Power players muster forces for electricity market reforms

Source: Rod Kuckro, E&E reporter • Posted: Tuesday, April 22, 2014

The behemoths of the electric power sector are pushing federal regulators hard to enact reforms in East and Midwest markets that they say would strengthen the reliability of electricity supply and shore up their bottom lines.A central focus of the reform efforts is the capacity market in the PJM Interconnection, which oversees the wholesale electricity business in 13 states and the District of Columbia.

In a capacity market, generators receive compensation for investing in power plants. Load-serving entities — the market participants that secure electricity, transmission and related services for end-use customers — make the payments to generators to ensure the long-term availability of sufficient capacity for the reliable delivery of power. The amounts of the payments are set through an auction.

The reforms are intended to shut down speculation in the markets and the ability of power generators to engage in arbitrage between PJM and neighboring markets. They are also squarely aimed at raising the amounts of money that market players can obtain to keep their electricity generation resources in service.

“Those are incredibly important reforms; they’re just necessary to keep the boat from sinking,” said Joseph Dominguez, Exelon Corp.’s senior vice president for governmental and regulatory affairs and public policy.

With the nation’s largest fleet of nuclear power plants, Chicago-based Exelon is among the group of investor-owned utilities operating in markets whose usually circumspect executives have been taking every opportunity to issue dire warnings about the harm to their business and customers. In addition to outdated market designs, they blame a combination of canny energy traders, the emergence of low-cost natural gas as the preferred fuel for power generation, subsidies for renewable power and flagging demand for electricity.

“The level of concern and complaints about the markets has gotten louder,” said Paul Patterson, an analyst with Glenrock Associates.

The first complaints from the C-suites were heard in recent quarters during conference calls with Wall Street analysts on earnings, when executives would point to broken market designs to help explain disappointing financial results.

Next, FirstEnergy Corp. CEO Tony Alexander used an industry conference to press the point. Speaking before the National Association of Regulatory Utility Commissioners in February, Alexander blasted the outcome of recent capacity market auctions, saying, “You can’t have major power plants not in clear capacity markets year after year after year.”

Alexander was referring to the phenomenon where wind power, natural gas and efficiency resources often have been able to knock more-expensive-to-operate nuclear and coal-fired plants out of contention for future capacity supply by bidding into auctions — and clearing — at a lower price.

In recent months, similar sentiments about price suppression and other defects in the markets have been expressed by Entergy Corp. CEO Leo Denault, American Electric Power Company Inc. CEO Nicholas Akins, Exelon Corp. CEO Christopher Crane and Dominion CEO Tom Farrell.

What the companies have in common are fleets of so-called unregulated power plants that operate in one or more of the competitive markets such as PJM, the Midcontinent Independent System Operator (MISO), the New York Independent System Operator and ISO New England.

While their specific concerns vary from market to market depending on the makeup of their generation fleets, they share a view articulated by Entergy’s Bill Mohl, president of the company’s wholesale commodities unit.

“The ISOs has taken the position that all they have to look at is the short-term markets. If you look at the way utilities planned historically, they looked out a long period of time and did centralized planning. The ISOs say, ‘That’s not our job; we’re not going to do that.’ As a result, they’re focused on short-term markets, and now there are unintended consequences,” Mohl said.

Those unintended consequences include the decision by Entergy to close its 620-megawatt Vermont Yankee nuclear plant later this year. Factors cited by Entergy in the decision included sustained low natural gas prices and wholesale energy prices, a high cost structure for a single-unit plant and “wholesale market design flaws that continue to result in artificially low energy and capacity prices in the region, and do not provide adequate compensation to merchant nuclear plants for the fuel diversity benefits they provide.”

For similar reasons, Dominion closed its 556 MW Kewaunee nuclear plant in Wisconsin last May, and Exelon has said it will decide this year whether to shutter a handful of no-longer-profitable nuclear plants.

Historically, the nation’s 100 nuclear reactors have been the most reliable generators of so-called baseload electric power with their ability to operate around the clock. Moreover, the industry touts their value as carbon-free sources of electricity that are needed if the nation is to meet its goals to reduce greenhouse gas emissions. And more recently, owners of nuclear plants have cited their benefit of having at least a year’s worth of their uranium fuel on site to help anchor grid reliability.

That availability of on-site fuel also is cited by owners of coal-fired generation who want to see their resources regain value in power markets where natural gas generation has been setting a lower marginal wholesale price.

FERC facing short-term, long-term fixes

The Federal Energy Regulatory Commission opened a docket in 2013 on possible capacity market reforms and held an all-day technical conference in September. The conference was followed by reams of comments that are being analyzed and could result in one or more rulemakings.

A subsequent technical conference April 1 on how the markets performed during the extreme cold in January and February featured executives from each ISO and others interested in seeing FERC act to prevent price volatility and supply issues before the next winter.

A recurring theme during the conference focused on how the record winter demand for power might have been less costly had ISO market designs been more effective in promoting the construction of new generation resources.

At the close of the April 1 meeting, Acting FERC Chairwoman Cheryl LaFleur issued participants a challenge to come up with solutions (EnergyWire, April 3).

“I was just issuing the kind of stern warning that ‘Hey, it’s already April, and if we’re going to do it by next winter, we all — FERC and the people who file things at FERC — have to get on with business,'” LaFleur said in a recent interview.

Among the near-term actions FERC could take would be to allow intra-day bidding by generators and align the times of day when the electricity and natural gas markets trade to promote better coordination.

“I do think we have time to make course corrections to help us going into next winter,” LaFleur said.

But, “if we’re going to change the capacity markets in some way to price in fuel security, that’s not something I would do over a few weeks period; that’s a longer-term issue,” she said.

Pending rule changes seek to keep ‘boat from sinking’

There are a few changes to the PJM market pending at FERC that the industry would like to see enacted sooner rather than later. In fact, the industry would like to seek them approved in advance of the next so-called base residual auction that procures capacity for a period three years away, in this case for a year spanning 2017-18. That will occur on May 12.

One proposal seeks to end speculation by providers of demand response, existing generation and owners of generation in neighboring ISOs.

PJM had noticed an “increasing trend where folks were clearing in the three-year forward auction and then purchasing replacement capacity [in subsequent incremental auctions],” said Andrew Ott, PJM’s executive vice president for markets. “There’s a financial incentive to do that because what we’ve seen is the incremental auction prices are lower than the three-year forward base auction. People can get paid the base price — let’s say it’s $100 — and if the incremental auction price is $20, they can buy a replacement at $20 and keep the $80 profit,” Ott explained.

The PJM proposal wants offers in the base auction to be physical — to represent resources intended for delivery, Ott said. “It takes away that financial incentive to replace by saying that you can’t keep the profit. You can’t just walk away from your commitment and expect to profit from that transaction.”

Another pending proposal, Exelon’s Dominguez believes, would “clear out of the market fake megawatts, megawatts that arbitrage” by bidding into the PJM auction from another ISO. He used as an example a generator in MISO, whose capacity market procures capacity only one year ahead.

“If I’m sitting in MISO, I can bid my capacity into the PJM market on a forward basis for the next auction that will cover 2017, 2018. Then, two years from now, I could bid the same capacity into the MISO auction and see if I can get a higher price. If I get a higher price, I go back to PJM and pay the penalty or buy replacement megawatts in the incremental auction. And I’m done. You have essentially bid the same megawatts to two different markets, waiting for the higher price,” leaving PJM short, Dominguez said.

“So the reforms that are at FERC are going to prevent that. They will prevent the diversion of resources that are committed into one market. In other words, you get one bite at the apple,” he said.

PJM eyes new auction to meet peak winter demand

To address longer-term concerns, PJM has launched an analysis of whether to institute a new capacity market auction that would help meet future peak demand for electricity in the winter, according to Ott. Like the base auction, a winter auction would procure capacity three years out, he said.

A key design element of a winter auction would benefit owners of nuclear and coal-fired plants with their on-site fuel supplies. Natural gas prices spiked during the polar vortex in early January and during subsequent cold weather, pushing the price of electricity to record highs in New England and elsewhere. The cause was the diversion of gas supplies from power generators — which did not have firm contracts for the fuel — to local gas companies for heating.

“What this would do is say is that a certain amount of capacity has to have a firm fuel requirement [to bid into the auction]. That could look like a gas unit with dual fuel [gas and fuel oil], a coal unit, of course, and a nuclear unit. But it would say a certain minimum percentage would have to have a dependable fuel capability. And that, of course, would not include a unit that is just pure gas, because obviously there can be interruptions there even if they have firm gas, because there can be interruptions based on the interaction of the gas and electric markets,” Ott said.

The analysis also will “look at the next two winters, and we’ll establish this reliability target — for lack of a better term right now — we’ll call it a firm winter fuel capability. Do we have enough or not? Obviously, if we determine we don’t have enough, we could hold an incremental auction,” Ott said.

The analysis should be done by midsummer, “well in advance” in case rule changes are needed from FERC, he said.

One option for PJM during a transition period while more gas pipeline infrastructure is built might be to provide additional compensation to nuclear and coal-fired plants, Dominguez said, so “we’re not depending on gas arriving at 22 miles per hour through an interstate system that could be curtailed.”

Generators’ lobby weighs position

Asked if there might be some resistance among wholesale market participants — especially owners of gas-fired plants — to the types of reforms PJM is pursuing, Dominguez suggested “power producers have overestimated their ability to ramp generation or to bring all of their megawatts to market during times where the megawatts are called.”

The types of reforms PJM “is talking about will eliminate the overforecasting of the capability of some units, and some people will not like that,” he said. “But the overwhelming majority of participants in the market want to have transparency. And the lack of transparency has caused a real problem for retailers and customers alike.”

The Electric Power Supply Association, which represents competitive generators — including the likes of Entergy and Exelon — is “actively talking about it with our members right now,” said President and CEO John Shelk. “We don’t have a policy on it.”

“The devil’s really going to be in the details of these different ideas. And that’s what we’re really trying to do internally now is to kick around what are the questions that FERC would encounter if they were to pursue something like this or any of these other options,” Shelk said. “It’s that kind of level of detail that folks are only now starting to talk about.”

He cautioned that there has to be a focus on more than just reform of capacity markets, which he estimated provide about 15 percent of a power plant’s revenue.

As important or more is reform of the energy market, the real-time and day-ahead buying and selling of electricity, which accounts for 80 percent or a plant’s revenue, as well as the so-called ancillary services market, which provides about 5 percent, Shelk said.

“If you only look at capacity markets, then you’ve missed a large chunk of the revenue that needs to be there for companies to make sound investment decisions,” he said.

In the past couple of years, “all the focus tends to be capacity markets — that’s where the controversy has been. And while they are important to reform, if you don’t do something about how energy is generated and sold on an hourly basis in real time, you’ve missed a large part of the problem,” he said.

Entergy’s Mohl and Exelon’s Dominguez also advocate reforms in the ISO energy markets, something that isn’t even on FERC’s radar at the moment.

“We’re really headed off the cliff if somebody doesn’t take some leadership and take a look at what’s happening now and what’s going to happen in the long run,” Mohl said. “I think FERC is probably best positioned, since they have jurisdiction over the markets.”

“The polar vortex was a wake-up call, and it’s gotten people’s attention. But nobody is taking the lead in pulling together a common group of stakeholders to come up with a reasonable solution on how to address this in the long run. ISO New England, PJM, MISO, New York — all are facing the same challenges to different levels.

“There will be winners and losers” after market reforms, Mohl said. “But the last thing we want is that it takes a reliability event to get everybody’s attention.”