The Rules of the Grid: Transmission Policy and Motives Gehind It

Deck: 
Making sense of RTO Week, the mediation talks, and FERC's promised new rulemaking.
Fortnightly Magazine - December 2001


 

Making sense of RTO Week, the mediation talks, and FERC's promised new rulemaking.

Dynegy's senior vice president Peter Esposito didn't think much about the celebrated mediation talks on forming a single, unified transmission grid for the Northeast U.S.

"We spent 45 days talking about process," he said. "We never got to specifics. FERC needs to step up to the plate and tell the RTOs what to do."

Yet that may be just what FERC Chairman Pat Wood has in store.

Just two weeks after he had brought the curtain down on RTO Week, ending the marathon five-day workshop (Oct. 15-19) on the fundamentals of operations and markets for electric transmission at his new-look Federal Energy Regulatory Commission (FERC), Wood was still searching for answers to help him issue the sort of detailed instructions that Esposito and Dynegy longed for.

And, as if not fully satisfied with the ideas that came out of the workshop, Wood on Oct. 30 took the unusual step of lifting the Nov. 5 due date for comments, and asking the industry yet one more time to weigh in with suggestions on how to restructure the electric transmission sector. That set the stage for what was widely expected to be a new, improved, second-chance notice of proposed rulemaking (NOPR) on regional transmission organizations (RTOs). Those new rules, to come out as early as November or December, would set out a clear blueprint of how an RTO should behave.

And not a moment too soon. The original rulemaking, Order 2000, set a deadline of Dec. 15 for RTOs to win final certification. With full compliance looking ever more doubtful, some suspected that FERC would extend that date as well, as part of its second NOPR.

To find the cause for the commotion, look no further than a pair of reports issued in September, and the reactions from utilities, power producers, trade groups, and state regulators. One report came from FERC administrative law judge (ALJ) H. Peter Young, on mediation efforts to create a single RTO in the Northeast United States (NERTO), combining the independent system operators (ISOs) for PJM, New York, and New England. The second concerned mediation talks underway in the Southeast, and was issued by FERC ALJ Bobbie J. McCartney. Those two proceedings show the true nature and depth of the stalemate that so far has blocked progress on the RTO front.

On one side, FERC policy demands that any new RTO must form a board of directors that qualifies as "independent" of market participants, including transmission owners. It is this independent board that must lay down the rules for grid operation and market design. It is this board that must direct the RTO in filing rules and tariffs with the FERC.

On the other, the transmission owners (TOs) want to control the process. They demand the right to set the rules themselves-before handing control of their assets over to the RTO-. The TOs point to Section 205 of the Federal Power Act. They say the law guarantees their right to propose and file tariffs to recover the costs of operating their transmission assets, plus a return on their investment.

So a new NOPR from FERC might be just the ticket. By nailing down a more detailed set of marching orders for RTOs as a backstop, consumer groups and state regulators might prove more willing to trust transmission owners with the job of selecting the RTO board. Or the transmission owners might prove more willing to trust their assets to a board chosen by someone else.

What's at stake? It's not only the grid, but the energy market as well. The industry has come to see RTOs as more than just an air traffic controller for the power lines. It now sees RTO governance and structure as the foundation stone for retail as the very foundation for retail competition in electricity.

Listen to Mark D. Kleinginna, energy director at Ormet Corp., which operates a single plant in Hannibal, Ohio, that consumes 4,500 gigawatt-hours of electricity each year, as he described his predicament on the first morning of RTO Week:

"PJM is the most liquid hub in the world, [but] it doesn't do me a lick of good. ... The rules aren't standardized ... I don't know the rules of the game."

This lack of standard rules worries Harvard Professor William Hogan, widely seen as the godfather of much of the PJM ISO's market design. If left to him, he would likely mandate a PJM-style structure for all RTOs. Without that, he fears a California-style catastrophe in other regions across the country, as he warned FERC at RTO Week:

"We're in the worst of all possible worlds. ... We've opened up, we've given a lot of people choice ... yet we don't have the mechanism to make that system actually work ..."

Hogan challenged Wood either to move ahead or put the toothpaste back in the tube:

"If you're not going to go forward and create competitive markets and put in a reasonable standard market design, then you'd better tell us how to go back to where we were before. And frankly, I've been trying to think about that. How do you go back? I don't know."

But Pat Wood has faith in his plan.

"Save your brains," he told Hogan. "We're going forward. We're not going back."

The Northeast Mediation: Each Region for Itself

Judge Young's "Business Plan" for building a single combined Northeast RTO presented various differing design alternatives for corporate governance and running an energy market-plus timetables and deadlines for completion of key milestones for each plan option, giving his report the look of a strategic planning "action plan"-but in reality the Northeast mediation talks were less about timetables and more about which region or industry sector should control the process.

Speaking for FPL Energy and Sithe Power Marketing, lawyers John Moot and John Estes, from Skadden, Arps, Slate, Meagher & Flom (Washington, D.C. office), painted a picture of doubt and mistrust:

"It was clear from the outset," they said, that "a large number of mediation participants opposed the formation of a single Northeast RTO. It is simply not in the pecuniary interests of numerous parties to move willingly ... to a single RTO."

Enron vice president Thomas C. Briggs wanted PJM to run the transition to a single Northeast grid. As he put it, "PJM's success-in contrast to the problems experienced in New York and New England- warrants putting PJM in control of the going-forward process." Duke Energy echoed that wish, insisting that the combining the three regionswas not a "merger of equals," nor even a "jump ball." While Duke saw the New York approach as "grander in design," it urged that the FERC should take PJM as the "starting point" for a transition to a unified Northeast grid.

Yet Dynegy lawyer Stephen Huntoon was not so sure.

"While PJM is widely acknowledged to be the smoothest operating ISO in the nation to date," he wrote, "it is not perfect."

Huntoon warned that "after $100 million and two years have been spent, we will have institutionalized the defects. There will be little appetite to spend more time and money to fix them."

Board Selection. A key problem for grid consolidation is how to form a board of directors for the new, mega-RTO. Briggs at Enron joined many others in proposing a "5-3-2" board (five seats for PJM and PJM West, three for New York, and two for New England), plus an eleventh voting seat for a CEO selected by the first 10 board members. He rejected the idea of parity (each ISO having equal representation on the board): "It is hard to imagine how putting three equal components of largely hostile boards together to form a new board could be made workable."

PJM defended the 5-3-2 idea by noting that it and PJM West together served 54 percent of peak load in the Northeast region, and claimed 53 percent of both the region's annual sales (megawatt-hours) and installed generating capacity. Yet a group of New York transmission owners said the New York ISO energy market traded $5.2 billion a year, versus $1.7 billion for PJM and $600 million for ISO New England. The TO group also put New York ahead based on net book value of transmission assets-$3.8 billion versus $3.3 billion for PJM and $1.7 billion for New England. PJM questioned whether bilateral sales transactions might have been counted improperly in the comparison, leading to New York's higher numbers. PSE&G carried the issue to extremes, calculating five separate alternative sets of board allocation factors for PJM, New York, and New England, respectively, accurate to one one-hundredth of a board member:

  • Number of Customers-4.9 to 2.55 to 2.59,
  • System Load-5.4 to 2.6 to 2.1,
  • Generation Capacity-5.3 to 2.7 to 1.9,
  • Transmission Miles-4.0 to 3.43 to 2.52.
  • Market Volume (MWh)-6.53 to 1.2 to 2.3.

Another key proposal called for a 3-3-3-4 board, with parity for the three ISOs, plus a nonvoting CEO and four voting seats for various stakeholder sectors yet to be determined, including perhaps a co-called "public interest" sector, to include such interests as renewable energy or environmental concerns. One alternative, known as Option 1-G, did not specify board make-up, but would allow for the three ISOs to keep their functioning boards even while forming a fourth transition board to set up the combined Northeast RTO, creating four potentially conflicting boards that would operate simultaneously.

But however unwieldy, that option drew support from public service commissions (PSCs) in Maryland and the District of Columbia.

Timothy Robinson, general counsel for the D.C. PSC, worried that Option 3-G (a single regional transition board) would leave PJM (and New York and New England) rudderless during the transition, and imperil further progress in market design. Maryland PSC general counsel Susan Stevens Miller picked up on that thread:

"Indeed," she noted, "one of the reasons why the Maryland PSC did not support Option 3-G was its proposal that the boards of PJM and the other ISOs would be replaced ... there would be no PJM board [during the multi-year transition] with the power to make necessary filings under [FPA] Section 205 to address problems or concerns within the Mid-Atlantic Region."

Competitive Comparisons. Some from New York and New England warned that PJM looked good by comparison only because it was "plain vanilla"-they said it lacked load pockets like Boston or New York City needing special attention for second-case contingencies or mitigation of market power. But state regulators in Delaware turned the argument on its head. As they claimed, "the lower two-thirds of Delaware" represented its own load pocket, along with much of the Delmarva Peninsula, thought to be just as bad. "It is a pocket," said the Delaware PSC, that suffered "major outages in 1999, and which, even with subsequent transmission upgrades, will more than likely continue to experience significant congestion." The PSC cited a recent report from the PJM Market Monitoring Unit:

"The Southern Delmarva area exhibits high [market] concentration ... HHI [Hirschman-Herfindahl Index] varies from a minimum of 2370 through a mid-range of 5065 to a maximum of 7750. The DPL South Interface was constrained over 5 percent of on-peak hours. ... Other transmission constraints also occurred ... mostly on the lowest bulk operating voltage of 69 kilovolts, isolating smaller pockets of load."

Yet the fact remained that utilities in New York had sold off 90-plus percent of generating capacity-much more than in PJM-which many said had tended to make generation markets much more competitive, and suggesting that the PJM model might prove a less forgiving model for regional consolidation than otherwise thought.

As the New York ISO added, "Merchant suppliers, which predominate in New York and New England, have different incentives and employ very different bidding strategies."

Stakeholder Influence. Any number of stakeholders demanded all manner of representation, and aimed to sidetrack the mediation talks by spending time and energy on identifying which stakeholder sectors were deemed worthy of representation on the board. Indeed, stakeholder groups in New York and New England had come to the mediation talks with high expectations.

PJM vs. New York: Who's Got the Better Market?

A 10-point analysis of regional differences and how they mesh in a single RTO.

1. POWER FLOWS AND SYSTEM STATUS. "State estimators basically provide a snapshot of the status of the electric system, including the distribution of generation and load, using a partial set of inputs to estimate the status of the entire system.

"The availability of a 'good' state estimator solution is very important. It is a key element in the PJM pricing structure, and a very desirable improvement for New York, which currently does not include state estimation results in their real-time operations, but instead uses [an] assumed distribution of load.

"My conclusion would be that the presence of a state estimator would contribute significantly to improving the ability to secure the reliability concerns that New York has expressed, as New York currently is unable to as accurately estimate the location of load, and thus power flows on its system in real time."

2. VOLTAGE AND FREQUENCY CONTROL. "This is another area where ... the PJM current practice ... would offer significant regional reliability benefits. ..

"Currently, PJM has procedurally integrated AC [alternating current] security runs on a 15-minute basis into its real-time dispatch. That means that operating limits and contingencies may be modified in the DC [direct current] characterization of the dispatch to reflect real-time AC limits.

"New York does not have this capability. Their AC security runs are done off line, and cannot be directly integrated into the real-time dispatch of the system. This means that not only does the New York system have to operate more conservatively, in terms of approaching operating limits and the full utilization of their system, they also face potential operating risks that may not be seen, or are only seen abruptly."

3. UNIT DISPATCH (DAY-AHEAD). "Both PJM and New York run a SCUC [security constrained, unit commitment model] program in the day-ahead market. The same would be true for the RNMC 3-M proposal. Both existing SCUCs attempt to find the lowest-bid cost set of generators that can reliably meet load and reserve requirements while honoring all relevant operating security requirements.

"The PJM and New York SCUC procedures ... both fully accommodate ... reliability requirements ... and would do so if either structure were applied to the other physical market. ... The models are very much the same. ...

"The 'scare factor' of reliability is raised repeatedly ... as a factor to oppose ... a single market. [But] there is absolutely no reason to assume there is any merit to these concerns.

"In New York City, there are a number of double contingencies, some of which are under the control of Con Ed, and not the ISO. These are the 'special' security conditions that New York suggests PJM ignores. The reality is that they are not ignored by PJM. [They] simply do not reflect current PJM operating contingencies with the PJM control area. ... There is no magic here ... just different inputs.

"If Con Ed or PECO for that matter has specific contingencies ... Con Ed and any other transmission owner would be free under the PJM system to establish all reasonable security requirements they feel are necessary."

4. SCUC RUN ALGORITHM. "While the formulations ... in the SCUC software are virtually identical ... PJM's SCUC is able to run faster in general than New York's ...

"PJM solves the problem in an iterative fashion, starting from a reduced set of monitored operating contingencies in a DC representation of the [AC] system. Using this reduced set allows for quick and efficient solution times. "When the problem solves, PJM then subjects the DC solution to a full AC security analysis that incorporates all relevant contingencies. If this AC evaluation 'solves' (finds no security violations), the commitment process if finished. If it doesn't solve (i.e., there are violations of some security contingencies), PJM then utilizes software that analyzes the AC security violations to create modified constraints to be added to the original SCUC problem, and the entire process is repeated. ...

"[Thus] PJM settles the day-ahead market after that initial run, [and] as noted above, mitigation is conducted within that single run. ...

Alternatively, because of the multiple pass process in New York, four or five SCUC runs are needed to complete market settlement [for the] day ahead. This is a major impediment. ... My personal perspective is that while market mitigation requirements for New York City may require two SCUC passes, the current New York multiple pass structure isn't necessary when coupled with full financial bidding. []

"Certainly, a single SCUC run coupled with financial bidding and supplementary security commitments is a reasonable basis for the RNMC design. It couples computational speed with a superior market design approach, while not sacrificing any security requirements."

5. EX POST PRICE ADJUSTMENTS. "Where a difference does exist ... it is not with respect to physical security, but rather with respect to the associated business rules, and [their] impact ... on pricing. Perhaps this is where the confusion arises.

"In the New York ISO market structure, there is no virtual or financial bidding capability in the day-ahead markets. [Editor's Note: The New York ISO has been working to correct this shortcoming, and in fact financial bidding (bidding by buyers and sellers other than physical generators or load-serving entities) was approved for New York by the FERC on Oct. 24.

"As a result, it is necessary to reflect the pricing impacts of additional additional commitments." [i.e., to impose "artificial" or ex post adjustments to market-clearing prices to reflect the impact of generating plants not actually dispatched but dedicated and on call to meet special security requirements.]

"This process is employed because the absence of financial bidding instruments in the New York market would result in a structural arbitrage between the day-ahead and real-time market without it.

"This simply isn't needed in the PJM design ... [with] ... a full set of financial bidding tools. ... In the PJM market structure, the day-ahead market prices clear based solely on participant bids. Any additional security commitments not met through the day-ahead bidding are implemented as needed, but do not affect the day-ahead market-clearing prices."

6. MITIGATING MARKET POWER. "The New York ISO suggests through its Option 1-M plan that the PJM market model, as well as the proposed RNMC, would not be able to accommodate the important market mitigation practices that occur in ... New York, particularly with respect to ... generator market power within New York City. ...

"Again, this is simply incorrect, and misrepresents what actually is happening in PJM today. ...

"In New York, the mitigation is implemented by cost-capping in-city generation units when prices in the day-ahead market in-city exceed a certain price threshold relative to prices at Indian Point. If this threshold is crossed, a second run of the SCUC is conducted using mitigated cost-based rates. ...

"PJM also implements this mitigation by evaluating the existence of congestion in the SCUC results. The only difference is that PJM has implemented a mechanism to effectively re-run the SCUC with the mitigated prices in a single model pass. ... [T]here is absolutely nothing in the procedures proposed for the RNMC that would prevent a 'two-pass SCUC' mitigation process like New York's if the participants desired it. ..."

7. FINANCIAL CONGESTION RIGHTS. "The definition of financial transmission rights in the two markets-FTR's ["firm transmission rights" in PJM] and TCC's ["transmission congestion contracts" in New York]-are the same. These rights entitle the holder to the difference in locational prices between the point of withdrawal and the point of injection of energy.

"PJM allocates these rights ... [they can be resold bilaterally]. ... [T]he rights are initially allocated and extend for one year, with the allocation process [then] being re-initiated. ...

"New York effectively auctions off all transmission rights and allocates the revenues to the transmission owners who then apply these revenues to reduce Transmission Service Charges (the fee mechanism used to recover the fixed embedded costs of operating the transmission system).

"The New York market is very flexible in terms of the ability of the parties to bid for exactly the rights they want ... [while] the PJM annual allocation process precludes the establishment of a meaningful long-term market. This is a key market design deficiency, as it makes long-term hedges for both generators and loads impossible.

"If you want the ability to manage risk on a long-term basis, a clear necessity in a capital-intensive market, you can't have the PJM allocation system. In fact, the PJM committee structure is currently actively considering moving to a market design structure that is similar to what New York and New England have proposed."

8. ICAP AND RESERVE MARKETS. "One difference between the models in the reserve area comes with respect to differences in performance obligations of the units in each market, and associated bidding requirements. ... For example, both PJM and New York obligate generating units that are serving as installed capacity [ICAP] to bid into the day-ahead market. ...

"PJM ... expects such an installed capacity unit to be available to be called (or recalled) by the ISO [on an intra-day basis] if the unit is needed ... PJM compensates generators for such an [intra-day] call through payment of the bid start-up and no-load cost for the unit ... which are in addition to the installed capacity payments. PJM makes no separate availability payment for such an intra-day call. ...

"However, New York does not expect such an installed capacity generation unit that has not been committed day ahead to necessarily be available intra-day. Thus, under the New York market structure, the ISO has to make additional payments to generators to assure this intra-day availability. As a result, in New York generators make availability bids as part of separate reserve bids. ...

"Similarly, New York has separate bids for ancillary services. PJM honors these same ancillary requirements (e.g., the constraints employed by the SCUC are the same), but the products are not bid separately. ...

"There are reasons to argue that the New York process would be more efficient, as it would seem to create a better match of generators to the reliability needs of the system. However, if this efficiency superiority exists, it is very subtle. ..."

9. REAL-TIME BALANCING. "[S]tatements made ... have suggested that the New York market model simultaneously considers all operating contingencies in the real-time dispatch, while the PJM market doesn't. Again, this simply isn't true. ...

"The actual difference ... is that PJM allows for some discretion by generators in selecting when a specific constraint may become binding based on expected changes in system load - e.g., PJM may 'tighten' a constraint in anticipation of rapid changes in load. ...

"This 'subjective' action by PJM is ... analogous to the look-ahead demand evaluated by the New York BME (balancing market evaluation) process ... [and] ... seems to be very much the same as the type of actions that New York operators taken when thunderstorm contingencies are invoked for News York City. ...

"Indeed ... in many instances operators in New York make the exact same type of subjective interventions in the market. The real difference is that in New York, they simply don't advertise these practices. ...

"For instance, often the New York system operator/dispatcher may keep certain units on line, even when these units are de-committed by the SCD (the New York real-time energy market tool). ... This is done because the unit may be needed at a later time, and due to minimum down time requirements, the unit would then be unavailable if de-committed. The SCD model lacks the ability to consider this near-term system reliability requirement, and as a result the operators intervene. ..."

10. UPDATING THE PLATFORM. "It is indeed true that the New York platform is antiquated, in fact my understanding is that some legacy elements predate 1980. [I]t would be a virtually impossible task to update the New York market platforms to incorporate ... new and faster solution engines.

"However, such inflexibility is not characteristic of the PJM market platform and the RNMC proposal. The PJM market platform is modular, and readily allows for the smooth replacement and updating of analytic elements. In fact, only several years ago PJM replaced its SCUC and real-time analytic engines, moving to state-of-the-art solution techniques 'on the fly.'

"[I]n most aspects the PJM software components have been implemented in a modular manner ... the analytic engines 'plug in' to the framework. ...

"These factors that make changes so burdensome in New York are possibly contributing to some of the perceptions by the New York ISO that it is difficult and risky to pursue a path such as the RNMC plan. ..."

At the New York ISO, decision making is shared explicitly by a stakeholder Management Committee that works in tandem with the ISO board. Modification of New York ISO tariffs under the Federal Power Act requires approval of both the ISO board and the Management Committee. And in New England, the ISO works as a matter of contract on behalf of the participants committee of the New England Power Pool (NEPOOL). Such practices were made plain by a group of municipal utilities from New England:

"The most direct way to ensure RTO accountability is to continue to accord decisional rights to RTO stakeholders, including determining whether to make Section 205 filings.

"New England stakeholders have held such rights under the 'sector' voting structure contained in the FERC-approved Restated NEPOOL Agreement."

By contrast, the big power producers and marketers argued that stakeholders must play an advisory role only, with no decisional authority over the filing of tariffs. But the municipal utilities answered from New England:

"Keeping consumers away from the negotiating table," they said, "but expecting them to pick up the tab ... is a recipe for poor decision making and litigation."

Independent Transcos. Even some transmission owners found themselves on opposite sides. Consider, for example, the proposal by more than a dozen electric utilities in the Northeast, including National Grid, representing almost 70 percent of investor-owned grid assets in a new combined Northeast RTO, to create a so-called "independent transmission company" (ITC), operating across 13 states on the eastern seaboard. This group, known as the "ITC proponents," also has engaged in discussions with Hydro One Inc., the owner of most of the transmission system in the province of Ontario. The proponents opposed any idea to give tariff-filing authority to a transition-stage board of directors created to form a new combined NERTO. Presumably, such authority would remain with the owners during the transition.

By contrast, a group of transmission owners within PJM remained leery of granting too much power to an ITC: "Having sat through every day of the mediation process," they saw "many questions left unanswered" about the plan proposed by National Grid.

The PJM owner group talked of one approach by which an ITC might "own or operate the Northeast RTO's entire electric system and exercise all functions of the Northeast RTO other than market administration." The PJM group said it preferred a different construct-an ITC that would own and maintain grid facilities, but leave it to the RTO to be the system operator, service provider, and administrator of market, tariffs, the generator connection queue, and the planning function."

In the end, it fell to the Maine Public Utilities Commission (PUC) to offer the most sanguine advice, urging everyone-and especially the FERC-to keep focused on markets, not interest groups: "In the final analysis, the paramount obligation of the FERC is not to bring about treaties among warring parties ... but rather to establish markets."

Market Design: The Debate Over Best Practice

As Judge Young had defined the mediation process, the right and responsibility to identify, nominate, and define "best practices" in design and operation of markets and market oversight institutions belonged only to the three regional ISOs. Stakeholder groups complained vehemently, but to no avail, of being shut out of the process.

John Anderson's ELCON group, in particular, had argued that best practices could come not only from among the three Northeast ISOs, but also from other regions. For instance, ELCON touted a congestion management system under development in a collaborative process in the Southwest Power Pool as a possible best practice for a Northeast RTO. That system, said ELCON, was based on a "flexible set of financial transmission rights known as 'financial congestion hedges' (FHCs)." As ELCON explained, "these FHCs are designed to promote a liquid and transparent forward market for transmission rights."

New England's Frustration. Another irony lay in the fact that when the FERC in July had called for mediation talks to fashion a consolidated Northeast RTO, the New England ISO had only recently elected to adopt the PJM standard market design (SMD), including locational marginal pricing (LMP) for congestion management.

Thus, it had warned FERC early on that the mediation process might not "produce a timetable" for a single market any earlier than 2003, as under New England's own SMD plan. (Indeed, the New England Conference of Public Utilities Commissioners, known as NECPUC, had said the same thing in August, when it sought to overturn a FERC order that dismissed NEPOOL's proposed SMD plan as "moot," in light of the Northeast mediation process.) Thus, with New England having chosen the PJM design, but having as yet gained no operating experience with it, the battle over market design and the mantle of "best practice" evolved largely into a fight between PJM and the New York ISO.

A Pre-emptory Strike. The One RTO Coalition, led by Mirant, struck the first blow in this battle when it published a study in the utility trade press citing inefficiencies in trading patterns between the New York, New England and PJM ISOs, and claiming over $400 million in potential annual market savings through the creation of a single, consolidated Northeast RTO. ()

The Coalition then made its study a matter of public record by adding it to comments it filed on Judge Young's mediation report. PJM followed suit, filing comments on the same day to which it attached a copy of its own in-house analysis, entitled "Accommodation of ISO-Nominated Best Practices By the Regional Networked Market Model." (The title refers to the "Regional Networked Market Concept," or RNMC, proposed by PJM as a plan to build a market for a single, combined Northeast RTO, included in Judge Young's report as Appendix D. Previously, Judge Young had asked the mediation parties to concentrate on process, and to keep clear of endorsing specific market or operating practices, and indeed to keep the mediation talks confidential).

PJM's Oct. 9 filing amounted to a pre-emptory strike-identifying 40 specific "best practices" nominated by the New York and New England ISOs during the mediation practices to be considered as changes or supplements to the PJM market platform, and then showing how PJM's RNMC proposal would easily accommodate at least 35 of the 40 ideas at the very outset of the combined RTO. Consider one example dealing with transmission congestion contracts (TCCs) and firm transmission rights (FTRs), an area where PJM had been faulted by many for sticking to a system of annual entitlements of transmission rights, rather than an open auction:

  • Best Practice: "New York auctions all TCCs/FTRs."
  • Best Practice: "New York allocates TCCs/FTRs to market participants paying for transmission upgrades that increase transfer capabilities."
  • Best Practice: "New York is developing an auction process which will simultaneously optimize multiple duration TCCs."
  • Best Practice: "In New York, TCCs/FTRs are always fully funded. Any excess or shortfall is covered by the transmission owners, whose rates are automatically adjusted monthly on a formula basis."
  • Best Practice: "New England auctions FTRs and allocates auction revenues to Auction Revenue Rights holders."
  • PJM Accommodation: "TCC/FTR allocations/auctions would be developed for the entire region based on the best practices of New York and New England, if desired by stakeholders. Decisions regarding the FTR/TCC distribution can be formulated in parallel with work on developing a regional market."

And the Pennsylvania PUC only rubbed salt in the wound when it fired a broadside against New York, describing the ISO as a "command-and-control" system:

"The posture taken by the New York ISO in this proceeding, in its adamantine insistence that most of the elements of the New York ISO market must replace PJM's under the guise of being 'best practices,' bodes ill for continued mediation efforts," said assistant counsel John A. Levin, speaking for the PUC.

And Levin further accused the New York ISO of attempting to optimize daily generation dispatch for New York State without regard for its effects on neighboring regions. He claimed that New York and New England each had rebuffed recent formal requests submitted by PJM to obtain historic market data to enable it to create a model to simulate behavior in a consolidated Northeast regional energy market.

"Indeed," said Levin, "it may be impossible for the New York ISO stakeholders to voluntarily accept a regional wholesale market model which relies more upon true economic and congestion signals and less upon centralized planning and dispatch."

The New York ISO responded quickly, declaring that the One RTO Coalition and PJM each had violated the spirit of the mediation process and asked the FERC to strike the comments to the extent they exceeded the maximum allowed length of 10 pages. It quoted consultant Roy Shanker, who stated at RTO Week that New York's market design was, "in principle, superior to PJM's." ()

On Oct. 23, the New York ISO released a study of its own on its Internet site. The study, conducted by economic consultants at LECG, cited the Mirant study as published in , as "seriously flawed," in part because it allegedly confused real-time energy flows with day-ahead prices, and incorrectly assumed that posted prices always reflected the true incremental cost of energy- "an especially problematic assumption for NEPOOL," the ISO said, "which does not yet employ locational marginal pricing."

Into this mess stepped David B. Patton, the Independent Market Advisor for both the New York ISO and ISO New England. In comments filed with FERC on Oct. 9, he cited instances of "inefficient net exports" of power from New York, where it was priced as high as $1200 per MWh, for delivery to New England, where it was priced at $50 to $60. He attributed this nonsensical phenomenon to transmission constraints and to "disappointing" progress among stakeholders in resolving seams issues and establishing a "single scheduler" for facilitating transactions among the three Northeast ISOs- thus appearing to bolster the conclusions of the Mirant study.

RTO Week: More Questions Than Answers

Meanwhile, back at RTO Week, the FERC avoided serious bickering between PJM and New York, but failed to draw a bullet-proof blueprint for RTOs.

As suggested in a prior column on the subject (see, "Camp Flowgate," , Nov. 15, 2001, p. 4), RTO Week exposed a fundamental rift-between those who seek RTOs as performing the limited role of transmission traffic cop, and those who envision RTOs key player in energy markets and resource planning.

Surprisingly, perhaps, the consensus at RTO Week appeared to favor the idea that operating- no, make that "facilitating"-a day-ahead spot energy market marks an essential function of an RTO. Add to that the job of transmission planning, managing the queue for generator interconnections, and designing and filing tariffs for transmission, congestion pricing and ancillary services, and the RTO becomes the major player in wholesale energy markets.

In fact, the one market that was seen as unnecessary for RTOs was the ICAP market (for installed capacity as reserve generation), which one panelist saw as a relic of the rate-of-return regime, and another likened to a social tax enacted to achieve purely political aims. For example, witness Roy Shanker saw ICAP as no more helpful than price caps:

"It's like Lucy, Charlie Brown, and the football. You can tell me you're not going to cap the markets. You can tell me you're going to allow a market response. And the minute the shortage is there, and the prices go through the roof, you pull the football away.

"So we need ... that surplus supply in the market and that surplus is mandated through something like ICAP. It's effectively a tax. You're telling people, I don't care what the market wants, I want extra."

Other issues drawing attention, but no less important, concerned FERC's policy of not incorporating limits on tort liability in federally approved transmission tariffs for ISOs, and the difficulty of determining how to compensate small municipal utilities and cooperatives for the value of small transmission systems turned over to transcos or RTOs-especially for small radial systems built to support a small local distribution system, and that don't make an obvious contribution to regional trade patterns.

As was shown again and again at RTO Week, the wide acceptance of locational marginal pricing (LMP) tends make the merchant generators the most important clients of the RTO. More LMP seems to make physical transmission less important in the scheme of things. It seems to do a better job of incentivizing merchant generators than of helping the RTO identify and plan capital opportunities to upgrade or expand the transmission grid-which, after all, was a key early idea behind the notion of RTOs.

In particular, and perhaps with the Neptune Transmission Project in mind, engineer Masheed Rosenquist from National Grid challenged FERC and her fellow panelists to rationalize the RTO structure with the idea of merchant transmission:

"Planning has been contentious in New England," she noted, "with debate about whether the market creates an efficient result. How do you reconcile a new merchant transmission line that sells its own rights with an RTO policy that favors non-pancaking?"

Vermont regulator Michael Dworkin then added: "You cannot combine a merchant transmission solution with eminent domain rights. State eminent domain laws will require proof that the project at hand is the most efficient alternative, compared with new generation, a gas pipeline or demand-side management, etc. That is why a market solution with eminent domain laws will automatically involve a governmental decision on efficiency and planning."

FERC commissioner William Massey then asked, "Will a strong RTO planning process increase the chance that state officials will approve transmission projects?"

"What makes the data credible," Dworkin answered, "is first a lack of bias and second, technical competence. A commitment to the general public good. And we would prefer to have a lack of bias, rather than just a stakeholder from every conceivable interest group."

Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.