To the Editor:
Bruce Radford’s December 2006 article, “An Inconvenient Fact,” provides a helpful critique of a fundamental element of open-access transmission reform, one of the most important rulemaking cases affecting electricity regulation at the Federal Energy Regulatory Commission (FERC). The possibility of requiring non-RTO utilities to offer efficient balancing and congestion management through a security constrained economic (re)dispatch service including third parties would indeed be a helpful albeit modest reform of current rules. It would remedy an obvious type of discrimination utilities still can use to prevent third parties from gaining comparable access to the nation’s transmission systems. Furthermore, it would provide incentives for other constructive reforms rather than creating arbitrary obstacles to transmission access. However, the discussion of these matters would benefit from clarification of a few simple points.
First, the common element of what your article refers to as the “Chandley/Hogan” proposal for open real-time dispatch, as well at the “Transparent Dispatch Advocates” (TDA) proposal, is that non-RTO utilities should include third parties in an essential transmission service—redispatch—that these same utilities now provide to themselves. Utilities routinely use economic security-constrained redispatch every day to avoid curtailments of their own service so as to reliably serve load. No party has denied this. But they do not typically allow third parties access to the same redispatch to avoid curtailments to serve the third parties’ loads.
Because this transmission service helps avoid curtailments, the provision of this service to some and the denial of that service to others is inherently “undue discrimination,” the problem FERC is statutorily obligated to prevent. Discussion of this topic needs to start from that premise. Redispatch is not sufficient for open access without undue discrimination, but it is surely necessary. Unfortunately, FERC never acknowledges this point in its Open Access Notice of Proposed Rulemaking (NOPR). Ignoring what is necessary ensures failure of the policy.
Second, denial of this essential transmission service is a critical element of undue discrimination. FERC’s focus on how non-RTO utilities calculate essentially arbitrary available transfer capability (ATC) in different ways is trivial in comparison. As you note, the “inconvenient fact” is that standardizing ATC calculations fails to address the fundamental fact that ATC cannot even be defined, much less measured, independent of the dispatch.
Third, and this is critically important to understanding what is going on, FERC persistently ignores the first two points, as well as the physics underlying its explanations of “transmission.” Every control area’s security-constrained dispatch, of which “redispatch” to relieve congestion and provide balancing is an integral and necessary part, is the quintessential transmission service. It is vacuous to talk about “transmission service” without referring to the dispatch. When FERC purports to reform the rules for “open access to transmission service,” but never mentions access to the essential transmission service of (re)dispatch, FERC is either misdirected or misdirecting.
Fourth, those not granting third parties comparable access to their economic (re)dispatch service routinely use security constrained economic dispatch (including redispatch to relieve congestion) to serve their own loads. All control areas use the dispatch to balance the system and use redispatch to avoid violating transmission constraints (congestion). So the question FERC should be asking is: Why don’t the utilities allow third parties access to the same transmission service they use themselves?
Fifth, the arguments in opposition to remedying this fundamental discrimination do not withstand scrutiny. For example:
• It is not true, as APPA charged, that requiring non-RTO utilities to include third parties in security-constrained economic dispatch would impose all of the requirements of FERC’s “standard market design (SMD).” As proposed by FERC, the original SMD rule would have required all utilities to join RTOs, and required utilities to turn over control of their respective dispatches to the RTO. Neither redispatch proposal includes these requirements. To be sure, both proposals would require non-RTO utilities to accept bids for redispatch service and therefore to pay any generators for redispatching. And both would obviously need to charge grid users for the redispatch and balancing energy provided. Chandley/Hogan explain that locational marginal pricing (LMP) is the only consistent way to define these prices (a point on which the TDA proposal seems to disagree). But using LMP is not synonymous with SMD and mandatory RTO membership. The SMD also included meeting reliability constraints and economic dispatch, but these should not be rejected because they were part of SMD. FERC’s proposed SMD rule went much further, including requirements for resource adequacy, transmission planning, independent governance, and so on. In short, the key elements of FERC’s version of SMD that most troubled state regulators are not present in these modest proposals for redispatch.
• It is not true, as Progress Energy claims, that providing access to redispatch would require “confiscating the power supply resources of [the utilities] in order to serve loads that they have no obligation to serve.” The practice in RTOs is to allow any utility to reserve and use its own plants to serve its own loads. They are not required to go further. Only if a utility voluntarily chooses to offer additional power from its plants to the dispatch does the RTO dispatch those plants further to serve the RTO-wide loads. The same voluntary principle would apply in the Chandley/Hogan and TDA proposals. It’s conceptually little different from making “off-system sales,” as utilities do today.
• It is not true that native loads necessarily suffer as a result of including third parties in the redispatch. As your article correctly notes, offering redispatch to all parties does not take away the benefits native loads enjoy, save for their ability to exercise discrimination and exploit monopsony power. Instead, offering redispatch to all parties on a non-discriminatory basis expands the benefits enjoyed by native loads and extends them to all grid users. By expanding the reach of security-constrained economic dispatch and encouraging third parties to be part of (bid into) that dispatch, the dispatch can solve the balancing and congestion management problems that must be addressed for reliability, and do so at lower costs. This is not a zero-sum game; the redispatch proposal enlarges the benefits pie.
• It is not true that a utility granting access to its (re)dispatch would require them to be “insensitive” to “concerns of state regulatory commissions.” Nothing about offering redispatch service to third parties changes any element of state versus federal jurisdiction. And as long as the utility prices the redispatch service correctly (as is done by RTOs), then utilities providing that service are made whole for the legitimate costs of providing the redispatch.
• Finally, SMUD claims that a requirement that non-RTOs offer redispatch service would go beyond the scope of the FERC Open Access NOPR. Yet the NOPR already contains proposals for expanding redispatch service. But even if that were not true, if FERC found undue discrimination in the denial of an essential transmission service (i.e., redispatch), then FERC would have a statutory obligation to remedy that undue discrimination, either in the current NOPR or in another proceeding. SMUD’s claim is therefore beside the point.
There are many details that warrant further discussion. But it is essential that the conversation FERC has initiated be consistent with the realities of actual grid operations and the physics of the grid. FERC shouldn’t embrace the undue discrimination that continues under FERC rules, and parties who claim that remedying discrimination would cause the sky to fall should be challenged to explain their claims. So far, FERC’s NOPR proposals fall short of even this minimalist threshold. Public Utilities Fortnightly performs a substantial public service by informing its readers and keeping on the pressure for an intellectually coherent discussion of transmission service that recognizes the essential aspects of dispatch.
John D. Chandley, Principal, LECG LLC
William Hogan, Harvard University
To the Editor:
In “An Inconvenient Fact,” Public Utilities Fortnightly suggests that “standard market design” is rising from the ashes in the guise of proposals variously dubbed “open dispatch” and “transparent dispatch.” FERC’s request, as part of its Open Access Transmission Tariff (OATT) reform rulemaking, for supplemental comments on the Transparent Dispatch Advocates’ (TDAs) proposal, attests to the seductiveness of these real-time redispatch proposals, particularly the TDAs’ seemingly kinder, gentler version. Who wouldn’t want to get more use out of the frequently constrained grid? What could be bad about requiring transparency in the real-time costs of redispatch? Why not rely on bids to ensure the most efficient real-time redispatch?
From my perspective representing transmission-dependent utilities (TDUs), I am very sympathetic to the underlying concerns that appear to be driving the TDAs’ proposal. TDU efforts to secure reliable, predictable, and affordable power-supply arrangements are too often frustrated by claimed lack of transmission availability. However, the TDAs’ proposal, which would require transmission providers to post real-time redispatch cost estimates, accept third-party redispatch bids, and choose the lowest bid that could most effectively clear a constraint (i.e., operate a real-time bid-based market at congested locations), is not the answer. Because of “inconvenient facts” not adequately addressed by the TDAs’ proposal, it will not achieve the goals espoused by its advocates and, if adopted, would amount to a major, costly, and complicated detour from the course set by Congress in enacting the Energy Policy Act of 2005 (EPACT): creating a robust grid that supports competitive markets and meets the reasonable needs of load-serving entities.
Inconvenient Fact #1: Absence of Needed Cost Certainty. As the TDAs recognize, for redispatch to be effective, it must be predictable and reasonably certain at the time a customer decides whether to take transmission service. However, particularly for the long-term service it claims to facilitate, the TDAs’ proposal provides anything but cost certainty. Indeed, TDAs concede that the level, frequency, and cost of redispatch for a particular long-term transaction cannot be predicted with any precision. The proposed exposure of long-term service to unpredictable, directly assigned redispatch market costs would extend to customers outside of RTO markets the congestion-cost volatility that, as Congress recognized in enacting EPACT’s long-term rights provision, undermines load-serving entities’ ability to commit to long-term power supply arrangements. Customers seeking to lock in long-term generation costs would be reluctant to gamble on long-term transmission service predicated on an open-ended obligation to pay whatever redispatch charges are required in real time, especially where the deck is stacked. The frequency, level, and cost of redispatch over the long term likely will be driven by decisions of the vertically integrated transmission provider (with whom the customer likely competes) as to dispatch, adding or retiring generation, acceptance of additional transmission requests, and upgrading the grid (or not), as well as being influenced by all other factors affecting the dynamic AC grid.
Inconvenient Fact #2: Charges in Excess of the Actual Cost of Redispatch. TDAs also assert that for redispatch service to be effective, it must reflect actual costs. But redispatch prices produced by the TDAs’ proposal will likely be much higher than actual cost.
While the TDAs’ proposal suggests that in non-market environments, real-time redispatch values “can and will necessarily be cost-based,” it in fact permits market-based bids, even from vertically integrated transmission providers, as long as the bidder has market-based rate authority in the control area. Many vertically integrated transmission providers have market-rate authority for energy sales within their control areas, based on control-area-wide assessments of market power. But control-area-wide tests do not measure market power in supplying more targeted redispatch service.
In many cases, very few generators, or perhaps only one, will be in a position to efficiently relieve the constraint, making such generators pivotal. Even if multiple generators can affect the constraint, the high concentration of transmission-provider-owned generation within its control area means that the transmission provider often will be able to name its redispatch price, even assuming it is generally subject to effective competition for energy sales within its control area. In other instances, an independent generator, because of its location relative to the constraint, may have market power with regard to redispatch.
Nor can it be assumed that redispatch prices will be disciplined by customer decisions as to whether to take service. If a customer were foolish enough to have accepted long-term transmission service subject to the obligation to pay for real-time redispatch (as the TDAs’ proposal contemplates), the resulting redispatch price would be subject to no discipline whatsoever. Although this is a recipe for market power abuse, quarterly reports and retention of data for commission audit provide the only monitoring envisioned by the TDAs’ proposal; no constraint-specific screening, mitigation, or monitoring is proposed.
In short, the redispatch markets proposed by the TDAs certainly are not assured to produce anything like the “actual cost” of redispatch, defeating this key prerequisite for effective redispatch service, and undermining its claimed societal benefits. As in the theory underlying the single market clearing price markets used by Day 2 RTO markets, such benefits depend on the assumption that bidding will reflect true opportunity cost—usually short-run marginal costs. There is little reason to hope that such benefits will be produced by redispatch markets operated by and participated in by vertically integrated transmission providers. The Day 2 RTO markets on which the “open” and “transparent” dispatch proposals are modeled (but whose benefits for consumers remain controversial) are at least operated by independent entities, with some (although not necessarily adequate) market-power mitigation and monitoring. By including none of those protections, the TDAs’ proposal all but invites mischief.
Of course, ongoing constraint-by-constraint market power examination, accompanied by mitigation and monitoring administered by an independent market monitor, could be layered on top of the TDA proposal, as could independent operation of the redispatch markets. But then we’re looking at something more like mini-RTOs than the “great taste, less filling” approach advertised by the TDAs.
Alternatively, all redispatch bids could be restricted to cost. But even that approach would bulk up the TDAs’ proposal with requirements for extensive and intrusive auditing. Particularly given the transmission provider’s ability to affect constraints through its dispatch choices, the customer, and FERC, will need the ability to verify the cause as well as the cost of redispatch.
Inconvenient Fact #3: Enhancing Profits From Constraints Won’t Get Transmission Built. TDAs’ statements that the proposal will reveal the value of upgrades and thus encourage construction echo claims that LMP would encourage expansion. But allowing transmission providers to collect real-time redispatch charges, thus creating a new profit center, will hardly induce them to eliminate the constraint and reduce their profits. Experience in RTO markets attests to the failure of LMP signals to create the robust grid Congress has directed FERC to achieve, as the DOE’s National Electric Transmission Congestion Study confirms.
FERC’s OATT reform initiative is on the right track with its focus on regional joint planning. To produce long-needed grid expansion, interactive and proactive regional joint planning should be reinforced by open seasons for joint ownership of major upgrades, elimination of obstacles to crediting of customer-owned transmission facilities, and measures to hold transmission providers accountable for failing to construct and maintain a grid adequate to support the competitive market and meet customer needs. Broadly spreading the costs of broadly beneficial upgrades also should be included on FERC’s agenda. But a proposal that rewards transmission providers that maintain a weak grid with lucrative redispatch revenues (on top of full transmission rates, as proposed by the TDAs) would be a complex and distracting step in the wrong direction.
Cynthia Bogorad, Spiegel & McDiarmid, Washington, DCcynthia.firstname.lastname@example.org
(Ms. Bogorad serves as counsel to the Transmission Access Policy Study Group)