The Electric Reliability Council of Texas (ERCOT) on April 30 updated its summer 2018 planning reserve margin to 11% based on resource updates, but it warned that the regional grid serving most of Texas could still suffer rotating outages under extreme conditions.

In its final Seasonal Assessment of Resource Adequacy (SARA) report for the upcoming summer season, which spans June to September, the grid entity said it expects to have sufficient generation—78,184 MW—to meet a summer peak load forecast of 72,756 MW based on “normal weather conditions.” That forecast, it noted however, is expected to soar 1,600 MW higher than the all-time peak demand record set in August 2016.

The projected reserve margin is below ERCOT’s target of 13.75%. Still, the report presents a more optimistic assessment of ERCOT’s total generation resources than it predicted in its preliminary summer seasonal assessment of resource adequacy (SARA) report released in March. The preliminary report projected a higher summer peak load forecast of 72,974 MW, which ERCOT anticipated it would barely meet with a total resource capacity of 77,658 MW.

The non-profit wholesale markets operator serving 90% of Texas on Monday said that since March, its total generation resource capacity has increased by 525 MW. The increase is due primarily to the change in status of a 300-MW mothballed unit from unavailable to available for the summer season, and a 226-MW gas-fired power plant that will come online earlier than planned in mid-June. A formerly unavailable Switchable Generation Resource worth 54.6 MW will also become available to the ERCOT grid. The change in total capacity factors in minor decreases in capacity contributions from a private use network and in-service date postponement of a small gas-fired unit to fall 2018.

Planned additions for the summer now total 728 MW—345 MW of thermal sources and 383 MW of renewables based on the expected summer peak capacity contributions, ERCOT said. The final summer unit outage forecast of 4,349 MW remains unchanged from the preliminary SARA report.

Risk of Rotating Outages Pervades

In an afternoon call with reporters on Monday, ERCOT Manager of Resource Adequacy Pete Warnken said that the additional capacity slightly improves the tight market conditions. But, he warned, “As our SARA indicates, we do have some scenarios where if we have a combination of extreme system conditions, then there is a possibility that we may have what are called ‘rotating outages’.”

The SARA outlines five potential risk scenarios. The first is modeled on extreme weather conditions based on a long heat wave and devastating drought during the summer of 2011, an event that forced the grid operator to cut power to large industrial users to avoid rolling blackouts. An extreme summer forecast could boost summer demand to 75,958 MW, outstripping available generation resources. The other scenarios anticipate maintenance outages, forced outages, and low wind output.

“Since we do have more resources, that risk is probably reduced a little bit. But again, really, the focus for ERCOT is to make sure that we can quickly respond to those situations—and appropriately—to any type of change in system condition,” Warnken said.

ERCOT has been preparing for tight operating reserves owing to a spate of recent plant retirements—including of major coal baseload generators—and delays in some planned resources.

Considering its limited reserves, ERCOT said in its final SARA report that it is prepared to meet the anticipated record demand with ancillary services and contracted emergency response service capacity. “ERCOT may also request that Transmission and/or Distribution Service Providers (TDSPs) implement load control measures established through Standard Offer contracts with their customers.”

Based on the December 2017 Capacity, Demand and Reserves (CDR) report, about 2,300 MW of such additional capacity is available to ERCOT for addressing reserve deficiency situations, the SARA notes. It adds: “ERCOT also anticipates further voluntary load reductions and an increase in power sold in the market by industrial facilities in response to higher power prices during peak demand.”

An Enduring Problem

On Monday, ERCOT also released its May CDR report, the latest installment  of the grid operator’s biannual effort to provide insight into planning reserve margins for the next five years (through 2022). That report is also more optimistic than the December CDR, but it still projects that reserve margins—which is calculated as the difference between total resources and firm load forecast divided by firm load forecast—will fall below the 13.75% target.

Reserve margins for summer 2019 will fall to 11% (compared to 11.7% in the December CDR), increase to 12.3% by 2020, but dwindle through 2021 at 12% and 2022 at 10.9%. In 2023, the reserve margin will plunge to a scarce 8.9%.

In 2017, by comparison, ERCOT had a reserve margin of 16.9%. That was a significant improvement from dismal reserve margin projections from only six years ago, when ERCOT declared several emergencies to reduce electric demand, and stricken with capacity shortages, forecast a negative margin by 2022.

According to ERCOT, the May CDR lowers the 2019 summer demand forecast to 74,202 MW due to a delay in a new industrial facility located on the Texas coast. Meanwhile, it adjusts peak demand forecast upward starting in 2021 to reflect the planned integration of Lubbock Power & Light customers.

A New Target Focus

The grid entity, which has neither a capacity market nor a requirement that generators build or purchase reserve capacity to meet unexpected supply shortages, has since its supply crisis in 2011 taken a number of price-related actions to encourage investment in generation. A number of gas-fired, wind, and solar power projects will come online through 2023, the May CDR report says.

On Monday, ERCOT Senior Director of System Operations Dan Woodfin told reporters that the grid entity expects the market to respond to scarcity conditions. “It’s a good bet to expect that [generators] will be looking at summer conditions and then make decisions appropriately,” he said. “If they expect higher prices due to those scarcity conditions, and it’s within their economic and financial decisions, then they’ll bring those resources on.”

Meanwhile, ERCOT is also mulling shifting its focus away from its reserve margin target of 13.75%, which Woodfin noted was a “physical reliability–based measure” to one based on “the economics of meeting a certain level of reliability.”

The new “economically optimum reserve margin” will explore the balance between what is needed to maintain reliability and costs necessary to maintain that reliability. “We’re doing a study this summer, and we’re going to be publishing the results toward the end of this year,” Woodfin said.

Market Design Changes on the Horizon

ERCOT, whose wholesale market  was created as the Texas Legislature restructured the state’s electric market in 1999, in an April 2018–released report noted that it continued to meet the power needs of about 24 million Texans within its region despite “rapid growth and change for electric markets” over 2017.


Though other U.S. electric markets suffered lax demand growth over 2017, new Texas businesses and residents drove electricity demand records in ERCOT. The independent system operator set a new winter peak demand record in January 2017 and new monthly demand records throughout the year.

Demand is expected to ramp up owing to planned industrial facility additions, including the Freeport Liquefied Natural Gas facility. The master plan for that project, endorsed by the ERCOT board last December, indicates a peak demand boost from 800 MW in the region to 2,300 MW by 2022. Neighboring utilities like Lubbock Power and Light and Rayburn Country Electric Cooperative (LP&L) are also working with Texas regulators to move a portion of their loads into ERCOT.  LP&L’s move, approved in early 2018, could occur by 2021.

Demand growth in ERCOT. Annual energy and peak demand in ERCOT has soared over the last decade. Courtesy: ERCOT
Demand growth in ERCOT. Annual energy and peak demand in ERCOT has soared over the last decade. Courtesy: ERCOT

On the supply side, however, the grid entity lost more than 5,100 MW in 2017 owing to the exit of several fossil fuel powered units, which couldn’t compete in ERCOT’s low wholesale price environment. A new Public Utilities Commission (PUC) of Texas requires that as of January 1, 2018, generators must notify ERCOT of plans to retire units at least 150 days—not 90 days, as previously required—in advance of closure.

Meanwhile, ERCOT has also seen a proliferation of wind and solar resources. On October 27, 2017, (at 4 a.m.), for example, wind generation provided 54% of ERCOT’s power, and wind set an instantaneous wind output record of 16,141 MW on March 31, 2017 (at 8:56 p.m.). “As wind power continues to increase in Texas, ERCOT is working collaboratively with other grid operators and utilities to reliably integrate this generation,” it said. ERCOT has also added a reliability risk desk to closely monitor and respond to wind and solar forecast errors, net load ramps, and inertia levels, and ancillary service needs.

Interconnection requests reached historic levels in 2017 with nearly 200 requests. Utility-scale solar projects accounted for 56% of those requests.

For now, the grid entity expects to see planning reserve margins fluctuate owing to unit retirements, new investment, and new resources coming online, Woodfin noted.

However, a number of proposed market design changes are also underway to ensure pricing mechanisms are in place to reflect appropriate economic outcomes in the wholesale market, making sure that prices reflect those appropriate economic outcomes when we get into scarcity,” he said.

At the direction of the PUC  last year, ERCOT assessed the cost and time to implement real-time co-optimization (RTC)—a process of procuring energy and ancillary services simultaneously in the real-time market—and marginal line losses. ERCOT estimated that it would cost about $40 million and take four to five years to implement RTC, and about $10 million and up to two years to move forward with marginal losses. ERCOT is preparing to report to the PUC on these changes in mid-2018.

As significantly, the PUC in early 2018 approved the removal of ERCOT’s reliance on reliability unit commitment resources—including reliability must-run units—from online capacity considered when calculating operating reserve demand curve price adders. ERCOT is preparing to implement that mechanism to “make sure that the prices reflect scarcity conditions,” by this June, Woodfin said.


—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)