Energy Blog

US power market reform uncertain




  • Playing football … with DOE’s proposal to reform competitive electricity markets.
  • Friday Luminant asked ERCOT for permission to retire all three units at the Monticello coal-fired station. That could push the DOE plan into fast-forward.
  • Don’t expect a decision from FERC about the proposal before winter.

When one begins to peel, one finds a lot of onion. One could also find north of 100 million tons of US domestic coal burn – maybe double that in a high natural gas price scenario.

The Department of Energy proposal to reform competitive electricity markets, a move that could be deeply positive for many coal and nuclear power plants, has already become a football, political or otherwise, and it might not be easy to predict who will choose which jersey.

Let’s leave that layer of onion for a bit further down today’s missive. Instead we’ll start by trying to offer a bit more insight into the nuts and bolts of Energy Secretary Rick Perry’s directive to the Federal Energy Regulatory Commission. The proposal’s importance was underscored Friday when Luminant asked ERCOT for permission to retire all three units at the Monticello coal-fired station on January 4, 2018. The request will trigger a reliability review.

If ERCOT determines the units are not needed for reliability following the 60-day review, Luminant would move forward with retirement. Luminant could well be attempting to force regulators to get serious very quickly about power market reform. In any event, one sees why the Perry proposal is in an intense spotlight. An extremely well-placed source noted that the proposal is pretty well crafted and written more in the language of lawyers than of energy analysts. As such, he urged that attention be paid to particulars of the language. There could, for instance, be a benefit to generators beyond the obvious.

The document mentions that eligible plants must be entirely compliant with environmental rules in order to be considered as a generation source necessary to grid reliability and resilience. There also is some acknowledgement that since regulations including, for instance, MATS and clean water helped to force some closure decisions, there might be a compensatory element to the rule.

For instance, as a part of any payment to assure the life of generation capacity, the rule might provide “compensation for the need to spend, say, on lime injection, for instance.” The potential justification – “Does the price of electricity pay for this? So far, no.”

But the DOE argument is that the generation is necessary for grid security and by extension national security. “This could mean that the (greater) market would pay for that – socialize the cost – and allow those plants to stay up.”

One energy trader isn’t buying the Perry plan. “Subsidizing coal in this capacity will disrupt the market place,” he said. “I have long said keeping inventories does make sense from a national security perspective, but not universally across the fleet.

“If the coal plants are to be subsidized, it should not be in manner that changes the merit order of dispatch.” Instead, he said “the burden should be shifted to a national footprint rather than a regional – ratepayer – basis.” The source also disagrees with the direction the plan takes.

“The truth is the subsidy should go toward environmental controls, shoring up pensions for miners and plant operators, and remediation of the existing fleet,” he said. “To expect an extended life of relevance for the coal plants is a total disregard for the facts.” Debate is likely to be intense. Folks could see things a myriad of ways when looking through a glass onion.

90 days, Judge?

There is no indication yet – and probably no decision – regarding the definition of 90 days of onsite fuel supply. Will that mean 90 days in the purest sense – the amount of fuel that can be burned on a given day, times 90? Or will some other measure be employed – one that takes into account the actual fuel burn, either by looking backward or forward?

Things could be more complicated if the purest definition is not employed. “What is 90 days – 90 days of one quarter or 90 days in the winter?” Various scenarios will be drawn up and negotiations begun, the source said. Neither is it clear exactly how many power plants might benefit from the rule, which in the DOE proposal applies only to plants located in a FERC-regulated market. Generation in SERC, Intermountain and the Pacific Northwest would not be included, for instance, and “not ERCOT, probably, because it’s not a FERC-regulated market.” But application of the rule, if it occurs, could be extended to other markets based on the resilience and reliability argument. And whether that happens could depend on the reasoning applied to rule implementation. “Is it security or (is it) how the market operates?” the source said.

In any case, coal generation benefited by the rule, as envisioned now, could total north of 100 million annual tons, according to knowledgeable sources. But as indicated above, the number could double if gas prices were to substantially increase.

The numbers assume about 45 GW of coal generation would be eligible for relief under the plan.

Beyond the coal issue, there is the question of whether some natural gas plants might be given status under the rule. Gas generators could and probably will seek status through the acquisition of firm supply contracts, and directly by building pipeline specifically devoted to a potentially eligible plant.

Gas generators could also argue for status by maintaining stocks of LNG or fuel oil. But that’s problematic. Onsite LNG “would cost you a lot, but you could” stock it, the source said. Fuel oil might be excluded by its potential impact on sulfur emission levels. Coal and nuclear plants have the best arguments for onsite fuel security, the source said. “There’s nothing more secure than the coal pile,” and maintaining a large inventory is relatively inexpensive. Nuclear units need only have their fuel recharged “and you’re good for three years.”

But there are some complicating factors. There is an argument, for instance, that grid reliability and resiliency would rely on some assurance of gas generation availability in California. That might be a wormhole for gas plants elsewhere.

Much ado or die

All of these points are moot if the rule doesn’t get traction at FERC. And that is no slam-dunk.

FBR sent a note to investors in which it pointed to comments made by FERC Commissioner Robert Powelson, a Trump appointee, to the Organization of PJM States. The commissioner “reinforced our belief that it is unlikely FERC will take final action on DOE’s proposed rule to insert resiliency pricing into wholesale markets before winter,” the note says.

Powelson said FERC “will not destroy the marketplace” and according to FBR “implied he would leave FERC if action is taken to undermine competitive markets.”

The question, of course, is whether competitive markets have already been undermined by prior regulations and by tax benefits for renewables. Rather than attempting to eliminate such tax credits, for instance, FERC could find the Perry proposal “kind of rebalances, a bit, competitive markets,” a source said. The question will be raised regarding whether gas plants have had an unfair advantage. “In the competitive markets, gas has been eating everybody’s lunch, but it hasn’t been asked to pay for fuel security,” the source said. Gas producers “want the pipeline industry to pay for pipes.”

As has been pointed out here, the Perry proposal also incorporates a rapid timeline for FERC consideration and potential implementation of the new rule. Speed is of the essence where some coal generation is concerned. A lengthy process could result in some premature plant closures. This is the area in which Powelson’s comments might raise the deepest concerns. He might have a hitch in his giddy-up, as it were.

The Powelson “commentary is the strongest indication yet that FERC may pursue a longer-term evaluation of valuing reliability in the marketplace, or reject it outright, rather than issuing a final rule within the 60-day proposed time line from DOE,” FBR wrote. The fact FERC has a quorum increases the possibility, at least, of rapid movement on the DOE proposal. The quorum was restored in August when the Senate confirmed commissioners Neil Chatterjee and Powelson.

But Sen. Lisa Murkowski, R-Alaska, chairman of the Senate Committee on Energy & Natural Resources, appears to be doubling down given the desire of DOE to fast-track its proposal. She wants Trump nominees Kevin McIntyre and Rich Glick confirmed as FERC commissioners this month rather than in November, as anticipated. “For years, I have been concerned about how federal laws and rules affect the reliability and resiliency of our nation’s electric grids,” Sen. Murkowski said. “I respect Secretary Perry for taking an action that he believes is necessary. As the law provides, the Secretary’s transmittal of a proposed rule to FERC will spur action on a debate that has been underway since the start of this decade.” Sen. Murkowski noted “the work will shift to FERC as Congress intended when it established the Department of Energy and the Commission 40 years ago. I look forward to seeing the record develop even further, and will be following the proceedings closely.” PJM Interconnection seems sceptical of the proposed DOE mechanism. “The pricing and fuel security objectives identified by the Department of Energy are best achieved through competitive markets in order to retain disciplining forces that work to prevent consumers from paying for unnecessary and inefficient resources.”

Questions will be asked

Interested parties may comment to FERC regarding the Perry proposal on or before Oct. 23, and reply comments are due on or before Nov. 7. One can access a list of questions for which FERC seeks replies. Here is one interesting line of questioning – “As the proposed rule focuses on preventing premature retirements, should a final rule be limited to existing units or should new resources also be eligible for cost recovery? “Should it also include repowering of previously retired units?

Alternatively, should there be a minimum number of MW or a maximum number of MW for resources receiving cost-of service payments for resilience services? If so, how should RTOs/ISOs determine this MW amount? Should this also include locational and seasonal requirements for eligible resources?” Here is another – “If technically capable of sustaining output for a sufficient duration (and meeting other relevant requirements), should resources such as hydroelectric, geothermal, dual-fuel with adequate on-site storage, generating units with firm natural gas contracts, or energy storage (each of which might have a demonstrable store of energy to draw upon to sustain an electrical output, if not necessarily fuel) also be eligible? Why or why not? “If technical capability is the appropriate criterion for eligibility, what specific technical capability should be required to be eligible?” And another – “The proposed rule defines eligible resources as having a 90- day fuel supply. How should the quantity of a given resource’s 90 days of fuel be determined? For example, should each resource be required to have sufficient fuel for 24 hours/day and sustained output at its upper operating limit for the entire 90-day period? Would there be any need for regional differences in this requirement?”

One might also pay attention to a series of questions regarding potential implementation of the rule, including:

  • “How would eligible resources receiving cost of service compensation under the proposed rule be committed and dispatched in the energy market?
  • “How would eligible resources receiving cost based compensation under the proposed rule be considered in the clearing and pricing of centralized capacity markets?
  • “What is the expected impact of this proposed rule on entry of new generation, reserve margins, retirement of existing resources, and on resource mix over time?
  • “Should there be performance requirements for resources receiving compensation under the proposed rule? If so, what should the performance requirement be, and how should it be measured, or tested? What should be the consequence of not meeting the performance requirement?
  • “Should there be any restrictions on alternating between market-based and cost-based compensation?” Onions have multiple layers and peeling one leads a lot of folks to cry. Who is left in tears when all is said and done will be critically important to domestic coal generation.

Learn more about our North American coal market news and commentary.

Jim Thompson is Research and Analysis Director of Coal at IHS Markit.
Posted 13 October 2017

About The Author

Research & Analysis Director, Coal

Jim Thompson, Director for IHS Markit, is lead commentator for the IHS Coal & Energy daily newsletter and editor of the weekly publication, US Coal Review. He is conversant on worldwide market trends, with a focus on the North American coal markets. Mr. Thompson provides expertise both in thermal coal for electricity production and metallurgical coal for use in the steelmaking process. He is widely quoted by leading financial newspapers and speaks at multiple, industry-related conferences. He has more than two decades of experience in providing analysis and insight on coal markets for coal producers and consumers, as well as for financial analysts and investors. Mr. Thompson cofounded Energy Publishing, which was acquired by IHS Markit in 2013. He graduated from Dallas Baptist University.