The Electric Reliability Council of Texas must massively expand its transmission capacity to move West Texas renewable power to load centers in the eastern half of the state by 2035, a move aimed at accommodating fossil-fuel generation retirements, but experts differ on whether the state government would approve such spending.
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ERCOT's Long-Term System Assessment, mandated to be presented to the state legislature every two years, shows that under various scenarios, locational marginal prices by 2035 could range from less than $82/MWh to more than $125/MWh. The range depends on how much generation transitions to renewable resources, what renewable mandates are established, and how much battery storage becomes available.
Posted on the ERCOT website on Dec. 23, the LTSA identified 16 high-voltage projects that potentially may be needed by 2030 and two more by 2035. All but four are in the eastern half of the state, with the remainder in far West Texas.
The projects have a total estimated breakeven cost of $13.8 billion, which ERCOT spokeswoman Leslie Sopko said Jan. 4 is "the amount of capital expenditure that the analysis indicates could be supported based on the current economic planning criteria."
In an email, Morris Greenberg, senior manager for North American power analytics at S&P Global Platts Analytics, said the estimated breakeven cost "represents the value of the upgrade (or what you would be willing to invest to build it).
"So, for example, taking the aggregate value $13 billion in the Current Trends case, this would produce levelized benefits of about $1 billion/year," Greenberg said. "If the projects cost that amount or less, you would build them."
Under a scenario with current trends – increased renewables, reduced fossil-fueled generation, continued moderate load growth – the 18 projects would save about $1.1 billion a year in production costs and $1.9 billion a year in congestion rent by the 2030 study year, according to the LTSA.
Jeff Schroeter, managing director of Genova Power Advisors, wondered whether the Public Utility Commission of Texas would approve such ambitious transmission expansion. He speculated in an email that the projects could collectively represent a "backdoor attempt at CREZ 2.0 for economic reasons to move energy."
Texas' Competitive Renewable Energy Zone, designed to bring 18.5 GW of wind generation from wind-rich West Texas to the load-heavy eastern half of the state, was completed in 2013 at a cost of about $7 billion. As of the end of November, ERCOT had more than 29 GW of wind capacity installed and operational or synchronized to the grid.
The CREZ projects were funded by charges to customers via a transmission and distribution rate adder.
Since those projects were built in 2013, the commission has primarily approved large transmission projects over reliability concerns rather than economics.
"I thought the PUCT was only approving investment for reliability reasons," Schroeter said in an email. "I've heard the commission had tired of [transmission and distribution service provider] rate increases about 5-7 years ago."
However, Greenberg said he thinks Texas leaders will act as necessary to resolve the constraints identified in the LTSA by 2030-35, if the upgrades "can improve reliability and reduce costs. Of course, the upgrades will also have to be included in future shorter-horizon transmission plans, and cost allocation will likely prove contentious," he said.
As evidence of Texas regulators' willingness to approve wires projects for economic purposes, Manan Ahuja, Platts Analytics, manager of North American power analytics, cited the PUCT's approval of transmission projects to reduce congestion to serve West Texas loads driven by expanding oil and gas exploration.
LTSA scenarios that depart from the "current trends" include a renewable mandate scenario, a high battery energy storage scenario and a high industrial load scenario.
The renewable mandate scenario assumes the extension of investment and production tax credits through 2035, a $40/ton carbon dioxide tax to start in 2021 and escalate thereafter, plus faster implementation of distributed solar systems.
The high battery storage scenario assumes "aggressive adoption of electric vehicles and low battery capital cost projections from the National Renewable energy Laboratory."
The high industrial load scenario assumes an increase in peak demand to 112.2 GW by 2035 compared with the current trends scenario's 2035 peak of 106.6 GW.
The LTSA projects that 21 GW of existing coal and gas generation would retire by 2035 in all scenarios, largely replaced by solar, wind and new gas generation, plus battery energy storage.
These various scenarios would have a wide-ranging effect on average locational marginal prices, according to the LTSA. By 2035, the current trends/high industrial load scenario would yield the least expensive power, less than $82/MWh, by 2035, while the renewable mandate would yield the most expensive, at more than $125/MWh.
"Rapid growth in solar and wind generation will result in many zero-priced hours," Platts Analytics' Greenberg said. "To justify the investment in new dispatchable (gas or storage) capacity in a market structure without capacity requirements and prices will require a significant number of hours with scarcity prices. So prices will be quite volatile with the need for new capacity limiting the downside for average prices."