’s just whoever happens to show up we already have ORDC; contemplation is premium is for agreeing to be there
  • McAdams – And give ERCOT certainty
  • Lake – I think we can establish distinction between products, how can be determined at a later point and we can lean on stakeholders
    • Bivens – More fundamental, there are ways a forward market does not work; in residual market loads must pay for all PCs generated, will be a mismatch between what loads want to buy and what generators want to bid in
  • McAdams – Saying there will be a mismatch and will always be scarcity and prices will always be sky-high
    • Bivens – Even if they are 0 in residual, with always be high in froward
  • Lake – I don’t think anyone is trying to say no virtual in the forward market; not only do I think we can establish these principles on the front end, but we need to establish before we can dig into nuts & bolts; very solvable problems
  • Lake – There is a possible universe where voluntary forward can be a tool to match risk for the retailer perfectly with the retail contract
    • Webking – There are aspects like market power in exercising price control; there are also competitively neutral constructs that allow retail market to continue in SB 7 structure
    • These are different constructions, fundamentally different for providers and customers
  • Cobos – Market power manipulation on one end, on the other is retail market competitiveness, PCM could affect competitiveness with additional risk premiums that need to be built into contracts; all pieces of the retail market could impact ultimate competitiveness and lead to smaller pool
    • Webking – Hour in which credit obligations are assigned, if that is based on things like thermal outages, virtually impossible to predict load
    • Collateral costs are key in competitiveness issue, big determiner of continuance of retail market
  • Lake – Predicting future loads is hard, which is why PCM does not have forward procurement req, has residual market; just because a new construct regulation is introduced you won’t necessarily have fewer retail providers; those that can deliver best product will thrive
  • Cobos – Not all reps are the same, some have generation, some independent; you’re right, but there are issues in the retail market we need to be mindful of as we continue to evaluate PCM so ultimately all reps can continue to offer fixed-rate products
  • Lake – Certainly something to consider in the technical implementation

 

Katie Coleman, Texas Association of Manufacturers

  • Cobos – PCM/RTC, do you have any thoughts?
    • In 2019 when we did original ORDC shift, this was supposed to be paired with RTC to not get on curve unnecessarily; very important piece of the puzzle
    • If you go towards PCM, you want to make sure that it is being used and dispatched efficiently
  • McAdams – Was concerned about PCM that uncertainty could create distorted behavior; real time co-op gives a safety net on that
    • Would help; have been dealing with these types of inefficiencies for a long time; need to use PCM in a rational way
    • Want to limit PCM to times when market signifies capacity issue, which is why you want to leak to some form of peak load, e.g. net peak load is more predictable for everyone and more predictive of capacity issues
    • Will get more DR and solution will be more tailored
    • E3 report recommendation of low reserves does not get you there
    • Much easier to rationalize and respond to net peak load
  • Glotfelty – Would PCM incentivize members to build more co-generation plants & utilize this to sell into the market as well?
  • McAdams – Or enhanced demand response
    • Anything that makes the cost of buying from the grid greater incentivizes more behind-the-meter generation
    • If it is cheaper to self-supply, they will look at it; a lot of clients don’t do that
  • Cobos – If a PCM is implemented
  • Lake – Subject to consideration by the legislature

 

Closing Comments

  • Lake – Plan is to reconvene on the 19th with more discussion/deliberation
  • Lake – Goal is to meet the requirements of SB 3 and consider, if a bridge is needed, what type of bridge is needed
  • McAdams – Will be a change to the plan?
  • Lake – Will have a narrowed second blueprint; need to identify the principles before anything
  • Lake – Suspect all could come up with a list of, if implemented, the decision points that need to be considered
  • McAdams – Next week we will pull it all together and have it something
    • Staff – Will assimilate all we have heard today and have something for the commission to work with next week