Energy Regulation and Law : Discussion and Commentary on PUC TX DER Pilot Memo - July 13, 2022
Texas energy regulators - Commissioner Will McAdams and Commissioner Jimmy Glotfelty - have issued a joint memorandum in the Public Utility Commission of Texas's policy proceeding, "Review of Distributed Energy Resources" that directs the creation of a pilot project to test impacts of small-scale distributed energy resources in the ERCOT market. The pilot project would be formalized under a series of rules and requirements in the Commission's regulations, Subs. Rule. Section 25.361(k), under which ERCOT has the authority to conduct pilot projects and grant temporary exceptions from ERCOT rules, as necessary to effectuate the purposes of pilot projects. The memo directs ERCOT to prepare and present a governing document to ERCOT's board of directors, which must provide final approval to the pilot under Commission rules. Simultaneously, the Commission has stated that it will form a Task Force to identify operational obstacles to launching a pilot program and also assist ERCOT in drafting the governing document. The Commission has set forth a date for the governing document to be completed and presented for ERCOT Board consideration by October 11, 2022, so that a desired pilot start date of Q1 2023 can be achieved.
The following is a high-level look at what each of the memo's Guiding Principles mean in practice and what types of opportunities and challenges these principles present to the energy market as a whole. It also provides insights into how the Texas energy regulatory landscape could impact which types of customers are eligible for participating in such a pilot if implemented statewide.
Guiding Principles Discussion
(1) Understanding the impact of having ancillary services carried on the distribution system: distribution system providers ("poles and wires" utilities) in Texas have stated they do not have the experience or procedural design for systems in place yet to enable several - and potentially hundreds - of smaller assets like residential solar-charged batteries operating simultaneously on their system to send customer power back to the grid. In these comments filed with the ERCOT grid operator, utilities expressed concern that they have "not evaluated the impacts of residential battery systems simultaneously injecting into the Distribution System during an Ancillary Service deployment. " Utilities also noted that customers injecting through the distribution (low-voltage lines ) back to the transmission/ERCOT grid, could be impacted if they are located on system feeder lines which may need to be put out of service in a reliability event.
- Both issues can be studied in a pilot, along with other concerns or areas of curiosity which these utility systems will inevitably have to reckon with as distributed systems growth continues in their service areas. It also makes sense while the pilot is ongoing and more customer sites begin to participate, to help utility systems identify how to craft DER-friendly energy programs that align a customer's incentives to purchase these systems with their utility's desire to capture the additive value of DERs for their own system needs - and reward customers for their contribution to local reliability and grid reliability.
(2) Create a structure that incentivizes competition and attracts broad DER participation through load serving entities (LSEs): an LSE is a legal entity/company that is in the technical business of delivering megawatts to end-user customers of any kind (homes, businesses, factories, public facilities, etc.). The customer's energy usage is a "Load" on the energy system, hence these companies are known as "load" serving entities (LSEs). Texas is different than most of the Southeast because it has three kinds of LSEs: retail choice competitive energy providers (that buy and sell energy and deliver it to you, and you choose to buy energy from that entity which is why it's called "competitive"), municipal electric providers (cities and public power companies, that do the buying and delivering to its residents, residents do not have a choice), and cooperative electric providers (each member resident in a coop has some stake in the cooperative's ownership, and a Board dictates decisions of the cooperative as to what to buy, where to buy). In the Memo, these LSEs are described as "REPs" (Retail Electric Providers) and "NOIEs" (Non Opt In Entities - meaning municipal and cooperative providers that did not opt in to competitive choice models). Learn more here: https://www.ercot.com/services/rq/lse.
Importantly, LSEs should not be confused with a "poles and wires" company. Rather LSEs are commodity providers - the entity that procures megawatts and delivers it to the end-user across another entity's poles and wires (the Utility). LSE and Utility functions can be combined in one larger company: a "vertical Utility system." That means the same company that is buying the Megawatts (LSE), also owns the poles and wires that deliver the energy to the consumer. Most of the Southeast US is a "vertical utility system" . Texas ERCOT has competitive choice and vertical utility system area (and remember there are non-ERCOT vertical utility systems in Texas footprint, like Entergy and El Paso).
- Therefore, the significance of this guiding principle is that it invites all types of ERCOT customers to participate, but, a NOIE is a gatekeeper for its customers to pilot participation - the NOIE (muni or coop energy provider) must choose to participate to enable access to the pilot and, in a competitive REP area, REPs AND Utilities of the customers must come together to enable participation of interested customers. It also means that customers could have more options in the future with more potential REPs to engage in electricity contracts that have a "virtual power plant" credit or payment associated with their REP participating in the Pilot and partnering with the customer's Utility.
Source map - REPs compete to be their customers' LSEs in these areas of Texas: https://www.powerwizard.com/texas-deregulation-map/
(3) Measure the impacts to relieving or causing congestion on the distribution system, and study how to transition distribution-level aggregations to more granular dispatch and settlement: this is a more loaded principle, but we'll unpack it anyway! ERCOT has best described the issue and concern of congestion in their comments to the Texas Public Utility Commission in 2021. "Nodal pricing is an essential element of [ERCOT's] ' s management of transmission congestion. Every five minutes, SCED's algorithm identifies the sources of electricity supply that can meet the system load at the lowest total cost while maintaining transmission system reliability. Based on this calculation, SCED assigns and communicates to each Generation Resource and Energy Storage Resource (ESR) a specified dispatch level and a locational, or nodal, price. When congestion exists on the transmission system, the nodal price and dispatch level may change depending on whether the Generation Resource or ESR contributes to, or alleviates, the congestion. For Generation Resources or ESRs that contribute to transmission congestion, nodal prices and dispatch are lowered consistent with the Resource's "shift factor"-i.e., its impact on each constrained element. For Generation Resources or ESRs that help to resolve that congestion, nodal prices and dispatch are increased consistent with the Resource' s shift factor. In this way, dispatching and pricing Generation Resources and ESRs on a nodal basis helps to ensure the reliability of the transmission system." ERCOT goes on to explain that DERs are receiving "load zone" pricing for the electricity they consume - meaning, a weighted average of the nodal prices at each electrical bus within each of the eight ERCOT load zones. "Zonal pricing impairs ERCOT's ability to manage system reliability because a given load' s impact on a transmission constraint has no material effect on the wholesale energy price paid by the load. In this way, zonal pricing fails to provide consumers any meaningful incentive to adjust their consumption to resolve those constraints. The use of zonal shift factors to dispatch Load Resources likewise fails to account for the impacts of each load on specific transmission constraints". Weighted pricing in this fashion, is important for unsophisticated energy consumers - because passing "nodal" prices to small customers would mean in neighborhood A and B in the same utility area, customers could receive wildly different energy costs as price-takers on a system where generators and larger system demand are setting highly differentiated real-time pricing. ERCOT's comments state, for this reason: "ERCOT acknowledges that there may be sound non-market policy reasons to continue using zonal pricing to settle individual residential and other smaller consumers" even though the grid operator would like large loads to move to "nodal" pricing. Residential customers that currently participate in export-type programs like solar buyback, thermostat monitoring, etc., are not getting a "market price" for the exports in real-time under either nodal or zonal: rather, their LSE fixes a credit and rate for their participation under a fixed rate/tariff offered to the customer, and settles that exported energy on their behalf in the real-time market. With this pilot in the works, all that could change and diversify product offerings - customers will still purchase energy from their REP/LSE at fixed rates, but the amount of "credit" they get back for exporting power, could go up or down based on how they choose to participate in grid services, that are directly compensated from ERCOT to the REP/LSE, and passed through as bill credits via their REP/LSE.
- The mismatch between how supply-side large power plants participate in the market (nodal pricing) and demand-side energy exporters participate (zonal pricing, or, no direct price-based participation) is a core blocker to Virtual Power Plant models launching in Texas. ERCOT describes this in its comments on quickly unlocked exports from small DERs; ERCOT basically said it was impossible to do so without a long period of studying congestion impacts or resolving this differentiated pricing (bill settlement of energy in, energy out) issue.
- While reading the above may make you wonder - well just move all residential/small DER customers nodal, nothing wrong with that - think again. As RPower mentions in its comments to the PUCT, discussing larger DER resources of 1 -10 MWs, that "[w]hile RPower understands and appreciates the rationale for nodal settlement that comes with the requirement of registration of distributed resources, the practical implications are an incredible increase in complexity for financial analysis and risk management." RPower then expands the universe to VPP approaches, saying "One could argue that all energy consumers should be paying based upon nodal pricing as such a scheme would encourage placement of new loads in areas where pricing is most advantageous. But this would have a deleterious impact on many consumers as they would paying significantly higher prices in certain areas, having potentially catastrophic impacts to businesses and communities across the state. Further, REPs that sell energy to consumers across ERCOT would move from relatively straight forward position management and hedging requirements at a few liquid trading points to incredibly complex hedging requirements at thousands of illiquid trading points. PURA wisely required Load Zone settlement of energy consumers for these reasons." By contrast to large DERs, which look and behave more like large power plants, small DERs serve a different purpose and have a different value to the grid: "DERs have much more in common with REPs than with Generation Resources, considering that a) the size of the assets is small, therefore having limited impacted on wholesale energy pricing; b) the number of assets can be very large, making project evaluation and hedging an incredibly complex task; c) consumers seeking the benefits of DERs will be treated significantly differently given their location; and finally, d) nodal pricing for DERs reduces the benefit to REPs of using DERs as a hedge for their customer's energy exposure by introducing an unnecessary basis cost."
- RPower clearly lays out the case that would make it logical for the DER Pilot to stick with a simple zonal pricing approach while aggregations are small enough that there will be little or no impact on intrazonal congestion, while ERCOT develops a creative approach to "weight" consumers in a nodal approach that fits small DERs better than full-on nodal market pricing.
(4) Ensure adequate customer protection is in place and information is anonymized: this principle is simpler than most to break down. Under Public Utility Commission rules, REPS (by now, you know what those are!) must follow special rules when offering residential and small commercial customers energy plans in their capacity as LSEs. These are: Substantive Rules Section §25.475. General Retail Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers. In addition to these rules, it is clear that if a new VPP product in conjunction with a pilot is offered to REP customers, some new disclosures about what that means/entails are in order. For example, Tesla's ELRP VPP program in California (look up "Join the Tesla Virtual Power Plant - PG&E 2022") incorporates certain disclosures in a customer agreement that is published on Tesla's website (scroll down for the complete customer agreement). "Anonymizing" information, is a reference to information sharing between a pilot participant (REP/LSE) and the customer's Utility. Utilities have articulated a desire to know where customers are aggregating and exporting on their distribution systems, and how that behavior impacts their system (see these comments as an example, or peruse the several individual Utility comments in PUC TX Docket 51603). It could also refer to the manner in which Utilities share information via ESIDs (the individual meter tag on the meter that shows your energy usage) with ERCOT, or, how the Utility exchanges information with their customers about interconnection (the permits/contracts for having such a system interact with utility poles and wires).
- A lot of information has to change hands in order for an LSE/REP to approach ERCOT under a pilot program and qualify their customers in aggregate as a "Resource" that can provide grid services. The bottom line is that this effort is highly collaborative - everyone needs to play ball and work together to create watertight programs, contracts, and customer-facing communications and agreements in place, to get MWs back to the grid and get customers the best deal for their participation. If you're ever wondering why DER pilots can grow slowly, it's the multi-party synchronized movements that are the hardest to achieve - but also the most fun challenges for companies that are passionate about being in this business to enable cool products for their customers and the utilities that want to enable innovation.
(5) Start simple while ensuring economies of scale exist on a MW basis to attract broad participation. The pilot parameters should have the flexibility to progress to more complex scenarios as participation increases: the first thing you need for a successful virtual power plant, is actual assetenrollments from customers. Simplicity in all its form - a simple scope of services that the VPP could provide, and a simple process for quickly getting more kWs into an aggregated group that can become MWs - the faster customers will see bang for their buck and the grid will see a scalable, meaningful DER asset that does as well or better than conventional supply in a pinch. The reference to "more complex scenarios" means that in a future state where there are enough customers participating in any VPP product, LSEs will be able to expand the types of products they can enroll those customers in, potentially inviting more innovation from DER software providers and other aggregator entities that can partner with LSEs or approach customers directly to add value to DER contracts/offers.
- An embedded consideration in this discussion is that customer exports of DER energy are not "sales for resale" from customers directly to the ERCOT wholesale market - rather, customers are compensated by their LSE/REP for their excess generation under PURA 39.916(j). And in turn, REPs are not wholesale market participants like Generators, and the exports of their customers are settled (and paid for) as load-reducing (negative load) offsets. This means that under current law, neither energy customers nor their LSEs are subject to market rules and strictures of being wholesale power providers (or, "Power Generation Companies" in PUC TX lingo). As long as LSEs/REPs are the intermediary that allows for the transitional value between customers and the grid, that simplicity will enable quick scaling of customer participation without unnecessary regulatory headaches and red tape. LSEs/REPs may seek some guidance from the Commission that Ancillary services, sold back to ERCOT through their Customer DERS, can avail of similar treatment. Finally, a "more complex" future universe in which customers could be approached by any aggregator to sell their grid services (a party that is not the customer's LSE) could mean customers have to have some "wholesale" agreement in place to facilitate those sales ("Power Generation Company" type rules), or, these independent aggregators need to conform with REP-type laws so that customers experience the same protections and procedures they are used to getting from their REPs/LSEs.
The Public Utility Commission of Texas discussed this item at its July 14, 2022 Open Meeting, Item 16 - available to view at https://www.adminmonitor.com/tx/puct/open_meeting/20220714/