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A wide swath of comments filed in the Texas PUC Staff’s March 16^th proposal and request for comments on the development of minimum transmission charge cost recovery evaluation.

Below are excerpts from comments filed.

Joint Comments of Google and Lancium – “As the Commission considers the adoption of a minimum transmission charge, Joint Commenters believe the Commission should consider the following:

• Term and Percentage: The term and percentage of minimum transmission charges should strike a reasonable balance: provide sufficient revenue guarantees to protect the system and existing consumers from initial capital risks, while avoiding overly punitive, long-term financial lock-ins. After the initial term, large load customers should transition to the standard system-wide cost allocation methodology based on their actual metered load. Joint Commenters have previously proposed a 50% minimum transmission charge over five years.
• Supporting Operational Security: Joint Commenters understand that the use of minimum demand charges will not obviate the need for an operating security. Joint Commenters believe that two years of transmission should adequately provide short term security for a single site in the event of default.
• The Need for Balanced Exit Options: Joint Commenter’s proposed Transmission Capacity Planning and Commitment Framework includes flexible exit options that hold other ratepayers harmless in the event a load needs to ramp down or shut down.1 As part of the adoption of a minimum transmission charge, the Commission should develop a stranded cost test requiring the interconnecting utility to evaluate if the transmission infrastructure can be utilized by other loads in the queue. To the extent that transmission will go unused, the large load shall be obligated to pay for the upgrades built to serve it. However, if those upgrades are deemed used and useful for other interconnecting loads, the remaining upgrade costs transition to those customers who can make use of the transmission service. Provided the protections and revenue guarantees remain intact without significant cost shifting, the load should be permitted to disconnect or ramp down without paying damages.
• Optimizing Demand Response: To prevent minimum transmission charges from inadvertently deterring demand response, the Commission should initiate a separate docket to evaluate market-based load-shifting tools that better align response signals with actual system needs.

Texas REP Coalition – “This proceeding should ensure that the overall cost allocation by class does not result in residential and small commercial customers being allocated more of these new transmission costs than is appropriate for their contribution to cost causation and utilization of the transmission system – in other words, it should be expected that the percentage allocated to smaller rate classes at the wholesale level in the future will be lower than has historically been the case given drivers of the current growth in transmission investment. Timing is also a concern. Investment in transmission expansion is already underway and will ultimately be recovered in rates through rate-making mechanisms that, if left unchanged, would not recognize the magnitude of large load until it actually came onto the system. The rate impacts to residential and small commercial customers cannot be managed if the underlying wholesale cost allocation is not reflective of these concerns. Therefore, it is important to have adequate security for large load interconnections, should they fail to materialize or under-materialize, as well as ensure that large loads are energizing in tandem with the infrastructure built to serve them.

To ensure adherence to these principles, the wholesale cost allocation methodology cannot be solely based on a limited coincident peak (CP) demand-based allocation that is a look-back of customer class demands. First, for some large loads whose requested demand is included in the transmission planning process and will take power from the transmission system but are either highly flexible to curtail load during the CP intervals or supplied energy during those intervals by generation behind the meter, their demand may never be included in a CP calculation even though they do utilize and rely upon the transmission system throughout the year. Further, if a limited CP methodology is maintained for all of the transmission cost allocated to these loads, the ability of these loads to intermittently rely on generation resources or controllable/flexible load to back off of demand during these peaks may have the same result.

With regard to understanding the potential rate impacts to residential and small commercial customers, there has been some discussion that residential customers may actually benefit because new transmission cost will be spread to larger billing determinants for new large load. The wholesale transmission cost allocation approved by the Commission should recognize that if the new large load is controllable/flexible, utilizes backup generation, or is co-located with existing or new dedicated generation, that load may not be included in the formula used to allocate the cost of those new lines. However, if new transmission is designed and built to serve the new load then the load drives transmission investment and benefits from the transmission grid at minimum in times when the load is not curtailing, utilizing backup generation, or the behind the meter generation is on outage or uneconomic. It is important that the cost allocation approach adopted by the Commission ensure that such loads bear some cost responsibility for their reliance on and use of the transmission system. The Texas REP Coalition supports that the proposal reflects these concerns in the wholesale cost allocation formula to the distribution utilities that provide retail electric delivery service to the large loads and will ultimately bill for these transmission costs. The retail cost rate design cannot properly protect residential and small commercial customers from having the percentage of their retail bills attributed to transmission cost continue to rise unless the wholesale transmission cost allocation is properly addressed.

One proposal that merits further analysis would require that large loads pay a portion of the requested interconnection demand rather than a look back on actual demand and a handful of CP intervals over the year. It is important that any change such as this or having a portion of transmission costs allocated on something other than a handful of historic CP demand intervals to the relevant customer classes, apply at the first step of wholesale transmission cost allocation. Texas REP Coalition respectfully requests that the wholesale cost allocation methodology be the focus of this proceeding.

“Accordingly, the Commission is correct in reviewing mechanisms that would potentially bifurcate the cost allocation among classes at the wholesale level to include allocation of a portion of the cost that is not based on a coincident peak methodology and includes some recognition of the transmission costs driven by the projected presence of large loads that benefit from the grid during off-peak conditions and that are driving investment decisions in transmission. Any intra-class allocation methodologies for retail rates should be addressed in separate proceedings.”

Texas Industrial Energy Consumers’ Comments – The Replacement for 4CP Must Reflect Cost-Causation – The “Draft Evaluation of Transmission Cost Recovery” (the “Draft Evaluation”) places undue, arbitrary emphasis on which allocation approaches benefit which customer classes without any nexus to underlying cost-causation. There is no discussion about the drivers of transmission investment today, how they have changed, or how the Commission can “more appropriately” allocate costs to reflect such drivers, as required by SB 6.1 Instead, the Draft Evaluation compares each group of consumers’ aggregate daily peak demand ( the 365CP ) to the total costs recovered from customers under the existing 4CP methodology and observes that there is a “misalignment.”2 This incorrectly presumes that daily/365CP reflects the type of demand that contributes to transmission needs, even when it is 20% or more below absolute annual system peaks. This is like comparing apples to oranges and then concluding that apples should be “more orange.”

“A transmission cost allocation “snapshot” that considers DSP demand during four to six CPs, including a winter data point, likely strikes the right balance and tracks cost causation. As the Draft Evaluation and TIEC’ s independent analysis both verify, the CPs in June, July, August, and September have consistently been above 95% of the single annual CP. In addition, in recent years, there has been one CP in either December, January, or February above 90% of the highest yearly CP.4 Based on this data, a 5CP methodology (4CP + floating winter peak) or 6CP methodology (4CP + floating winter peak + floating summer peak) would reasonably expand the number of CPs to limit excessive avoidance behavior, but without compromising cost causation. Additionally, to make it more challenging for loads to “misrepresent” their use of the transmission system by selectively curtailing, the Commission could consider broadening the snapshot from 15- minutes to 30-minutes. To avoid the 15-minute 4CP intervals today, a load must curtail for multiple hours for many days in the summer . As a result , lengthening the intervals and adding additional CPs will likely make complete avoidance significantly more costly and difficult. This, combined with the minimum transmission proposal described below, will provide a targeted solution to the issues the Commission and the Legislature seek to address while limiting collateral damage to high load factor manufacturing businesses, who continue to pay full freight transmission on 90%+ of their non-coincident peak (NCP) demand.”

“A Minimum Transmission Rate Would Protect other Customers (Large and Small) from Undue Cost-Shifting – TIEC recognizes that the Commission is under immense pressure from the Legislature to ensure that transmission development to serve projected growth in data centers does not increase costs for residential customers and small businesses.5 TIEC notes that these concerns apply equally to existing industrial businesses, who provide important contributions to tax base, employment, and the overall state economy. At the same time, there is a desire by the Legislature to ensure requirements on data centers will not stop traditional businesses from siting in Texas.

These issues cannot all be addressed through changes to wholesale transmission allocation. In addition to adding CPs and broadening the “snapshot,” as described above, a targeted solution that balances these conflicting goals is to adopt a “take-or-pay” or “minimum demand charge” for new “very” large load exceeding a certain size threshold. Under this framework, very large loads (TIEC suggests 250 MW or greater) would be required to enter into take-or-pay contracts as a condition of receiving the requested interconnection capacity. Customers would commit to a minimum demand charge based on a percentage of the grid capacity available to them – whether they actually use it or not-and would begin paying the minimum charge as soon as the interconnection capacity is available.

“This targeted approach will solve several issues” without divorcing wholesale cost allocation from cost-causation. First, it would close the potential timing gap between interconnection capacity being made available to a very large load, and when the load has fully ramped up to use and pay for that capacity. An interconnection must be built to serve the ultimate total demand at a new site, and while a customer is ramping up operations over a number of years, other loads may have to subsidize the costs of system upgrades. Requiring a very large load to pay for the capacity as soon as it is available, rather than when the customer’s ultimate ramp is achieved, will close this gap. Second, this approach will prevent complete avoidance by any new loads who can substantially curtail their load or who have on-site generation to serve their full demand. This should obviate the need to dramatically deviate from a reasonable wholesale transmission allocation in an effort to “catch” loads in off-peak usage periods. TIEC believes that the minimum rate should be set at 75-80% of the available interconnection to reflect that a customer’ s maximum NCP for purposes of transmission modeling is rarely achieved by a customer of any size, yet the system must still be sized to maintain reliability during such conditions. This is true for all customers and should be reflected by some percentage below NCP.”

Retail Electric Providers for Affordable, Innovative Rates (REPAIR) – “REPAIR is motivated by the Staff Report’ s conclusion that even a move to the farthest bookend considered in the Report, 12 Coincident Peak (“12CP”), would cause a meaningful but still relatively small reduction in the transmission costs paid by residential customers, versus commercial and industrial classes (“C&I”). We calculate the magnitude ofthis reduction, using the residential customer percentage cost allocation change results of the staff linear linear regression analysis along with 2025 TCOS rates, peak loads, and residential meter data, at $16.73 per residential customer in competitive territory annually, with lesser-reaching reforms , such as 6CP , increasing costs by $ 4 . 82 . We believe that a change to the allocative factors from 4CP to 12CP can be an important step toward fairness for residential customers like those we serve, but it should be complemented by policies that allow residential customers to engage in the same kind of demand response that larger customers and Non-Opt-In Entities (“NOIEs”) do. We estimate that such a reform, whether they were responding to 4CP or 12CP, would return more than $250 per residential customer annually.

As the Staff Report notes, when Texas first adopted the transmission ratemaking methodology it continues to this day, smaller customer classes had no exposure to demand-based transmission pricing because of technological barriers-namely, the lack of smart meter technology. 2 That barrier no longer exists and, as the Staff Report implies, it is time for a “rate design approach” that “ensure[sl that rates [arel as cost-responsive as the available metering technology allow[ s].”3

Notably, other markets expose Retail Electric Providers to demand-based cost allocation for their customers’ transmission usage. 4 These markets essentially cause the same signal that C&I customers face to be replicated for residential customers, but add retailers as an intermediating function, to prevent residential customers from directly facing demand charges. If adopted in Texas, such a reform would create an equal playing field between residential customers in the ERCOT REP market and C&I customers.

To put the opportunity in clear terms, if a C&I customer reduces one megawatt of demand across demand intervals today, that load will save $68,550. If a REP, on behalf of its residential customers, does the same-through smart thermostats, batteries, or time-of-use pricing-it will save only $94.5 That is not a typographical error. There is a 727:1 disproportionate benefit to C & I customers undertaking the same action as residential customers . Unfortunately , the changes the Staff Report contemplates would do nothing to reform this structural disparity in the ability to respond to demand-based price signals.

Although much of the discussion in this proceeding has concerned the disparity between C&I and residential customers, it is worth noting that there exist massive disparities even among residential customers in ERCOT. Like C&I customers, municipal and member-owned electric co-operatives (NOIEs) face demand-based transmission-cost exposure directly and, in their case, for all their customers in aggregate. NOIEs have invested in demand response accordingly. CPS Energy’ s SmartHours and Energy Saver programs have enrolled over 180,000 residential customers with approximately 184 MW of demand response capability. Austin Energy’ s Power Partner program has enrolled more than 60,000 customers with approximately 45 MW in demand reductions. Together, these programs conservatively generate approximately $3. 1 million per year in estimated transmission-cost savings. 6

Comparable programs in REP territory are relatively undersubscribed because REPs are not exposed to transmission retail rates that provide a financial incentive to build equivalent demand response capabilities. According to ERCOT data, among residential customers, in NOIE territory 44.6% are enrolled in demand response programs, whereas in REP territory only 10.1% are enrolled. 7 This is not a difference in technology access, customer sophistication, or program design capability. It is a difference in incentives.

To correct these inequities in Texas’ s retail market design-both between residential and C&I customers, and among residential customers-REPAIR proposes a straightforward remedy: During the annual update to Distribution Service Provider allocation-factor values proposed in the Staff Report’s Recommendation No. 5, allow REPs to opt into demand-based transmission charges, rather than being subjected to non-demand-based transmission rates. This election would be compatible with whatever demand-based value the Commission chooses to succeed 4CP in this proceeding.

Under this approach, a REP opting into this demand-based treatment would receive invoices for transmission charges consistent with those received by C&I customers that are exposed to demand based charges. This proposal allows REPs like ours the opportunity to act on behalf of our customers in the same way that C&I customers and their REPs and advisory services do. Importantly, the proposal is revenue-neutral for distribution and transmission service providers. Mechanically, it would work in tandem with the annual allocation update that the Staff Report identifies for comment, dovetailing with the regulatory process. There are a variety of permutations to this approach, tailored to scenarios that commonly present in the retail electricity market in Texas (such as how to incorporate the book in a REP acquisition) but all of these point in the same direction of giving customers on an opt-in basis exposure to demand charges that empower them to respond to that price signal on an equivalent basis to larger customers and NOIEs. We describe this proposal further herein.”

Vistra Comments – “The four coincident peak methodology (4CP) is a cost-allocation mechanism used to recover cost for the transmission system that is built to reliably transmit power from generators across the bulk power system to distribution service providers (DSPs) and ultimately to end use customers. This approach to cost allocation, as Staff’ s report thoroughly documents, has historical roots in cost causation principles at the time of industry restructuring and the introduction of competitive markets in the late 1990s, reflecting the metering technologies and policies driving transmission planning and operations at the time. In the three decades since, many policies and market dynamics have evolved but the cost allocation mechanism has not. SB6 has mandated that the cost allocation mechanism be reviewed and modified as necessary to reflect the state of the grid today. Vistra reiterates its overall support for a transmission cost allocation methodology that (1) is fair to all customers; and (2) minimizes any interference with the ERCOT wholesale market.

As Vistra has noted in prior comments in this project, the 4CP cost allocation mechanism has had limited-at-best impacts on reducing the need for new transmission infrastructure but has long been identified as a source of distortion in the ERCOT wholesale market. The latter point is of particular concern, because the ERCOT wholesale electricity market has historically been and currently remains an “energy-only” market structure, meaning that it depends critically upon Realtime energy scarcity price signals to inform forward pricing expectations, which in turn drive investment and retirement decisions for generation resources. Therefore, when non-market incentives drive behavioral changes, such as the “conservation and demand response price signal” that Staff’ s report identifies as a “pro” associated with the 4CP mechanism, the hidden cost is the lost investment signal for generation resources and, in turn, greater resource adequacy risks that are borne by all customers (not just the ones responding to 4CP signals). Therefore, while recognizing and appreciating that Staff’s report dedicates significant discussion to this distortive effect and appropriately highlights concerns with it,1 Vistra does disagree with the inclusion of 4CP’s demand response signal as a “Pro” in that list, lest it confuse readers that the negative effects on resource adequacy can be disentangled.

Second, Vistra notes the novel term “transmission scarcity” in Staff’s report, which is not a defined term in the ERCOT market, but is asserted to have “recently occurred during winter season peak periods.” There are many lenses that can be applied to that term (e.g., observation of higher peak loads outside of summer peaks, frequency of transmission emergencies, identification of regions with rapid electrical load growth under PLJRA §§ 39.166-167, delays in large load interconnection plans, power flow and transmission line loading indicators, congestion rent or auction revenues for congestion rent, operational constraints, transmission projects under review by ERCOT stakeholders for reliability or economic justifications, CCN applications before the Commission, Commission direction to construct transmission under PURA § 35.005, etc.). Vistra recommends the Commission more clearly define the term “transmission scarcity” if that concept is intended to help drive cost allocation policy.

“That being said, Vistra continues to recommend that the Commission reject “net peak load” as a potential metric of “transmission scarcity.” In Vistra’s analysis of transmission system utilization between peak load and peak net-load, Vistra’s observation is that transmission system utilization is consistently higher during peak load vs. peak net-load. That is, the transmission system, with a few exceptions of times when the peak load and peak net-load is at the same time, is more used when load is at the highest, not when load is highest relative to a specific class of generation resources. That supports the current tenet in the transmission cost allocation methodology to base it off the peak load interval vs. a methodology that uses net-load peaks. However, as discussed above, coincident peak and net peak are not the only two potential metrics of “transmission scarcity.”

AEP Comments – Re: Retail Transmission Cost Recovery – “The AEP Companies support requiring the requesting customer to bear the cost of those upgrades that only benefit that customer. Ensuring that the costs of customer-specific infrastructure are appropriately assigned to the customer requesting service helps maintain equitable cost allocation and protects existing customers from bearing costs that do not provide them with a direct system benefit.

“At the same time, the AEP Companies recognize that large load customers can provide significant economic benefits to local communities and the broader regional economy. Large industrial facilities, data centers, and other high-load customers often generate substantial investment, employment opportunities, and tax-base expansion, producing economic spillover effects. In certain circumstances, these broader economic benefits may justify the use of cost allowances or similar mechanisms to facilitate development. The balance of economic development incentives to support various industry types of load for the state are a necessity.”

Read all filed comments here.