US power policy grapples with renewables growth, capacity gaps

Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Platts' US generating fuels news team report on policies at state and federal level that will have consequences for energy security and the transition to renewables.

As the US power industry contends with reliability concerns due to low electricity prices, rapid renewables growth and baseload generation retirements , policymakers are scrambling to offer solutions.

Regulators are also trying to work out how to best incentivize adequate generation capacity additions, and how to ensure compensation of existing power plants and other resources operating in competitive markets.

The current challenges have already led to a variety of complicated market design proposals and other potential fixes created at both state and federal level.

Among the major federal issues being watched closely this year are efforts by the White House to keep nuclear and coal-fired power plants afloat, although so far the Trump administration’s efforts have been frustrated. Among the states, meanwhile, Texas has made market design changes to encourage generation capacity development at a time when reserve margins are extremely low.

PJM Interconnection also has the daunting task of installing reforms to maintain a competitive marketplace in the face of state subsidies designed to prevent the retirement of major baseload nuclear facilities because of low energy prices. And in California, the effort to go 100% renewable has led to a number of reliability questions.

Appealing to the base(load)

TheWhite House’s effort to keep struggling coal and nuclear plants solvent is perhaps the highest-profile power industry event in 2019. However, many Washington insiders have grown increasingly skeptical that action at the federal level to keep these baseload coal and nuclear plants online can find a legal foothold.

In a recent development, the board of the federal government-owned utility Tennessee Valley Authority voted February 14 to close two coal generation units despite pressure from President Donald Trump, who tweeted ahead of the vote that the utility “should give serious consideration to all factors before voting to close viable power plants”.

TVA responded that while coal was an important part of its generation mix, the Paradise and Bull Run coal plants at issue no longer met its system needs. Retiring the plants is expected to save TVA customers more than $1 billion.

This latest snub to the White House’s efforts comes over a year after the Federal Energy Regulatory Commission rejected the administration's original plan to prop up coal and nuclear generators. That involved a notice of proposed rulemaking from the Department of Energy that sought to guarantee full cost recovery and a return on investment for generators that had 90-day, on-site fuel supplies.

“I think it's just going to be very difficult to do anything on the federal level although I think the administration is going to continue to try,” Barry Worthington, executive director of the United States Energy Association, said in an interview. Action from states could be more likely, he said.

States such as Illinois, New York and New Jersey have turned to zero emissions credits programs to save their nuclear fleet, and Worthington said coal-producing states may look to craft programs to help coal units.

FERC Chairman Neil Chatterjee said on the sidelines of an industry conference that if a threat is identified, his preference would be to resolve it with a market solution. “Whatever action we take on resilience will be based firmly on the record, on evidence, on science without any political influence or favoritism for one fuel source or another. We just want to make sure we do it right.”

ERCOT struggles with tight capacity

Among the state initiatives being watched are the Electric Reliability Council of Texas’ market reform strategies to encourage development and retention of dispatchable generation resources, in light of the low reserve margins the Texas grid is expected to face again this summer.

A number of recent capacity retirements resulting from renewable power generation growth, cheap and abundant natural gas, and low power prices have put the state grid in a precarious supply situation.

Over 5 GW of fossil-fuel generation – including 4.2 GW of coal-fired generation – has been retired in ERCOT since May 2017. This summer the market has a projected 7.4% planning reserve margin, the lowest on record and well below the system's target of 13.75%.

In February, ERCOT issued a market notice stating that it would implement the first change to its Operating Reserve Demand Curve on March 1. ORDCs are used to calculate scarcity prices when supply and demand tighten, providing incentives for new generation development. ORDCs enable wholesale prices to increase automatically as available operating reserves decrease. The actual price adjustment is based on the level of increasing risk that a rotating outage could occur and the potential consumer impacts associated with an outage.

In order for the ORDC change to have the desired generation retention and growth effect, investors and developers must have faith that the resulting higher wholesale prices will be sustained, and such faith may be hard to find during a biennial legislative session in which lawmakers may hear complaints from consumers about surging electricity bills.

ERCOT, market stakeholders and industry observers all seem to disagree about how successful the market reform actions will be – or indeed can be – in encouraging new generation capacity.

“Market reforms are good but probably not enough to yield new dispatchable capacity within 2-3 years,” said Gurcan Gulen, energy economist and principal of G2 Energy Insights.

However, Gulen said that if the reforms enable developers to obtain financing, 2 to 3 GW of gas-fired generation may result.

In contrast, Cyrus Reed, conservation director of the Sierra Club's Lone Star region, said, “We do not think the ORDC adjustment will make a large difference in providing an incentive to more dispatchable generation, though it could provide an incentive for investments in demand response as a reaction to higher prices.”

In Texas, demand response often takes the form of on-site fossil-fueled generation, either with natural gas or by a liquid fuel such as diesel or gasoline. Such relatively high-cost, inefficient resources could be aggregated and dispatched to serve the grid in high-demand situations.

“Alliance” of renewables, oil, gas

In February, the ERCOT Board of Directors learned the Far West weather zone's peak demand has doubled since 2009 – from about 1.8 GW to about 3.7 GW – largely because of Permian Basin oil-and-gas development.

ERCOT projects about 20 significant new wind and solar projects in West Texas by 2033, but Neil McAndrews, an energy market consultant based in Austin, Texas, said the region's natural gas production is a more significant impediment to ERCOT's thermal generation fleet.

“The essential problem faced by all US utilities is that natural gas is priced, in large part, as a by-product,” McAndrews said. “The Permian oil field is wasting 55 Bcf per year via flaring, according to industry sources. … The gas that is flared is considered valueless.”

“Look for many more retirements of coal and nuclear units in the US,” McAndrews added. “Without addressing the fundamental problem of natural gas oversupply, there is little ERCOT or the PUC of Texas can do.”

PJM markets in flux

ERCOT has not been alone in attempting to manage challenging capacity trends. PJM Interconnection has been at the forefront of the situation in large part because of low power prices due to cheap natural gas from the Appalachian Basin, as well as several state efforts to subsidize uneconomic baseload facilities in response to those low power prices and the likelihood of plant retirements.

In its 2018 capacity auction, the PJM base residual auction RTO clearing price came in at $140/MW-day for capacity in the 2021-2022 period, an 83% increase from the previous year’s clearing price of $76.53/MW-day.

The capacity price increase was attributed to a response to continuing energy prices declines, and thus, net revenue for generators, Stu Bresler, PJM’s senior vice president of operations and markets, said when the results were released. Since generators have been receiving less revenue from the energy market, they have looked to earn higher capacity payments and thus bid into the auction at higher prices.

PJM has been working to adjust some of its energy market pricing rules, adding uncertainty to the pricing dynamics between the energy and capacity markets.

In addition, the Federal Energy Regulatory Commission issued an order in June 2018 that found the PJM Interconnection’s existing tariff governing its capacity market is unjust and unreasonable, which set off a major proceeding to adjust the rules. The order said PJM’s capacity pricing model had become “untenably threatened by out-of-market payments provided or required by certain states”. Illinois, New York, New Jersey and Connecticut have passed laws or issued regulations designed to financially support a number of at-risk nuclear plants, while several other states are considering similar actions.

A decision from FERC is expected in the first half of 2019 to keep the capacity auction on schedule for August. The upcoming auction already has been delayed three months due to the complexity of the process.

FERC’s order will be one of the most important capacity market developments of 2019.

PJM’s energy price formation contains two main elements: fast-start pricing and reserve price reform. Fast-start pricing, which would modify pricing treatment for generation resources that can start up quickly, awaits a FERC response. A contentious filing on reserve reform from PJM at FERC can be expected around mid-March, PJM president and CEO Andy Ott said in a recent interview. Reserve pricing reform is expected to include multiple components affecting several major aspects of the wholesale power market in the region.

Go deeper: Podcast - PJM CEO Andy Ott on energy and capacity markets

Initial S&P Global Platts Analytics modeling of the impact of both fast-start pricing and reserve reform resulted in an overall price increase of $1-2/MWh. Since the analysis was conducted, updates to the proposed ORDC as well as a larger penalty adder could increase this estimate, according to Platts Analytics power market analyst Kieran Kemmerer.

Ott said in the interview that he believes reserve price increases will incentivize new alternative technologies to provide more reserves and “compete away the advantage that generators have had and so the price will drop”.

As the rule changes encourage technologies such as storage and demand response, providing additional reserves to the market, the increased supply of reserves could exert downward energy price pressure.

The outcome will provide valuable lessons that could influence future state or federal actions.

ISO New England faces controversy

Stakeholders in ISO New England’s capacity market also recently raised concerns that low prices, a renewable exemption and a specific contract with the gas-fired Mystic power plant near Boston in a recent capacity auction, all conspired to damage the viability of generation resources in the region.

ISO-NE’s 13th forward capacity auction held in February closed at a preliminary clearing price of $3.80/kW-month, an 18% decline from last year’s auction price and the lowest clearing price in six years.

Worries arose that the Mystic power plant’s exemption and contract dampened the impact of ISO-NE’s rules for competitive auctions with sponsored policy resources. In December 2018, FERC accepted a cost-recovery proposal for Mystic, providing ratepayer support for the plant, which was allowed “price-taker” status in the next three annual capacity market auctions.

The New England Power Generators Association said that with Mystic entered as a price taker, the auction undervalued other fuel-secure resources in the market. “Coupled with the future scale of subsidized new entry, competitively-determined adequate revenues are at grave risk in New England,” NEPGA President Dan Dolan said.

New York carbon price

In New York, efforts to price carbon emissions into the wholesale market could lead to price increases. The New York Independent System Operator’s five-year power grid plan sets out strategic initiatives to guide its projects and resource allocation that include pricing carbon emissions into the wholesale market, which could increase power prices by about $10-$15/MWh, according to Platts Analytics.

“The carbon prices being discussed for implementation in New York are significantly higher than the current [Regional Greenhouse Gas Initiative] RGGI prices,” said Manan Ahuja, senior director of North America power modeling at S&P Global Platts Analytics.

If implemented, the carbon prices could add significantly to the wholesale power prices, increasing location-based marginal prices “by about $10-$15/MWh (in the proposed carbon price vs the RGGI price) based on our recent modeling,” Ahuja said.

Such changes would also impact decisions about what type of supply resources get built or retired, he added.

“Analysis conducted by the Brattle Group on the carbon pricing proposal under consideration, found a slight, short-term increase of roughly $1.50 on the average consumer’s monthly bill,” said Kevin Lanahan, vice president of external affairs at NYISO. “However, the same analysis found that costs drop quickly in the out-years, and produce savings as markets respond,” he added.

The initiative could go into effect in the second quarter of 2021, NYISO has said.

California worships renewables

Many states have ambitious clean energy goals and vague perceptions of the challenges they carry, but none are as far along or as deep into the difficulties as California. The state is forging ahead toward a goal of 100% clean energy by 2045, but to get there it will need new rules and at least some gas-fired power to ensure resource adequacy.

Meeting the target with only renewables and the current storage technology is likely to be too expensive, stakeholders say.

Not every megawatt needs to be clean and green under the state law that set the mandate, and there are certain resources needed for reliability that have a carbon footprint, said Karl Meeusen, senior advisor for infrastructure and regulatory policy at California Independent System Operator.

But while some thermal generation is needed in the short term, the possibilities are endless for the resource mix in the future, Meeusen said. And both Cal-ISO and the CPUC are working on rule changes to help transition to a low-carbon grid.

Getting to 100% clean energy with only wind, solar and short-duration storage is cost-prohibitive because it requires a massive overbuild of the renewable and storage portfolio to ensure reliability, according to Arne Olson, senior partner with consultancy Energy and Environmental Economics.

But getting to 80-90% clean energy can be done without sacrificing reliability, Olson said. “Natural gas capacity will continue to be needed indefinitely barring a breakthrough in nuclear, carbon capture and sequestration, or very long-duration storage,” he said.

While solar and storage will play a major role in California, there is also room for other resources, said Morris Greenberg of S&P Global Platts Analytics. Remote wind in Wyoming and New Mexico could be an important source of clean energy as inland coal retirements free up transmission, Morris said. The state can also rely on in-state hydro, some Pacific Northwest hydro, and California utilities’ share of the Palo Verde nuclear plant in Arizona, he explained.

The CPUC could improve the way the resource adequacy program accounts for the value of projects that combine renewables and storage, said Mark Specht, an energy analyst at the Union of Concerned Scientists. These projects create a value that is greater than the sum of their parts, he said.

Conversely, the CPUC might also need to weigh whether to require longer durations for storage projects to qualify as resource adequacy capacity, Specht said. Current CPUC rules allow four-hour storage to qualify. In many ways, California will be the power sector’s guinea pig for the relationship between clean energy and reliability. Big questions remain in many ISOs about the appropriate generation fuel mix and capacity levels to meet reliability standards, and the answers may hinge on technological advances in storage. However, one of the biggest challenges is establishing the right market design that leads to appropriate price signals to meet those reliability goals.

Reporting by Jared Anderson, Mark Watson, Kate Winston, Rocco Canonica, Jasmin Melvin and Jeff Ryser