On May 23, 2014, the United States Court of Appeals for the District of Columbia Circuit issued a decision with important implications for the owners of resources used to control the amount of demand a retail electric customer places on the power system − so-called “demand response” (DR) resources − and that seek to be compensated for doing so in wholesale markets. In Electric Power Supply Association v. FERC[1] the D.C. Circuit found that the Federal Energy Regulatory Commission (FERC) exceeded its statutory authority in establishing a uniform set of rules governing the compensation to be paid to DR providers. In nullifying those rules, the court created substantial uncertainty that, until removed, is likely to hamper the further development of DR resources, including those that may be operated by district energy systems.
FERC Order No. 745
FERC Order No. 745[2] established uniform compensation levels for DR resources in wholesale day-ahead and real-time energy markets. FERC directed regional transmission organizations (RTOs) and independent system operators (ISOs) to pay DR resources the full locational marginal price (LMP) typically paid to the owners of electric generating units. FERC justified payment of the full LMP on the ground that DR can supply the same benefits to the grid, in terms of balancing supply and demand, as can generation when dispatched. FERC, however, made payment of the full LMP conditional on the DR resource (1) being able to displace generation in a manner that serves the RTO/ISO and (2) meeting a net-benefits test, which required that the cost of paying the full LMP be less than the beneficial effect on energy prices resulting from the demand reduction provided by the DR resource.
FERC Order No. 745[2] established uniform compensation levels for DR resources in wholesale day-ahead and real-time energy markets. FERC directed regional transmission organizations (RTOs) and independent system operators (ISOs) to pay DR resources the full locational marginal price (LMP) typically paid to the owners of electric generating units. FERC justified payment of the full LMP on the ground that DR can supply the same benefits to the grid, in terms of balancing supply and demand, as can generation when dispatched. FERC, however, made payment of the full LMP conditional on the DR resource (1) being able to displace generation in a manner that serves the RTO/ISO and (2) meeting a net-benefits test, which required that the cost of paying the full LMP be less than the beneficial effect on energy prices resulting from the demand reduction provided by the DR resource.
The D.C. Circuit’s Decision Vacating Order No. 745
The Electric Power Supply Association (EPSA) − which represents the interests of merchant generation owners – sought judicial review of Order No. 745. Among other things, EPSA argued that DR by retail customers is within the regulatory domain of state utility commissions and that, in adopting rules for compensating DR resources, FERC had impermissibly encroached on state jurisdiction. EPSA asserted that, under Section 201 of the Federal Power Act (FPA),[3] FERC’s regulatory jurisdiction encompasses transmission and wholesale power sales in interstate commerce but not retail DR. In response, FERC claimed that the use of retail DR affects electricity prices at the wholesale level, thereby bringing DR within FERC’s jurisdiction under Sections 205 and 206 of the FPA.[4]
The Electric Power Supply Association (EPSA) − which represents the interests of merchant generation owners – sought judicial review of Order No. 745. Among other things, EPSA argued that DR by retail customers is within the regulatory domain of state utility commissions and that, in adopting rules for compensating DR resources, FERC had impermissibly encroached on state jurisdiction. EPSA asserted that, under Section 201 of the Federal Power Act (FPA),[3] FERC’s regulatory jurisdiction encompasses transmission and wholesale power sales in interstate commerce but not retail DR. In response, FERC claimed that the use of retail DR affects electricity prices at the wholesale level, thereby bringing DR within FERC’s jurisdiction under Sections 205 and 206 of the FPA.[4]
The D.C. Circuit agreed with EPSA’s view that FERC’s jurisdiction over electric power sales is statutorily confined to the wholesale market and that, by establishing the prices to be paid for retail customer DR, FERC had exceeded its jurisdiction.[5] The court acknowledged that retail DR can affect wholesale markets and attributed that effect to what is “undeniably a link between wholesale rates and retail sales.”[6] The court, however, saw FERC’s reasoning as placing no limits on its regulatory jurisdiction. If any activity with an effect on wholesale prices comes within FERC’s domain, the court observed, the FPA “could ostensibly authorize FERC to regulate any number of areas, including the steel, fuel, and labor markets.”[7] As for FERC’s argument that the “effect on wholesale markets” logic captured only direct DR participation in those markets, the court rejected the claim, noting that “the directness of participation may be a function of the richness of the incentives” available under FERC’s pricing rules.[8]
While the D.C. Circuit vacated Order No. 745 on jurisdictional grounds, the court also questioned whether compensating DR resources at the full LMP meets the statutory standard of justness and reasonableness. The court expressed the view that “comparable contributions cannot be the reason for equal compensation, when generation resources are incomparably saddled with generation costs. Neither (said the court) may FERC justify its current overcompensation by pointing to past under-compensation.”[9] This aspect of the EPSA decision, though unnecessary to the decision, could prove troublesome for DR providers in their pursuit of equivalent compensation through participation in state-regulated programs.
It should be noted that the outcome in EPSA was not supported by all three panel members. Senior Circuit Judge Edwards dissented, arguing that (1) Order No. 745 requires compensation for DR resources only if their participation actually affects the wholesale electricity market by lowering the market clearing price; (2) FERC relied on a fair interpretation of an ambiguous statutory delegation of authority in Sections 205 and 206 of the FPA; and (3) FERC’s decision to require full LMP compensation for DR resources was not arbitrary and capricious.
Hoping that other circuit members might share Judge Edwards’ contrary views, FERC petitioned for rehearing en banc. In September 2014, however, that petition was denied. FERC then requested a stay of the court’s mandate pending the outcome of a petition for writ of certiorari to the U.S. Supreme Court (and, if certiorari is granted, pending the Supreme Court’s decision). FERC also offered that, if a certiorari petition is not filed, the stay should be allowed to expire on December 16, 2014. The court granted FERC’s request for a stay of the mandate. On January 15, FERC and a coalition of demand-response providers and industrial customers filed separate certiorari petitions seeking reversal of the EPSA decision. Those petitions are currently being considered by the Supreme Court.
Implications for District Energy
District energy systems are well-suited to participate in DR programs, whether at the state or federal level. For example, a district energy system that serves the heating needs of a large building complex also may be able to produce steam that can be used to generate electricity.[10] Such combined heat and power can be configured to function as a DR resource because the electricity produced can be used on-site to reduce the demand that the building complex otherwise would impose on the grid. Such “behind-the-meter” CHP allows a large customer to curtail electricity consumption from the grid in response to a market price signal (economic DR) or to an emergency call from the grid operator (emergency DR), simply by ramping up the electricity production from its CHP facility. Through the compensation it receives for responding to the grid operator’s directives for demand reduction, a district energy system may be able to secure additional economic benefits beyond those derived solely from the more efficient delivery of heating services.
District energy systems are well-suited to participate in DR programs, whether at the state or federal level. For example, a district energy system that serves the heating needs of a large building complex also may be able to produce steam that can be used to generate electricity.[10] Such combined heat and power can be configured to function as a DR resource because the electricity produced can be used on-site to reduce the demand that the building complex otherwise would impose on the grid. Such “behind-the-meter” CHP allows a large customer to curtail electricity consumption from the grid in response to a market price signal (economic DR) or to an emergency call from the grid operator (emergency DR), simply by ramping up the electricity production from its CHP facility. Through the compensation it receives for responding to the grid operator’s directives for demand reduction, a district energy system may be able to secure additional economic benefits beyond those derived solely from the more efficient delivery of heating services.
The EPSA decision, however, leaves a very uncertain landscape for DR resources that rely on being compensated for their provision of DR services. Events before and after EPSA strongly suggest that payment at or near the level of full LMP is crucial to the economic viability of many DR arrangements. The current lack of clarity about whether prices at that level will again be available can be expected to impede future DR development, at least to some degree. By the same token, insofar as the viability of particular district energy CHP arrangements may depend on market-equivalent payments, the current state of affairs casts doubt on whether or to what extent district energy CHP will be able to monetize its DR capabilities. By removing the current uncertainty, a ruling by the Supreme Court in the EPSA decision’s appeal should help district energy operators see more clearly whether participation in the DR market offers an opportunity for additional economic value.
In the meantime, regions that rely heavily on DR for reliability are trying to find creative ways of dealing with the uncertainty created by the EPSA decision. For example, on January 14, 2015, PJM Interconnection, LLC (PJM) filed a “Stop-Gap” proposal that attempts to address the possibility of the Supreme Court denying review of EPSA by creating a new DR capacity product. This new DR product will be a demand-side capacity resource that reduces the amount of capacity PJM procures for the region and will replace current DR supply-side capacity resources. According to PJM, their proposal will not pay retail end-users for DR but instead will reduce the capacity obligations of, and thus the capacity charges owed to PJM by, wholesale entities that commit to reduce their loads in the wholesale capacity market. FERC has not yet acted on PJM’s proposal, and, until it does, uncertainty about DR use in PJM will persist.
[1] Electric Power Supply Ass'n v. FERC, 753 F.3d 216 (D.C. Cir. 2014) (“EPSA”).
[2] Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ¶ 31,322 (2011), order on reh’g and clarification, Order No. 745-A, 137 FERC ¶ 61,215 (2011).
[3] 16 U.S.C. § 824(b)(1) (2012).
[4] 16 U.S.C. §§ 824(d), 824(e) (2012).
[5] See EPSA, 753 F.3d at 219.
[6] See EPSA, 753 F.3d at 221.
[7] Id.
[8] Id. Likewise, the court gave no weight to FERC’s argument that Section 1252(f) of the Energy Policy Act of 2005, which calls for the removal of barriers to entry by DR resources, justified FERC’s action. The court found that FERC went beyond simply removing barriers by dictating the compensation providers of such resources must receive.
[9] See EPSA, 753 F.3d at 225.
[10] Princeton University is often cited as an example of how a campus building complex can use CHP facilities to successfully participate in the market for DR services. Princeton entered into an arrangement with PJM Interconnection LLC (PJM), the regional grid operator, to automatically bid DR in the PJM markets. This arrangement reportedly allowed the university to save more than $2 million in energy costs through the use of its CHP facility. To learn more, see “Princeton University and the Smart Grid, CHP, and District Energy,” a presentation by Thomas Nyquist, director of facilities engineering, Princeton University, at http://tinyurl.com/mqqertm.
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