Tuesday, January 22, 2019

Wind Nearing Coal as ERCOT Ponders Thinning Reserves

By Tom Kleckner

ERCOT enters 2018 facing new questions, as the growth in wind energy has begun threatening not only coal but also less efficient natural gas-fired generation.

In late November, the 155-MW Fluvanna Wind Energy Project in West Texas went online, pushing ERCOT’s wind power capacity past 20 GW. The milestone came a few weeks after the ISO approved the retirement of 2.4 GW of coal-fired generation, dropping its coal capacity to 15.1 GW in early 2018. (See ERCOT OKs Luminant Coal Retirements.)

Reserve Margin Reduced

ERCOT reserve margins wind energy

Garza | © RTO Insider

The retirements, along with those of several gas resources, has halved ERCOT’s planning reserve margin to 9.3% for summer 2018, leading Beth Garza, director of the ISO’s Independent Market Monitor, to proclaim an end to the “fat and happy times.”

“We’ve had really two years of clearly unsustainably low prices with high reserve margins,” Garza told the ERCOT Board of Directors in October. “We’re looking at a much different situation going into the summer of 2018.”

The Monitor says it hasn’t seen a summer with such tight reserve margins since 2007. “Will we see coal generators making profits that justify future investment?” asked IMM Deputy Director Steve Reedy during an October conference, noting the Monitor has seen more capacity on the ERCOT system than might be justified.

“If the load doesn’t rise fast enough to justify the generation, we expect to see retirements. So, we will see [in 2018] if retirements in the market work,” Reedy said.

ERCOT reserve margins wind energy

| Potomac Economics

After bottoming out in 2016 with the lowest real-time prices ($24.62/MWh) since the nodal market began operations in 2010, the ISO has seen prices increase to an average of $28.56/MWh through November. Still, that 16% increase lags the 28% rise in natural gas prices over the same period.

Solar, Wind Dominate Queue

All the while, wind and, increasingly, solar projects continue to flood the market. More than 29 GW of wind and almost 25 GW of solar are currently going through some form of study, accounting for the bulk of ERCOT’s latest generator interconnection status report.

Joshua Rhodes, a research fellow at the University of Texas’ Energy Institute, projects ERCOT’s wind capacity to reach 24.4 GW by the end of 2018. Given current capacity factors and coal retirements, that means wind will surpass coal as a fuel source for electricity by 2019. Coal generation has accounted for 32.2% of the ISO’s production this year, compared to wind’s 17.5%. Natural gas exceeds both, at 39%.

ERCOT reserve margins wind energy

| NextEra Energy Resources

So far, cheaper natural gas and wind have driven inefficient coal and gas plants out of the market.

“We haven’t had a true scarcity event in years, but if we have severe weather, we could have one,” said NRG Texas’ Bill Barnes, speaking on the same conference panel with Reedy. “That’s when we can all sit back and say, ‘Yes, that’s how it’s supposed to work.’ Or will there be temptation to intervene in the market?”

Market Rule Changes?

NRG Texas partnered with Calpine to sponsor a report of the ERCOT market, published in May. The report, coauthored by Harvard University’s William Hogan and FTI Consulting’s Susan Pope, recommends several market improvements, including adjusting the operating reserve demand curve (ORDC), adding local scarcity pricing and potentially implementing real-time co-optimization (RTC), to address intermittent renewables and improve incentives for generators. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)

The Public Utility Commission of Texas, which regulates ERCOT, has conducted a pair of workshops to discuss price-formation issues in the Texas grid operator’s energy-only market (project 47199). Stakeholders have suggested a wide range of market improvements, from adjusting reliability unit commitment (RUC) mitigation rules and instituting penalty curves for pricing constraints, to incorporating marginal losses’ costs into dispatch decisions and requiring locational reserve requirements.

The question of whether to defer market design changes until after the summer is yet another issue that must now be resolved.

The Monitor has called RTC the “most vital” market improvement. RTC is “foundational” to efficient pricing, it told the PUC, “especially in an energy-only market like ERCOT where participants rely on energy prices to facilitate short-term decisions to commit generation and long-term decisions to invest and retire.”

“The benefits of RTC would be substantial, as supported by the results seen by other [ISOs] where RTC is implemented,” the Monitor said.

ERCOT staff have been working on a study of the costs and time it would take to implement RTC or marginal losses in the wholesale market. A July report indicated it would take at least $40 million and four to five years to make the changes. A September report lowered those figures to at least $10 million and 18-24 months.

In December, the ISO filed a proposed plan to further assess the benefits of implementing RTC and marginal losses. Staff suggest using IMM software code to run a simulation of RTC in historical security constrained economic dispatch (SCED) cases to estimate the cost savings on an interval-by-interval basis, a process they expect to take six months.

ERCOT said introducing RTC into the market would provide additional flexibility in the real-time market in locating ancillary services, which would require modifying the RUC engine “to ensure a reliable operating plan.”

Staff predicted it would take about six months to complete a benefits assessment of marginal losses. ERCOT and the Monitor have promised another status update by the end of the first quarter.

New Loads, Oncor Deal

In the meantime, the PUC will hold a hearing Jan. 17-18 on Lubbock Power & Light’s proposed migration of 430 MW of load from SPP into ERCOT. The commission is also waiting on the results of a joint study on Rayburn County Electric Cooperative’s proposed transfer of another 150 MW of load from SPP to ERCOT.

In February, the PUC is scheduled to conduct a hearing on California-based Sempra Energy’s proposed $9.45 billion acquisition of Oncor and its bankrupt parent, Energy Future Holdings. Sempra and Oncor on Dec. 14 filed a settlement they had reached with key Texas stakeholder groups. (See Sempra, Oncor Reach Deal with Texas Stakeholders.)