FERC Order 745 and the Epic Battle Between Electricity Supply and Demand

From its modest origins as a way to shed load when the grid is stressed, demand response (DR) has grown to be a significant player in electricity markets. In the PJM region, demand response has accounted for as much as 14,833 MW of capacity, almost 10% of the total.

Customer Gains and Generator Losses

Demand response has had a huge effect on market prices, shaving off the lucrative peak periods when generators could count on their biggest rewards. In 2013 alone, it delivered $12 billion in customer savings in PJM.

But savings to a customer look like revenue losses to energy generators. This above all has resulted in a massive pushback against demand response.

Nicholas Akins, chairman, president, and CEO of American Electric Power, has been especially vocal in his opposition to demand response. In congressional testimony in April 2014, he complained that “demand response continues to be paid similar capacity prices to steel-in-the-ground generation.” (For more on AEP and its responses to a changing market, look for “American Electric Power: A Coal Powerhouse Repositions Itself” in the February 2015 issue of POWER and at powermag.com.)

“The competitive wholesale markets are not currently providing the structure necessary to maintain reliability and do not currently provide the proper economic signals to foster new power plant investment for the future,” he said.

“The real value of steel-in-the-ground capacity must be recognized in the competitive markets. Insufficient revenues from both the capacity and the energy markets mean additional nuclear and fossil generation may be retired.”

According to AEP, over the last 10 years of forward capacity auctions, the average clearing price has been $90/MW-day, less than 30% of the Net Cost of New Entry (CONE), a measurement based on the estimated cost of building a new gas power plant. This “may not be enough to sustain existing units, let alone entice new construction,” Akins lamented.

War on Demand Response Is Declared

This saber rattling has now erupted into a full war.

The Electric Power Supply Association (EPSA), the coalition of major generation owners, filed a lawsuit alleging that the Federal Energy Regulatory Commission (FERC) overstepped its jurisdiction over wholesale markets when it issued Order 745. This foundational order, promulgated in 2011, established that demand response must be paid the same as supply side resources.

EPSA was joined in the suit by the American Public Power Association (APPA), the National Rural Electric Cooperative Association (NRECA), and the Edison Electric Institute (EEI).

In a verdict that surprised many, in May 2014 the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) ruled in EPSA v. FERC that demand response was a retail transaction and, thus, subject only to oversight by state utility commissions. It also found that Order 745’s decision to require payment of full locational marginal price (LMP) was “arbitrary and capricious” under the Administrative Procedure Act. The court thus vacated Order 745 in its entirety.

In the order, the court said “Demand response—simply put—is part of the retail market. It involves retail customers, their decision whether to purchase at retail, and the levels of retail electricity consumption. . . . A buyer is a buyer, but a reduction in consumption cannot be a ‘wholesale sale.’ FERC’s metaphysical distinction between price-responsive demand and incentive-based demand cannot solve its jurisdictional quandary.”

“At the end of the day, we believe demand response is a good tool for managing load. But we don’t believe it belongs in the capacity markets,” said John Shelk, president of EPSA. “Because if it continues to be bid into a capacity auction, its going to continue to depress that market and it’s going to lead to more premature closures of power plants.”

FERC Commissioner Phil Moeller dissented with Order 745 when it was released, arguing that the rule would over-compensate DR resources relative to traditional generation resources because DR resources would receive both the LMP and the savings from not buying the energy.

“Demand response isn’t new,” countered Audrey Zibelman, chair of the New York Public Service Commission, in an interview with POWER. “Utilities forever have operated under the philosophy that if you have customers that would voluntarily interrupt, that was a much more efficient alternative than building a peaking plant that would run only a few hours of the year.”

“The fact that markets reflect that economic value shouldn’t be a surprise to anyone. I think what was a surprise to everyone was that it was a surprise to the courts.”

The U.S. solicitor general, who argues cases involving the federal government, has agreed to appeal the ruling to the Supreme Court. On Oct. 20, the D.C. Circuit granted a stay of the decision to vacate Order 745 until Dec. 16, and on Dec. 5, a further stay was granted until Jan. 15. PJM has decided to continue including DR in its capacity auctions (RPM) until the courts have settled the issue.

FirstEnergy has taken the battle one step further, filing a complaint with FERC demanding that PJM nullify the current capacity auction results, announced earlier this year, for delivery in 2017/18—and to rerun the auction with no demand response.

FirstEnergy calculates that removing demand response would more than double the price of PJM capacity, from $120/MW-day to $282/MW-day. That would increase the cost of capacity in the 2017/18 delivery year from $7.5 billion to $16.8 billion.

Workarounds

If the legal appeals are not successful, and FERC loses its ability to promote demand response, stakeholders are already discussing a few workarounds.

Zibelman, who was previously the chief operating officer at PJM, thinks there are regulatory maneuvers that can resolve the issue. For one thing, states clearly have authority to promote demand response. “Can the states delegate to the wholesale markets the value of the demand reduction if they choose to do so?” she asks. “Why would the Federal Power Act interfere with that right?”

“It should be a matter of choice for the states,” she argues. “If New York wants to do demand response as a load modifier, it should be allowed. If Maryland wants to participate in wholesale markets with DR, that should be allowed too.”

“It’s not that FERC is getting into the retail level, it’s that the states are choosing to use the wholesale market” to implement demand response, she says. Mid-Atlantic states “are reliant on PJM to implement their DR policies. If it is not offered as an option, it disrupts their market.”

Another strategy is to redefine DR as a load reduction, subtracting it from customer needs before buying capacity, rather than as a resource on the supply side. This would take DR out of wholesale markets altogether, sidestepping the legal issues.

“If you can monetize the value of demand reductions, the market will optimize for the remaining need,” Zibelman said. “Demand becomes the first resource, and the market meets the residual supply.”

Also, states can take over implementation of DR on the retail side. When the court order came out in May, DR provider EnerNOC anticipated “state regulators to take a much more active role in facilitating demand response activity.”

“Whether demand response participation in energy markets becomes the sole jurisdiction of state regulators—who have traditionally been significant supporters—or remains subject to a combination of state and federal regulation, it is likely to be a topic of continued debate on any appeal,” it said. “EnerNOC expects demand response solutions will continue to deliver major economic benefits to consumers of electricity under either scenario.”

New York has begun to take steps to ensure there is no gap in DR operations, opening a new proceeding on Dec. 17 “to develop programs and tariffs for electric utilities to be implemented statewide in summer 2015.”

Lastly, Senator Martin Heinrich (D-N.M.) has proposed federal legislation that would clarify FERC’s authority to promote demand response. However, in the deeply divided Congress, few observers expect rapid action on the bill.

PJM Capacity Performance Effects on DR

Another front has opened in the DR battle, around PJM’s proposed changes to its capacity markets, creating what the system operator call a “capacity performance” system.

In response to the “polar vortex” storm of Jan. 6–8, 2014, PJM has proposed significant changes to its capacity market, with big implications for demand response. (See “PJM Tightens Capacity Market Rules to Improve Reliability.”)

PJM offers three “economic” DR products, in addition to emergency DR. The Limited and Extended Summer products are geared toward air conditioning and other summer resources, while Annual DR is available year round.

During the polar vortex, PJM put out a request for emergency curtailment, and customers came through by dropping 1,911 MW of demand. But because these were voluntary responses, not bound by DR contracts, PJM is concerned that they may not show up when needed in the future.

“The significant value provided by Demand Resources during these winter events and the lack of performance obligation demonstrates a need” to make them mandatory, it wrote in its Dec. 12 filing to FERC on capacity performance.

To do so, PJM proposes to eliminate the seasonal DR products and replace them with a single year-round product, with much more stringent requirements. DR resources would now “be required to reduce load on any day of the year, for an unlimited number of interruptions,” and curtailments “will no longer be limited to a maximum of 10 hours in duration.”

The Advanced Energy Management Alliance (AEMA), composed of Comverge, EnergyConnect, EnerNOC, and Walmart, opposes the changes.

“Introduction of a new product will disrupt the physical and economic success that the RPM has provided the system, and will improperly negatively impact many resources that have performed reliably and consistently,” the group wrote in filings. “Rather, PJM can accomplish its objectives with more tailored reforms specifically targeted at the resources and issues that created the reliability issues this past winter.”

This view is echoed by Regulatory Assistance Project analyst Michael Hogan. Speaking at a meeting of the Mid-Atlantic Distributed Resources Initiative, a coalition of eastern state utility commissions, on Dec. 9, Hogan’s criticism of the changes to DR policies was unalloyed. “The top priority has been speed of implementation and fighting the last war,” he told the audience of regulators and stakeholders. “The plan is perfectly matched to the needs of the 20th century.”

By dumping Limited DR, PJM is losing its ability to affect the much larger summer peaks. “Doesn’t PJM’s system still peak in the summer?” he asked. “It would have been more efficient to address winter peaks by creating an Extended Winter DR product.”

But Ott said there were getting to be too many products. PJM is seeking a sustainable long-term solution where innovation is encouraged in the marketplace, rather than having PJM tailor products for every niche.

“That’s a more robust way to define the wholesale market, to allow the innovations to happen commercially,” he says.

Besides, he added, DR can also be part of coupled deals, marrying winter and summer resources to create one annual whole. As PJM wrote in its filing to FERC, requiring “such resource combinations has great promise to incent the development of new technologies such as storage resources which can complement wind, demand response, and energy efficiency products.”

Bruce Campbell, spokesperson for AEMA, was skeptical. “Coupling is an interesting idea,” he told POWER. “It’s one of those things that works in theory but it’s not at all clear that it works in practice.”

In a UBS analyst report from Dec. 7, Julien Dumoulin-Smith says he thinks that tighter rules will limit the amount of DR available overall. Though PJM says it favors Annual DR, which is currently supplying 1.5 GW of resource, it “could be reduced materially” by more stringent performance and binding standards, according to Dumoulin-Smith.

“More stringent standards on capacity participation (including DR) could yet serve to meaningfully drive out this resource,” he wrote.

PJM has proposed eliminating the summer-only Limited DR immediately, accounting for about 2.3 GW of reduction. The largest form of DR, Summer Extended, accounting for 7.1 GW last year, would continue to be allowed through the transition period but would be phased out by the 2020/21 auction.

“Net-net, we estimate at least a ~2GW decline (~$15/MW-day impact) in the auction just from [capacity performance] reforms alone,” Dumoulin-Smith concludes.

If successful, the court challenge to FERC Order 745, which threatens to derail demand response entirely, would have an even bigger impact. Dumoulin-Smith estimates the loss of nearly all demand response in PJM to be worth $62/MW-day. PJM’s Ott thinks losing half of DR would boost capacity prices by $30 to $50/MW-day.

In the end, Ott thinks this won’t happen. “Demand response is already physically there and shown that it can deliver, so it will find a way to survive.”

—Bentham Paulos is a freelance writer and consultant specializing in energy issues.