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Policy, fundamentals to challenge US independent power producers in 2018

Stagnant US electricity demand, lower commodity prices, policy interventions, and continued improvements in renewable energy costs and technologies may increase risks for independent power producers in 2018, which some industry observers say may result in more sector consolidation.

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"In general, IPPs will face a challenging 2018 due to persistently low commodity prices and flat to very moderate demand growth for electricity," said Matthew Cordaro, a former Midcontinent Independent System Operator CEO who now resides in New York.

For the 12 months ending September 30, retail electricity sales to all sectors in the US are down almost 71 TWh, or 2%, from the previous 12 months of 2015-16, and the trailing 12-month total is the lowest since the recession period of 2008-09, according to US Energy Information Administration data.

"Load growth is not likely to turn around that quickly, especially with counteracting factors, like distributed generation and energy efficiency improvements, continuing," said Manan Ahuja, senior director of PIRA Energy, an analytics unit of S&P Global Platts.

Gurcan Gulen, senior economist at the University of Texas Bureau of Economic Geology's Center for Energy Economics, said in an email, "The price of natural gas is not likely to increase much, hence keeping the wholesale electricity price relatively low."

Regarding renewable energy, PIRA's Ahuja said in an email that "cost declines/technology improvements are still in a steep part of the curve for renewables/storage -- they won't slow down that quickly."


Michael Webber, deputy director of the University of Texas Energy Institute, said, "An ongoing era of low power prices will strain IPPs' finances," which will result in "more bankruptcies."

NRG Energy is spinning off its GenOn merchant unit through a pre-arranged Chapter 11 bankruptcy. Exelon's ExGen Texas has filed bankruptcy.

Cordaro said that the "macro factors" of low commodity prices and low demand "present numerous financial challenges and will drive increased consolidation within the industry."

Dynegy announced on October 30 a planned merger with Dallas-based Vistra Energy in an all-stock transaction valued at about $1.74 billion, with Vistra as the surviving entity by mid-2018.

But Dynegy President and CEO Robert Flexon has said, "I wouldn't expect to see much in the way of consolidation in 2018 as significant consolidation has already occurred."

Vistra has announced plans to retire as much as 4,200 MW of coal-fired generation by mid-February, which prompted some industry observers to cite the Electric Reliability Council of Texas as a possible bright spot for IPPs in 2018.

"IPPs that are still operating should possibly do a little better in terms of revenues, but not much better as it still seems [natural gas] prices will remain low due to [oil-and-gas] drilling activity in general keeping up NG supplies," said Carey King, University of Texas Energy Institute assistant director and research scientist.

PIRA's Ahuja said these retirements, "along with continuing load growth in Texas, will make the reserve margins quite tight."

"Hence, there could be significant price spikes, especially on hot summer days."


But Dynegy's Flexon said IPPs may change their portfolios, but "the thing to watch in 2018 is on the regulatory side."

Ahuja said "Policy interventions are a wild card -- not sure which way they would end up."

One such issue is the US Department of Energy's "resiliency" notice of proposed rulemaking that would ensure baseload generators in organized markets are compensated for maintaining at least 90 days' supply of fuel, which would mainly benefit coal and nuclear generators in the northeastern quadrant of the US.

At the urging of US Federal Energy Regulatory Commission Chairman Kevin McIntyre, Energy Secretary Rick Perry on Friday granted a 30-day extension for FERC to respond to the NOPR. Flexon expressed hope "that the [DOE] NOPR will drive many of the price formation efforts that are just getting underway, while spurring a longer-term discussion around grid resiliency."

But UT's King said in an email that the DOE NOPR "is a challenge [for IPPs] in the sense that it will dampen competition as a factor in power generation seeking lowest marginal cost and therefore call into question whether power generation starts going more toward regulated models ... where politicians can influence the power generation mix (for renewables, coal, or other)."

In mid-November, PJM proposed new price formation rules "to more accurately reflect the resources required to serve load, to incent flexible resources, and to minimize out-of-market uplift payments," according to Stu Bresler, PJM senior vice president of operations and markets. The new approach would allow inflexible baseload generation to set prices, whereas flexible units -- typically natural gas peakers -- currently do so.

Inflexible generation has in recent years been deriving much of its revenue from capacity market payments and "uplift" payments from all load to generation needed for reliability.

If approved, PJM's new rules "could provide a meaningful upward lift" to locational marginal prices, Ahuja said.


New York and Illinois have instituted zero-emissions credit programs which provide subsidies to nuclear power, and states such as Connecticut and New Jersey have considered moves in that direction.

Dynegy's Flexon has questioned the viability of the competitive wholesale markets model in environments where "large incumbent utilities that, in particular, have exceedingly expensive nuclear assets are using their political muscle and putting the full-court press on state politicians to act in their own interest and not the public's interest."

"With states becoming increasingly active in policymaking without considering the cost to the public, does it reach a point where the states simply re-regulate to the more expensive monopoly model since political motivations are outweighing costs and becoming less of a consideration and hybrid markets won't work?" Flexon asked in an email.

California has several regulatory incentives to support renewable power; therefore, PIRA's Ahuja said, "merchant gas units have started retiring early there."


Eric Smith, Tulane Energy Institute associate director, said that "the fundamental problem with fossil-fueled IPPs is that they represent a failed attempt to fundamentally change the nature of the power market."

As IPP plants were originally developed, they were "qualifying facilities" from which the federal government mandated utilities to take power, Smith said in an email.

"Even when renewables were less pervasive, all too often their ultimate fate was to be acquired by the utility in whose territory they resided," Smith said. "Now, with growth in renewables and improving transmission, their place in the sun has been usurped."

The Public Utility Commission of Texas has established Project No 47199, "Project to Assess Price-Formation Rules in ERCOT's Energy-Only Market" to address issues raised in a paper by Harvard's William Hogan and FTI Consulting's Susan Pope that concluded a variety of forces are impairing ERCOT's market efficiency.

That paper recommended including marginal line losses in calculations used to determine which generation to dispatch to supply load, establishing local reserve requirements and setting local Operating Reserve Demand Curves, which provide an adder to energy prices as operating reserves decrease and the probability of load loss increases.

But UT's Gulen said, "'Price formation' reforms (if and where implemented) are not likely to yield enough additional revenue."

"Subsidized/mandated renewables will continue to eat into the market share," Gulen said, but added that "the vicious cycle of subsidies may lead to more nuclear and even some coal units to be subsidized."

--Mark Watson,

--Edited by Lisa Miller,