Texas regulators exercised their newfound regulatory authorities Thursday in bypassing ERCOT’s stakeholder process and directing three utilities to add a second 345-kV circuit to an existing transmission line in the frequently constrained Rio Grande Valley.

Citing the its “broad, statutory authority to order construction that ensures safe and reliable power,” the Public Utility Commission ordered AEP Texas (NASDAQ:AEP), South Texas Electric Cooperative (STEC), Sharyland Utilities and Electric Transmission Texas (ETT) to add a second circuit to their portions of the 385-mile line that circles the region.

Utility representatives said it will take almost three years to add the second circuit. Given the commission’s demand for an accelerated timetable, the project will still be completed before ERCOT’s planned construction of a new 345-kV line in the Valley. The grid operator is recommending the project, which has a $1.28 billion price tag, and plans to get board approval before the year is up. (See ERCOT Finds 345-kV Solution for Valley Constraints.)

Woody Rickerson, ERCOT vice president of grid planning and operations, said the greenfield project will meet future load growth and generation development through 2040 and address reliability and stability constraints. Seven of ERCOT’s 16 generic transmission constraints are in the Valley, which sits at the edge of the Texas Interconnection with limited long-distance transmission circuits.

Adding a second circuit and new facilities to close the loop on an existing 345-kV line from San Miguel down to North Edinburg and then over to Palmito will wring an additional 300 MW of capacity for the region, where the gird operator has been having trouble keeping up with load growth.

“We don’t want to see anything delay” the project, Rickerson said. It “would get us out of this just-in-time [cycle] … and would be a step change from what we’ve done in the past. This is a kickstart all the way to 2040.”

Commissioner Will McAdams compared the project’s cost to the multibillion-dollar 345-kV Competitive Renewable Energy Zone in West Texas that connected renewable resources to the state’s urban population centers.

However, adding the second circuit will still cost up to $500 million, according to the utilities’ projections. Sharyland estimates it will cost $106 million to $128 million for its 47-mile portion and to close the loop, while STEC forecasted it will spend $31.8 million to add to its 42 miles.

ETT, a joint venture between AEP and Berkshire Hathaway Energy subsidiaries, said its portion will run from $311 million to $350 million and that AEP’s facilities will cost $28.9 million.

As the commissioners struggled to understand the short-term project’s costs, AEP Texas Project Manager Wayman Smith explained that while the original line was double-circuit-capable, the towers did not have arms on both sides. He said additional structures also have to be added when the line makes a severe turn, as the turn can’t be made with circuits on both sides of the tower.

Smith said some 70 miles of its lines already have conductors hanging and arms because they were used to interconnect three different wind farms.

“We’re not going to put the Valley at risk,” Smith said. “That has put us in a bind, because now we have infrastructure that should have been built with two circuits from the beginning.”

Commissioner Lori Cobos said the utilities will still be expected to meet regulations’ ratemaking principles and standards. “This is not a blank check.”

Offer Cap Could be Halved

The PUC has given ERCOT stakeholders until Thursday to file comments on whether halving the $9,000/MWh high systemwide offer cap (HCAP) to $4,500/MWh is an “appropriate level” and whether the change will have any consequences on the value of lost load, currently set at the HCAP when the latter is in effect (52631).

McAdams, who filed a memo suggesting the action, said he did so in the “interest of market certainty” and to “assuage consumer concerns” by putting in place safeguards that market participants and residential consumers can rely on as ERCOT, hoping to avoid a repeat of February’s devastating storm, heads into the winter months.

Last winter’s storm “was traumatizing. We recognize that,” McAdams said. “The next winter after [it] will be remembered by consumers of all classes.”

The comment period would begin a process that could have a new HCAP in place by December. The commission could also take up the issue during its next market redesign work session on Oct. 14.

“This isn’t market redesign. This is market design,” McAdams said.

The HCAP is currently set by rule at $2,000 after it remained at $9,000 for too many consecutive hours during the storm as ERCOT battled to meet demand with about half of its available generation. That resulted in about $50 billion in market transactions during the week of the storm, sending several retailers and one cooperative into bankruptcy. The cap is set to revert back to $9,000/kWh on Jan. 1.

In ERCOT’s energy-only market, the price cap is designed to incent generators to produce power during scarcity conditions. While reducing the cap would cut into generators’ profits, Stoic Energy’s Doug Lewin, a consultant for 16 years in the market, said even they have filed comments urging the cap be reduced.

“This is the one thing that is almost certain to happen,” he told RTO Insider. “I think politically, it has to happen.”

McAdams has also suggested opening a rulemaking to decouple demand response resources from the emergency energy alert levels, identify a more conservative trigger for deploying emergency response service (ERS) resources and consider raising the ERS resources’ spending limit from the current $50 million.

PUC Chair Peter Lake said the commission will consider and take action on the feedback it has gathered in recent months on proposed changes to the operating reserve demand curve, ancillary services and other market features.

“We run the risk of putting Band-Aids on bullet holes,” he said. “The legislature has asked us to look at ancillary services and new products, but also to ensure broader reliability in the marketplace. I’m asking the stakeholder community to think about the kind of substantial changes to the ERCOT market’s normal functions … that will ensure the resources and economics of the ERCOT model go to generating resources that provide reliable power in any form or fashion.”

Debt Securitization on the Calendar

The commission said it will take up an order securitizing debt from the winter storm following an unopposed settlement in one of two related dockets.

Vistra’s Amanda Frazier said during last week’s Gulf Coast Power Association’s Fall Conference that parties to ERCOT’s request for a debt-obligation order to finance $2.1 billion in market debt have filed a settlement. She said the agreement addresses three key issues: the methodology and allocation of securitization proceeds among load-serving entities; how LSEs would document their exposure; and establishing opt-out provisions for municipalities and cooperatives (52322).

“We put a lot of work into the agreement. PUC staff really helped drive that outcome,” Frazier said.

McAdams said it would be prudent to give staff additional time to cover the agreement’s finer points and issues before issuing a final order. Staff has also scheduled time next week for the commissioners to discuss the settlement.

The second securitization docket proposes to finance $800 million to replenish ERCOT funds used to reduce short pays to the market (52321). As of Sept. 1, the market was still short almost $3 billion.

ERCOT filed its debt-obligation requests in August, and a three-day hearing was held earlier this month. (See “Securitization Hearings Conclude,” PUC Workshop Takes First Stab at Market Changes.)

PUC to Intervene in ANOPR

Following staff’s recommendation, the commission will intervene in FERC’s Advanced Notice of Proposed Rulemaking to reconsider its regulations on regional transmission planning, cost allocation and generator interconnection processes (RM21-17). (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

ERCOT is not within FERC’s jurisdiction and serves about 90% of Texas’ load. MISO, SPP and WECC all oversee portions of the remainder.

Noting MISO is currently working on long-term transmission-planning issues and cost-allocation measures, Cobos, who represents the PUC on the Organization of MISO States, said, “I think it’s important we get involved in these issues at the federal level.

“We do need transmission to ensure reliability in those areas of the state that are not within ERCOT,” Cobos said. “Those are very important areas of the state as well, and we need to make sure those ratepayers are not being allocating costs for other parts of those ISOs and RTOs that they’re not getting benefit from.”

Staff proposed the commission intervene in the FERC docket, direct them and outside counsel to monitor the proceeding, and participate in relevant discussions with SPP and MISO state regulators (41211).

“These regions, they’re not easy games to play in,” Commissioner Jimmy Glotfelty said. “Us getting in there and building relationships — getting them to understand what we want and what we need — is important.”

In other actions, the PUC:

• • • extended through May 2022 ERCOT’s requirement to make public generator forced and maintenance-level outages and derates within three operating days. Existing protocols have kept that information confidential until 60 days after the operating day. The commission in June ordered the grid operator to report that information after an above-normal number of outages forced a conservation call. The grid operator is working on a pair of protocol changes that will set up timely automated public reporting of outages (52266).
    • gave Executive Director Thomas Gleeson authority to solicit nominees to the Texas Energy Reliability Council, recently created by legislation. The council will be responsible for ensuring that Texas’ electric and energy industries meet “high-priority human needs,” address “critical infrastructure concerns” and improve their coordination and communication. It will comprise eight members, five of which will individually represent dispatchable power entities, transmission and distribution utilities, retail electric providers, municipalities and cooperatives. Three others will speak for energy sectors not otherwise represented (52557).