The Texas power market is in turmoil
Announced coal plant retirements are prompting calls for market reforms and hopes for higher power prices, but many elements must come into play before either of those scenarios can unfold. Meanwhile, there has been some merger and acquisition activity as generators reshuffle their portfolios to adapt to — and possibly influence — market conditions.
Some of the capacity slated for retirement will be replaced by new generating facilities, but companies are finding it cheaper to buy generation than to build it.
Some 5,625 MW of fossil fuel capacity is slated to be retired or mothballed in the coming year.
That has already raised concerns. Potomac Economics, the independent market monitor for the Electric Reliability Council of Texas (ERCOT), said in October the retirements could push the reserve margin below ERCOT's target of 13.75%.
Unlike other organized power markets, ERCOT does not have a capacity market to incentivize new generation. Instead, it relies on energy prices to provide price signals to keep supply and demand in balance.
Around 2011, the ERCOT market tightened to the point where there was a debate about implementing a capacity market, but that never came to pass. The state’s legislature did not act, nor did the Public Utility Commission, though the regulator did raise the cap on power prices, which now stands at $9,000/MWh.
Twice a year ERCOT issues a Capacity Demand and Reserves (CDR) report that projects reserve margins. The 2017 CDR shows the reserve margin north of 18% until 2022 when it falls to 16.8%. But the current CDR was completed in May, before the recently announced coal retirements. ERCOT stakeholders are now awaiting the updated CDR, which is due out in December.
The PUC is also working on revising the methodology it uses to formulate its Economically Optimum Reserve Margin (EORM), but that work is not scheduled to be completed until the third quarter of 2018.
ERCOT’s reserve margin projections have fallen into single digits 10 times in the last 10 years, but it has always bounced back. The recent low was in 2012 when the CDR projected a 2017 reserve margin of 5.8%. Subsequent CDR projections have risen steadily, from 10.5% for 2013 to 18.2% for 2017. “It fluctuates,” ERCOT spokeswoman Robbie Searcy told Utility Dive.
ERCOT also issues a shorter-term estimate of capacity adequacy, the Seasonal Assessment of Resource Adequacy. The winter SARA, released Nov. 1, included the removal of 3,551 MW of the recently announced retirements, including 1,200 MW of capacity still under review to determine if they are needed for system reliability.
“Given these capacity reductions, ERCOT still expects to have sufficient systemwide operating reserves for the winter season,” Pete Warnken, ERCOT’s manager of resource adequacy, said in a statement. “Our studies show this would be the case even with a much higher-than-expected peak demand.”
The only energy-only market
While ERCOT’s reserve margin is closely watched, in an energy-only market, generators make money on price spikes. But despite hitting new peak load records every year, power prices have not moved up significantly. ERCOT’s wholesale power prices have dropped to around $25/MWh from a high of $49.30/MWh in November 2014.
Texas had a cool summer, but ERCOT hit new monthly demand peaks in both July and August. Nonetheless, prices remained stable, Searcy said.
However, recent retirement announcements may deliver the relief from low prices that generators are seeking. Newly formed Vistra Energy announced plans to close its 1,800 MW Monticello plant on Oct. 6 and then surprised the market on Oct. 13 when it said it also plans to close its 1,100 MW Sandow and 1,200 MW Big Brown coal plants early next year.
In an Oct. 16 note, Neel Mitra, an analyst at the investment advisory firm Tudor Pickering Holt, said the retirements would cause reserve margins to tighten, but “it remains to be seen if on-peak forwards will sustainably rise in response.”
On Oct. 13, the 2018 on-peak power price for the North Texas zone rose to $34.50/MWh. The forward price at the beginning of the month was $30.10/MWh.
While on-peak forward prices for 2018 and 2019 in both ERCOT’s North and Houston zones responded to Vistra’s announcements with higher prices, “they’re back to where they were three months ago,” Mitra said.
Vistra’s announcement raises two immediate questions. First, will ERCOT allow the retirements?
ERCOT already has approved the Monticello retirement and says its review of Sandow and Big Brown will be completed by mid-December. If ERCOT deems the plants are needed for reliability, it would make them eligible for reliability must run (RMR) contracts.
“We do not believe an RMR will be put on any of the three coal plants because none of these plants are near load centers, and there are numerous [combined-cycle gas turbines] in the supply stack that can run harder,” Mitra wrote in June.
The other question is whether or not there will be more coal plant retirements in ERCOT. That is difficult to determine, Mitra said. “We believe the only way to tell is to wait until next summer or a weather event to see if there is any material increase in scarcity pricing.”
For now, many generators in ERCOT continue to struggle, and not just coal generators. In March, media reports said that ExGen Texas Power, an Exelon affiliate with five gas-fired plants in ERCOT totaling 3,500 MW, was considering a sale of its Texas assets. Moody’s Investors Service, in a report issued later that month, said ExGen has a “high default probability within the next 12 months.” The report cited, among other factors, ExGen’s “weakly competitive portfolio given new entrants” and refinancing risk “owing to the volatile and unpredictable merchant energy market in ERCOT.”
In a Nov. 2 report on market dynamics for unregulated generators, Moody’s noted that while power prices received a boost from Vistra’ announcement, prices remain “susceptible to pressure from the growing supply of low-cost renewable resources.” The report noted that wind power capacity has grown rapidly, from 15,764 MW at the end of 2015 to 19,000 MW currently.
Wind also continues to provide a growing share of ERCOT’s power production. A recent report from Joshua Rhodes, a research fellow at the University of Texas Austin’s Energy Institute, said that the output from wind turbines could soon overtake coal output.
Overall, ERCOT reports wind power production in 2016 accounted for about 15% of the power supplied compared with about 12% in 2015 and less than 1% in 2003. Moody’s said that trend would continue to put downward pressure on power prices.
ERCOT also expects another 2,230 MW of new capacity will be added by winter, including 709 MW of gas-fired generation, 1,313 MW of wind capacity and 208 MW of grid-scale solar capacity.
Not by wind alone
But wind isn’t coal’s main problem. For the most part, the plants slated for retirement already have low capacity factors; they mostly serve seasonal peaks. Wind plants, on the other hand, tend to produce power at off-peak hours. Given the large number of wind plants due to come online, Mitra says the coming coal retirements are unlikely to raise off-peak prices. Wind plants sometimes do run through on-peak hours, which has contributed to lower peak prices, but the bigger issue, he said, has been “large industrial customers adopting demand response/price conversation measures to avoid high transmission charges.”
Mitra ascribes Vistra’s plans to close its Sandow coal plant to the early cancellation of a power purchase contract with Alcoa that made the standalone economics of Sandow untenable.
The timing of Vistra’s announcement could also play into a strategy involving broader market dynamics. There are a lot of elements at play right now in ERCOT. Two of the Vistra coal plants could end up receiving RMR contracts. There also are about 1,500 MW of plants that have filed with ERCOT seeking approval to be mothballed. As the name suggests, that status is not a permanent shutdown — a spike in summer prices could draw them back in the market. And there's the dynamics of the natural gas market.
Pause for developers
Cheap gas and the entry of modern, efficient gas plants have been the bane of coal and older gas-steam plants for years. While natural gas prices have stabilized around $3 per million British thermal units, gas prices in West Texas have been sinking. A rise in oil prices has created a resurgence in oil production from West Texas’ Permian Basin. Oil produced there also throws off an abundance of associated gas with little market access, so it often trades at a discount to the national benchmark.
Cheap gas not only tends to lower power prices, it often attracts new entrants — developers eager to steal market share by building plants to take advantage of cheap fuel.
That has been Panda Energy’s strategy for years. It has worked well in the PJM Interconnection, but Panda got in trouble in Texas. In 2012, Panda Temple Power began construction on a 758 MW combined-cycle gas turbine plant in Temple, Texas, that entered service in 2014. This spring, the project company filed for bankruptcy. According to a court filing, the plant has been losing money since 2015.
Panda is suing ERCOT for “false and misleading market reports.”
Panda’s experience is likely to give pause to other developers eyeing the Texas market. In the first quarter, Calpine cancelled plans to add 400 MW to an existing peaking plant in ERCOT, instead signing a contract to buy 200 MW of power.
Aside from getting whipsawed by market volatility, generators with an eye on Texas have also no doubt noticed that it is cheaper to buy generation there than to build it. In July, Vistra said it plans to by the 1,000 MW Odessa-Ector Power Partners combined-cycle gas turbine plant from a subsidiary of Koch Ag & Energy Solutions for $350 million, or $332/kW, a deep discount to the roughly $1,000/kW price of building a new gas plant.
And at the end of October, Vistra announced a $1.74 billion all-stock merger with Dynegy, which owns about 4,700 MW of Texas plants — all of which are gas-fired except for a 635 MW coal plant.
One view of the timing of Vistra’s coal retirement announcement is that it aids the company’s acquisition plans. “Coal has been keeping prices down, so you can acquire low and then retire coal plants” in the hope of pushing prices up, Timothy Wang, a director at Filsinger Energy Partners, told Utility Dive.
In his October report, Mitra said, “We believe Vistra will take its foot off the pedal in terms of rationalizing its fleet and focus on M&A.”
The announced retirements could lead to “more balanced” power prices in ERCOT, Wang said, but most generation stakeholders, particularly those that might build new plants, are waiting to see if there is a repeat of 2011. They are waiting for shortages to show up in peak prices, he said.