Wholesale market crisis

In April, U.S. Energy Secretary Rick Perry sent a memo ordering staff to prepare a report to look into the retirement of “baseload” coal and nuclear plants, and why this is happening. And while Secretary Perry’s stated reasons for this report were long on energy mythology – including the anachronistic claim that such plants were necessary for reliable supply of electricity – a more credible draft report by Department of Energy (DOE) staff shows that many such generators are indeed in crisis, if not for the reasons that Perry has assumed.

It did not take a technical investigation to reveal what was happening. Across the United States wholesale power prices have been low and continuing to fall for nearly a decade, accompanied by the retirement of large volumes of baseload plants. While this has happened, large capacities of gas generation and later wind and solar projects have been put online.

But this fall in prices is not only enabling the retirement of conventional generation. It also poses challenges for the solar industry.

Causes of the price decline

There is no credible grounds for debate that the primary cause of this decline in wholesale prices is the fall in natural gas prices, which has been enabled by a boom in extraction of gas via hydraulic fracturing (fracking).

As natural gas has become an increasingly large part of the nation’s electricity mix, gas prices have become the driver of wholesale power prices, and according to DOE, electricity prices nationwide have been tracking gas prices for 15 years.

Another significant factor as reported in the leaked draft version of the DOE grid study is flat or declining electricity demand. While in the second half of the 20th century U.S. electricity demand was tied to economic growth as measured by gross domestic product, since 2005 electricity demand has been nearly flat, despite GDP growth following the 2008 recession.

The utility industry has maintained a curious degree of denial regarding this trend, and each year utilities issue forecasts for future electricity consumption which repeat their errors of the previous years.

Increased deployment of wind and solar has also been a factor in driving down wholesale prices, but these effects have been limited and both geographically and temporally specific – particularly for solar. Solar only represents more than 10% of annual generation in one state, so the effects have been largely limited to California, and only during the middle of the day when solar is generating.

Wind is having more of an effect in the Midwest, Texas, and the plains states, but depresses power prices mostly overnight when wind output is greater.

Market pressures and conventional generation

The effect on independent power producers (IPPs) which operate in the nation’s deregulated markets has been severe. In NRG’s 4th quarter 2016 results call, CEO Mauricio Gutierrez famously stated that “the IPP model is now obsolete and unable to create value over the long term,” as his company reported another quarter of dismal financials. But NRG is far from alone, as fellow IPPs Calpine and Dynergy have also reported heavy losses in recent years.

These negative margins are driving the retirement of conventional generation. According to the Federal Energy Regulatory Commission (FERC), since 2010 nearly 100 GW of baseload plants have been retired. These are mostly coal plants, and DOE’s analysis in the draft grid study finds that most of the plants that have retired over the last 15 years were at least 40 years old.

And while both plant owners and the Trump Administration have been using these retirements to raise the bogeyman of reliability concerns, the amount of reserve capacity to meet power demand in most parts of the country is well above the margins mandated by grid operators. In fact, regions such as the PJM Interconnection have well exceeded reserve margins, and are considered oversupplied.

In the case of accelerated retirements of coal and nuclear plants, it is important to note that such inflexible generation will ultimately conflict with high levels of solar on the grid. For addressing climate change, the retirement of coal plants is necessary.

But the mechanics of such retirements are driven by economic factors, and not through a top-down plan for decarbonization. As such, even newer assets at times get caught up in the whirlwind of market forces, such as when a gas plant put online in Texas in 2014 retired earlier this year.

Consequences for solar

Nearly all of the large-scale solar which has been built in the United States is backed by long-term contracts, and this has insulated PV from the market forces that have ravaged merchant operators. However, solar is not immune to price dynamics.

The most direct route for sustained low wholesale power prices to affect the solar market is in the realm of voluntary corporate and utility procurement of solar, which have emerged as significant and growing sectors in recent years. And while a slight change in the price differential between solar and gas will not necessarily dissuade companies like Google or Apple that have 100% renewable energy goals, GTM Research says that other companies may be fickle.

“It does affect the prospects for new development,” Shayle Kann, senior VP of research at Greentech Media and head of GTM Research told pv magazine. “All those other mechanisms, are, in one way or another, driven by solar being competitive with an alternative resource – typically gas. If gas is cheap, or cheaper, it makes all those other mechanisms more difficult.”

PURPA and long-term contracts

Additionally, the fall in wholesale power prices is having an impact on the policy environment. In March, Duke Energy argued that its customers were overpaying by $1 billion on $2.9 billion worth of prior contracts signed under the auspices of PURPA, a federal law requiring must-take contracts for solar generation, as part of a proposal for substantial changes to the law’s implementation in North Carolina.

Whatever you may think of Duke’s repeated attempts to weaken PURPA or its motivations, the power company’s argument is based on the accurate premise of a gulf between actual power prices and calculations of its “avoided cost”, or the price it expects to pay for power in the future. Avoided cost sets the price for PURPA contracts, which in North Carolina were locked in for 15 years before recent changes.

Duke’s argument is being echoed in states across the nation. And while it may not be the main reason that utilities are attacking PURPA, it is extra ammunition for those that want to weaken the law – such as has been done in Idaho and Montana. Even North Carolina has moved away from PURPA to an auction system for projects larger than 1 MW, as a compromise between Duke and the solar industry.

With the inability of future price estimates to keep pace with declines, it is tempting to think that long-term contracts are becoming passé, and there is a trend towards power from solar PV plants being sold under shorter-term contracts, sometimes with a so-called “merchant tail”. However, the solar industry is still dependent upon a certain contract length to secure financing, as most of the attempts at merchant solar both in the United States and Chile have been disasters.

GTM’s Kann warns against taking this logic too far, noting that from a utility’s perspective there should always be some balance of long-term contracts and market exposure.


In addition to the attacks on PURPA, lower prices and the threat to conventional generation is leading grid operators to implement policies that favor gas, coal and nuclear resources, and may be damaging to wind and solar economics.

The most blatant of these policies are zero emissions credits (ZECs), a form of bailout for aging nuclear power plants that attempts to draw an association with renewable energy credits. ZECs have been implemented in New York and Illinois, and are being considered by other states including Connecticut that host nuclear power plants which are struggling in the environment of low wholesale prices.

In Illinois, the creation of ZECs appears to have been aided by a deal struck between the solar and the nuclear industries, as part of a bill that fixed broken structures in the state’s renewable energy mandate. However, gas-heavy IPPs have sued to stop ZECs, and they are joined by other observers in arguing that this policy distorts wholesale market mechanisms.

Robbie Orvis, policy design projects manager at research and analysis firm Energy Innovation, notes that ZECs have multiple effects on power markets, This includes not only keeping capacity online that would otherwise retire and thus exacerbating oversupply, but price impacts. “The net effect will be to decrease prices in the spot markets and the capacity markets,” Orvis told pv magazine.

System redesign

ZECs are far from the only changes being proposed to wholesale markets. In May, NRG and Calpine – both of whom were involved in suits to stop ZECs in Illinois – filed a white paper with Texas regulators, proposing changes to the state’s mechanism to determine when scarcity pricing events occur.

This mechanism – the Operating Reserve Demand Curve (ORDC) – is not a capacity payment, but functions like one by supplying extra revenue for generators outside of energy markets. The two IPPs claim that the function of this mechanism has been undermined by incentives for wind and solar, as well as Texas’ socializing of transmission costs for renewable resources.

Such proposals to shore up the investments of conventional generators are not limited to states where renewables have weak support. New England’s grid operator (ISO), which like Texas’ ERCOT market has some of the slimmest reserve margins in the nation, put out a draft report in August which argues that without additional incentives, the region’s wholesale energy market may not be sufficient to keep new resources economically viable.

Orvis of Energy Innovation notes that even in the PJM Interconnection grid, mechanisms adopted by the grid operator sometimes favor conventional, not renewable, generation.

“The Capacity Procurement Mechanism, which requires that all resources are able to perform all year round, puts wind and solar at a significant disadvantage because they are highly seasonal,” explains Orvis. He also notes that ISO New England is considering a two-part capacity market proposal, which could likewise increase the barriers for wind and solar participation.

But while such moves to date have largely been made by conventional generators that want to protect their profits and market presence, not all such market redesign will necessarily be unfavorable to wind and solar.

In its recent report Flexibility: the key to low-carbon, low-cost grids, London’s Climate Policy Initiative notes that highly flexible resources such as fast-ramping gas generation will be needed to balance the output of high penetrations of wind and solar power. The report further finds that as such, markets design is needed to better provide signals to both consumers and electricity producers to encourage flexibility in the system where it is needed.

Market design that specifically supports flexible generation could support the transition to renewable energies while still keeping the grids stable, as opposed to capacity payments that, at times, keep online a number of aging, inflexible plants.

Change is coming

While the cause of the current collapse in U.S. wholesale power prices is mostly due to gas, as more zero (or sub-zero) marginal cost wind and solar come online, prices are only going to go in one direction: down. And while these prices may be wreaking havoc on IPPs, they are accelerating the retirement of dirty coal and aging, potentially dangerous nuclear plants, which is an essential part of the energy transition.

Energy Innovation’s Orvis argues that by pushing uneconomical plants off the grid, wholesale markets are in fact functioning as they are supposed to. “The market signals are meant as an incentive to retire generation when it is no longer needed – whether or not these plants have reached the end of their useful lifetime,” notes Orvis.

As such, in the current environment wind and solar are spurring market forces that can accelerate the energy transition. Depressed prices are also ushering in a future of cheap power, which bodes well for both industry and those in the developing world struggling to gain access to electricity, and the nations and regions which seize these opportunities first are likely to benefit.

The losers in the conventional power industries are already starting to resist such changes. But low wholesale power prices will also be a problem for wind and especially solar operators during their hours of peak output, and will put pressure on the industry to keep bringing prices down.

It is not clear that the current structure of wholesale markets is best suited to support the energy transition, or that such a market will continue to function under high levels of renewable energy – either for renewable power, or the gas-fired resources on some grids that are expected to remain an important component of a low-cost, high-renewable power system for the foreseeable future.

Given the active proposals to change the structure of wholesale power markets in the United States, the solar and wind industries need to be a part of the decisions about how to best structure such markets – if for no other reason than to ensure that the energy transition is not delayed by incumbent interests.

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