Here’s a morsel to chew on.
Six months back, when ISO New England was mulling over various reforms that FERC had mandated last fall in Order 719 for the nation’s six regional transmission organizations and independent system operators (RTOs and ISOs are interchangeable terms in this column), the ISO refused point blank to include in its mission statement a proposal by stakeholders that it should operate the bulk power system at the “lowest reasonable cost.”
“The reference to just and reasonable rates is inapposite,” the ISO wrote, in its compliance tariff filed with FERC in late April. Such a requirement, the ISO added, was a “misunderstanding of the ISO Tariff and ISO-NE’s role in the region.”
In particular, the ISO begged off any expertise or authority to opine or judge the merits of any market outcome:
“ISO-NE is not a regulator. ISO-NE is thus not in a position to ensure just and reasonable rates; this is the Commission’s role.”
In fact, FERC Order 719 had instructed each RTO to post on its Web site a “mission statement or organizational charter” to pin down its purpose and guiding principles, plus its “commitment to responsiveness to customers and other stakeholders, and ultimately to the consumers who benefit from and pay for electricity services.”
This directive, of course, was simply one of many. In addition, Order 719 mandated a number of reforms at RTOs, on issues such as governance, long-term contracting, responsiveness to stakeholders (for example, rules on the release of bid-offer data to market participants and state regulators), market monitoring, and most important, demand response and scarcity pricing——the idea of allowing rates during times of reserve shortages to more closely track the “value of service.” (Order No. 719, ¶556, Oct. 17, 2008, Docket RM07-19, 125 FERC ¶61,071).
And not just New England, but each covered organization—PJM, New York ISO, MISO, CAISO, the Southwest Power Pool—has submitted its own compliance tariff, and faces its own unique set of stakeholder issues.
In PJM, for example, the debate centers on market monitoring. Two years after the RTO was rocked by charges of management interference with its then-internal market monitoring (MM) unit (see “Pulling an Inside Job,” this column, May 2007), PJM now has included rules in its own proposed Order 719 compliance tariff that many critics see as having the potential to undo the settlement approved by FERC in March 2008, by which PJM had agreed to restructure its internal MM unit as an external office, independent of management and answerable only to the RTO’s board of directors.
In more precise terms, PJM now has proposed that its management would allow its external MM unit to furnish the RTO with operational data from supply-side resources, known as market “inputs,” but that PJM will choose not to be bound by such analysis when it implements market-mitigation rules under its tariff. Such input parameters ordinarily could include data on generating-unit cost and performance, such as fuel usage, heat rates, plus minimum run and down times, maximum daily or weekly startups, and so forth. FERC (Order 719 had stipulated that RTOs “may” choose to accept such inputs from external MM units, but that RTOs, at the same time, must retain sole responsibility for implementing their tariffs, which contain the rules for conducting market mitigation.)
Opponents now complain that PJM’s post-719 tariff will create a shadow MM unit operating internally within the RTO-management structure—the exact same type of MM structure that was justifiably undone by the settlement order. (See, FERC Docket ER09-1063, filed April 29, 2009, and industry comments filed through July 22.)
Stepping into the fray, PJM’s external MM, Monitoring Analytics LLC, now has offered up its own alternative tariff designed to secure its independence from PJM management.
Joseph E. Bowring, the former PJM internal MM, and now president of Monitoring Analytics, complains that its true role in market monitoring is critical but poorly understood by outsiders. As Bowring explains, his MM team at Monitoring Analytics typically will contact and talk with generators and power suppliers on a daily basis, to discuss and help with their calculations of costs, operational parameters, and market-power tests and screens. The MM, Bowring writes, receives data “directly from participants through its web-based interface, screens the data and discusses the details with each market participant. These negotiations provide guidance to suppliers on what sorts of bids and sell offers will be viewed as competitive and free of taint from market power under RTO-mitigation rules.
“The result,” Bowring declares, “is either agreement or disagreement, well in advance of the auction.
“There is no conflict of interest in the Market Monitor’s role,” adds Bowring.
“Typically agreement is obtained, and the market participant is able to proceed, confident that the MM agreed that the proposed costs or values raise no market behavior or compliance concerns.
“For nearly [10] years the interactions between the MM and PJM market participants have proceeded so smoothly that there has been little cause for those outside of the process, including PJM staff … to understand in detail how the process works and how it serves the joint and several interests of all concerned.” (See, Protest of Independent Market Monitor, pp. 26-32, FERC Docket ER09-1063, filed May 27, 2009.)
The clear implication from Bowring and others is that if RTO management has discretion to ignore the work prepared by the external MM when the RTO implements market-mitigation rules contained in its tariffs, then the entire process will become tainted with potential conflicts of interest.
The Ohio PUC explains: “RTOs should not be vested with mitigation authority as a result of the inherent conflict of interest that RTOs have in imposing mitigation upon their own member companies, whose membership and participation are optional.” (See, comments, Ohio PUC, p. 5, FERC Docket ER09-1063, June 26, 2009.)
The Maryland PSC is even more blunt: “PJM,” it charges, “is vulnerable to profit-motivated pressure from its members.”
Back in New England, in response to Order 719, ISO New England had expanded on a previously published list of objectives and drafted its own proposed mission statement—with a promise to “strive to perform” all its functions and services “in a cost-effective manner, for the benefit of all those served by the ISO.” And further, “to provide quantitative and qualitative information on the need for and the impacts, including costs,” concerning any major ISO initiative that would affect market design, system planning, or operation of the bulk-power system.
But gone missing was any mention of “consumer” or “ratepayer,” though the ISO said it “believed” that the phrase “all those served” implicitly would include “ultimate end-use consumers.”
That omission troubled consumer advocates, state regulators, public-power utilities and others concerned about rising costs for electric transmission-line projects slated for New England—costs required to be shared across the region for projects certified by the ISO as needed for reliability and system operation.
They questioned the ISO’s odd choice of language: “to perform in a cost-effective manner.” Did that refer only to the carrying out of the ISO’s own internal tasks, as opposed to the objective merit of the tariff in question?
The phrase “all those served” also appeared ambiguous. After all, RTOs at their core are transmission-service providers. The PJM tariff, for example, appears to exclude plain-vanilla retail ratepayers from the term “eligible customer,” whom PJM defines as either: A) any electric utility, transmission owner, power marketer, federal power-marketing agency or person generating electric energy for resale; or B) any retail customer taking unbundled transmission service directly from PJM.
And so the public power sector proposed an alternative statement of mission that would refer explicitly to the Federal Power Act and of FERC’s duty to keep rates affordable:
To ensure just and reasonable rates as mandated by the Federal Power Act and as determined by the Federal Energy Regulatory Commission, the ISO shall fulfill its mission at the lowest reasonable cost, consistent with the preceding principles ultimately to the benefit of all consumers who pay for electricity products and services.
Nevertheless, that effort failed to win at a roll-call vote taken April 3, 2009, at the NEPOOL participants committee meeting, leaving the ISO version intact.
Moreover, in defense of its less-committal mission statement, the ISO reminded the industry of its primary duty to plan and operate the bulk-power system, but to let the market decide when it should certify need for new system capacity.
The ISO stressed that it couldn’t determine “the relative costs and benefits of alternatives to transmission and advocate for the alternative with the “lowest reasonable cost. … [That] would be replacing its function as the operator of regional markets with a regulatory role in which it determines the alternatives the meet the region’s needs.”
The ISO saw its role as remaining neutral on the relative merits of competing proposals:
“If the market meets the identified need, through generation, demand response or otherwise, the transmission need determination will be withdrawn … [and] regional cost support will cease.” (See, Filing of ISO New England and NEPOOL in Response to Order 719, pp. 117-119, FERC Docket No. ER09-1051, Apr. 28, 2009.)
This debate, however, might not yet be over. In recent months, industry groups have continued to weigh in on what FERC meant in Order 719. (A decision on rehearing, Order 719-A, was handed down by FERC on July 16.)
Representatives of municipal and co-op agencies in Massachusetts and New Hampshire, for example, still find no solace in that notion:
“The ISO’s unwillingness to include in its mission statement a straightforward obligation to strive to provide or facilitate the provision of reliable service at the lowest reasonable cost has caused consternation among public power representatives.”
And the Connecticut Department of Public Utility Control (the PUC in the Nutmeg State) has commented that cost-effective performance, if at all achievable, must imply by definition the capacity to identify the lowest-cost option:
“If the ISO can assess ‘cost-effectiveness’—as it acknowledges it can—it should be able to determine the relative cost effectiveness of different approaches and choose the one that produces the lowest reasonable consumer costs.”
Any other approach, wrote the DPUC, either ignoring costs altogether or deliberately opting for a higher-cost alternative, would not promote a just and reasonable result.
“ISO-NE cannot feign indifference.”
Another important reform in Order 719 requires RTOs to remove barriers that might discourage participation of demand-response resources in organized energy markets. In FERC’s lexicon, that means treating DR resources “comparably” to generation in markets for energy and ancillary services.
Order 719 raises many issues, such as minimum capacity for DR bids, aggregation of retail customers for DR bidding, metering and communications telemetry required for DR bidding in markets, regulations and other ancillary services.
For example, ELCON (the Electric Consumers Resource Council), would prefer that FERC mandate a uniform, nationwide pro forma DR tariff—the same for all RTOs—the better to accommodate the large, corporate industrial companies who provide the lion’s share of DR services. ELCON has faulted RTO rules requiring telemetry with one-minute metering intervals for DR resources to be eligible to provide regulation and other critical ancillary services, arguing that “comparable” doesn’t have to mean “identical.”
Wal-Mart, however, reports that it recently has installed more than 1,275 advanced metering systems at its stores and facilities throughout the country, enabling individual stores to respond to dispatch signals at one-minute intervals. (Comments of Wal-mart Stores Inc., FERC Docket No. ER09-1063, June 26, 2009.)
Not so much attention has been given, however, to the effect on RTO governance that stems from empowering small-scale end users—transforming them from consumers into full-fledged market participants with a valid stake in RTO politics.
Filing comments at FERC on behalf of Dayton Power & Light, DPL’s chief regulatory counsel, Randall Griffin, sheds light on what it all means:
“PJM once was an unincorporated joint venture … for eight Mid-Atlantic utility companies and staffed by employees of what was then known as the Philadelphia Electric Company.
“But now the pendulum has swung way too far in the other direction. As PJM grew geographically … its membership grew exponentially.
“Currently, because of the way PJM membership and voting rights were established years ago, approximately 60 percent of the voting interest is in the hands of entities that own no substantial investment in generation or transmission … Unless changed, this will only worsen as potentially hundreds of new small generators, retail customers and aggregators of retail customers [ARCs] become members.” (See, Comments of DP&L, pp. 13-14, filed June 26, 2009.)
The PSEG companies observe that municipal co-ops can participate in the transmission-owner (TO) sector by owning less than a mile of transmission, while a large industrial end user can jump ship and join the generator sector “on the basis of a single-on-site generator that sells a small amount of excess power into the grid.”
Constellation Energy explains that on critical matters, stakeholder voting at PJM often splits into two blocs (60-40), reflecting the RTO’s five-sector voting scheme (generators, other suppliers, transmission owners, electric distributors, end-use customers), subordinating generators and TOs to the veto power of the larger (but less-capitalized) three-sector bloc, but leaving neither bloc with enough sector-weighted votes to achieve the required two-thirds majority. The PJM Power Providers Group (P3) commented that the current sector-weighted voting produces “skewed” outcomes “that misinform the board, primarily due to the substantial influence of small coalitions of industrial end users, other suppliers, and municipal utilities.”
PJM’s Task Force 719 sought to break the impasse, but couldn’t reach consensus in time to include any concrete proposal in PJM’s April 29th tariff filing. Thus, PJM has kicked the problem over to its GAST project (Governance Special Assessment Team). One ideal would involve bicameral voting, as in the U.S. Congress, where members would cast votes once as sector members, and then again through an added parallel vote that would be weighted by asset ownership. A two-thirds supermajority still would be required to approve new tariffs.
This problem only will intensify as DR takes hold.
As DPL’s Randall Griffin adds, PJM’s proposal in its Order 719 compliance filing to lower the minimum threshold to 1 MW for DR bidding and market participation could make “tens of thousands of individual, non-aggregated entities eligible for RTO membership, thus blurring the line between wholesale and retail markets.
“What exists today,” Griffin writes, “is a structure where, when sector voting is invoked, Joe Trader and others like him who buy and sell financial transmission rights out of their home offices have an equal vote with the investor-owned utilities.”
In terms of potential complexity, the most ambitious mandate of Order 719 instructs RTOs to modify rules governing price formation during periods of operating-reserve shortage. Thus, FERC wants to allow market-clearing prices during such shortage periods “to more accurately reflect the true value of energy.”
In Order 719, FERC suggested four alternative methods for RTOs to achieve scarcity pricing during a shortage emergency:
• Relax bid caps for gen suppliers and DR providers;
• Relax bid caps for DR bids only;
• Set an administrative demand curve for operating reserves, to allow prices to increase gradually with the extent of the shortage, in a similar manner to the way capacity markets work in PJM (the RPM market) and the New York ISO (ICAP market); and
• Set the market price equal to payments made to providers offering demand resources under an emergency DR program.
Though it says it won’t have a concrete tariff proposal ready to put in place until June 2010, PJM told FERC that it supports the demand-curve method. Potomac Economics Ltd., the independent market monitoring unit for ISO New England, also favors the demand-curve method, in part because “prices are rarely set at the offer cap during shortage conditions.” Potomac explained its view in a report on shortage pricing submitted to FERC at the same time ISO-NE filed its order 719 compliance tariff:
“The demand curve would establish an economic value for reserves that will be reflected in energy prices … the reserve market is effectively the marginal source of supply.” (See, Report on Shortage Pricing of Potomac Economics, FERC Docket RM07-19, filed April 28, 2009.)
It also was noted, however, that an administrative demand curve, working alone, wouldn’t entirely suffice. Rather, Potomac Economics argues that the demand-curve method must be supplemented by some form of FERC’s Solution #4, whereby scarcity prices reflect prices paid to emergency DR resources:
“One example [is] a load curtailment event that occurred in Maine on December 1 and 2, 2007, for a total of 15 hours. During these hours … the hourly average real-time clearing price for the Maine load zone ranged from $89 to $230 per MWh, averaging $131/MWh over the period. …
[But] real-time clearing prices in Maine did not reflect the cost of activating the demand response resources, most of which were paid $500 per MWh to curtail.”
In other words, if markets are clearing only because load is backing off somewhere under a real-time emergency directive from the RTO, outside of the market-clearing algorithm, then any real scarcity pricing solution must be fashioned to accurately reflect and integrate all such out-of-market actions going on behind the scenes.
In their most recent report on the price-responsive demand in New England electricity markets, ISO-NE and NEPOOL note that stakeholder discussions have been focusing on two alternative approaches to deal with power pricing during periods of shortage:
• Supply-side Approach: End users would submit DR bids to reduce load, in a manner similar to supply offers by traditional generation resources.
• Demand-Side Approach: Consumers get the “opportunity” to change consumption levels in response to different energy prices, giving consumers the same option to DR bids as is done by LSEs (load-serving entities). (See, Report of ISO-NE and NEPOOL, FERC Docket ER08-830, July 31, 2009.)
In the New England stakeholder discussions, a fierce debate has emerged over how much the market should pay for load reductions from DR providers.
EnerNOC, a leading DR services company, proposed to integrate load reduction offers into the supply side of the energy market, with a price paid to DR providers equal to “LMP – G” (the locational marginal price minus the generation portion of the retail rate charge to the DR provider).
This retail rate offset (G) stems from the idea that the end-use customer providing the load reduction is somehow being compensated by not having to pay to receive a delivery of electricity service. Otherwise, as goes this analysis, the DR provider will end up receiving a “double payment” for reducing load—an argument seen frequently in discussions of demand-side resource theory. (See the earlier column, “Demand-Side Dreams,” November 2007.)
By contrast, however, the Consumer Demand Response Initiative, an informal coalition of businesses, trade associations, and non-profits represented by attorney Donald J. Sipe, argues that this “double-dipping” notion is fallacious, and that DR providers should be paid the full market-clearing price, without any offset keyed to the retail rate.
CDRI notes—correctly—that a load reduction offered by a DR provider is indistinguishable from self-generation operating behind the meter. Thus, as a self-generator should be paid the full market-clearing price for energy for its output, so too should a DR provider earn the full LMP without any retail rate offset.
As Sipe explained in the comments, the true value of demand response comes from the consumer surplus generated for all other end users, because the DR load reduction has reduced locational market-clearing prices across the board. (See, Comments of Consumer Demand Response Initiative, p. 8, FERC Docket ER09-1051, filed May 26, 2009.)
That, of course, was the point FERC commissioners Jon Wellinghoff and Suedeen Kelly were making back in 2007, when they dissented in a FERC order that killed off PJM’s economic load-response program, charging that the FERC majority had mischaracterized PJM’s DR payment as a subsidy, and had “squandered” an opportunity to develop policy on demand response and scarcity pricing. (See, Docket EL08-12, Dec. 31, 2007, 121 FERC ¶61,315.)
As Sipe argues, there’s no need for any netting out of the avoided retail cost, on the misguided theory that consumers who agree to interrupt during shortages are somehow benefitting.
“The service provided is not the mere avoidance of consumption,” he writes, “but the willingness to coordinate service interruptions with the grid operator … to balance supply and demand in a fashion that maximizes consumer surplus.”