FERC's AEP ruling begs the question: Can the feds bypass states that block transmission reform?
In its search for the perfect power market, the Federal Energy Regulatory Commission (FERC) at last has joined the battle that lately has brought state and federal regulators nearly to blows. A recent ruling puts the question squarely on the table:
- n Can FERC overturn orders issued by the state public utility commissions (PUCs) that otherwise would stand in the way of its vision of regional transmission organizations (RTOs) with a standard market design (SMD)?
Such authority would come from Section 205 of PURPA-the Public Utility Regulatory Policies Act of 1978-which permits FERC to "exempt" electric utilities from compliance with problematic state mandates that might otherwise interfere with the unobstructed coordination of power movement across the interstate transmission grid. And FERC now has invoked Section 205 in no uncertain terms. It did so in a ruling issued late last year, by which it exempted American Electric Power Co. (AEP) from contrary instructions from Kentucky and Virginia, and compelled AEP to join the PJM RTO and to participate fully in PJM market structures, including: (1) the day-ahead and real-time markets for energy and ancillary services; (2) locational marginal pricing (LMP) for market-based management of grid congestion; and (3) centralized (RTO-directed) deployment of power plants and resources under the PJM protocols for bid-based, security-constrained unit commitment and dispatch.
Of course, Section 205 does give some immunity to state regulators. They can enforce their mandates against any purported exemption from FERC, so long as the state ruling is required to: (a) satisfy a requirement issued by some other federal law or agency; (b) protect the environment or guard against a fuel shortage; or (c) ensure the public health, safety, and welfare of the citizens of the affected state.
(And by the way, one might wonder why Congress had thought that the nation's utilities should ever desire an exemption from state regulation. But yes, Virginia, there was a time, back in the late seventies, at the time of PURPA, when Congress saw FERC as a friend to utilities, and the state PUCs-remember prudence reviews?-as their natural adversaries.)
Seizing on this fine print, regulators in Virginia and Kentucky had claimed that their situations meshed exactly with loophole letter "C"-that their states had imposed full economic regulation for traditional, bundled retail utility service, and that such regimes, essential for the "public welfare," would suffer under FERC's exemption. Those two states argued vociferously that FERC under no circumstances could "exempt" electric utilities from a constitutional exercise of state jurisdiction.
Yet FERC had anticipated the arguments from Virginia and Kentucky in its 55-page AEP ruling. Toward the end of the opinion, FERC explained carefully that when Congress had carved out those state-friendly loopholes in Section 205 back in 1978, it was thinking about things like air pollution, land use, and zoning. By contrast, said FERC, the legislative history from the late 1970s showed that when Congress drafted PURPA, it had never intended that protection of a state's system of economic regulation of electric utilities would qualify as an element of "public welfare" deserving protection against FERC's pre-emptive power described in Section 205.
And so it has come down to this:
By order of FERC Administrative Law Judge William J. Cowan, hearings will now begin Jan. 26 on whether FERC can rely on PURPA Section 205 to bring AEP to heel as a full-fledged market participant in PJM. But Virginia and Kentucky have balked, demanding an extension of time to prepare the defense. As those two states explained in their motion filed on Dec. 10, "this case represents the first time in the 25-year history of section 205 of PURPA that [FERC] has invoked that provision to exempt an electric utility from state law. … [T]he commission has never sought, until this proceeding, to utilize this statutory provision to preempt state law, let alone the laws of two sovereign states simultaneously."
Can this be so? Can FERC simply sidestep state opposition under the guise of creating the perfect power market?
Origins of Policy
The perfect is often the enemy of the good. Whether this proves to be the case with FERC is a question worth pondering.
The trouble began when certain former utility members of the now-defunct Alliance grid group announced their choices to join either the Midwest Independent System Transmission Operator (MISO) or the PJM Interconnection. Ameren chose MISO; AEP, Illinois Power, Commonwealth Edison, and Dayton Power & Light all chose PJM, forming a group now known as the "New PJM Companies," as distinguished from the "Classic" PJM members. These choices proved troubling to FERC, however, as they seemed to the commission to be counterintuitive. Thus vexed, FERC had opened an investigation concerning membership in MISO and PJM, covering such issues as market "seams," historic trading patterns, loop flows created by transactional patterns, and interfaces of different market and pricing regimes.
FERC aimed to create a "seamless" common market among MISO, PJM, and utilities that formerly had belonged to the now-defunct Alliance grid group. A seam can be defined as an interface between transmission providers that separates markets for artificial reasons-such as different business practices, market design, reliability rules, or software-that are not linked to fundamental economic characteristics, such as the cost of production. Surcharges are commonly assessed at such seams, with "pancaked" rates being a prime example. FERC sought to eliminate these seams, but all was not so simple.
FERC's guiding policy, announced in Order 2000, demanded removal of seams within regional markets. But could FERC also iron out seams separating the regions themselves? Wouldn't that imply a merging of regions and markets?
Such questions lead to a troubling thought: even if an RTO (such as PJM) once was deemed properly constituted, it might later become "undone" if the addition of new members in geographically inopportune locations would turn the once-efficient regional market into a larger but unwieldly one, riddled with seams and inefficient interfaces. Such a result might likely put a crimp in financing new RTOs. Yet this was exactly where FERC arrived in a series of key decisions:
- Forging a New Footprint. Back in July 2002, in what we can see now as a landmark decision, FERC bowed to the wishes of five utilities-all former Alliance members. But with PJM's borders expanded in this way, creating geographic inconsistencies along the PJM/MISO border, FERC decided that PJM would be rendered nonconforming as an RTO (too many seams, too many pancaked rates). Accordingly, FERC ruled that PJM and MISO markets and tariffs must be unified eventually, to remove seams and create a truly efficient regional market.
- Ironing Out the Seams. To further mitigate the seams problem, FERC decided last summer to eliminate the regional through-and-out transmission rates (RTORs) imposed by MISO and PJM that would have applied to transactions sinking within the hypothetically combined geographic "footprint" of the two regions. FERC also proposed to eliminate the parallel, company-specific through-and-out (T&O) rates imposed by certain former Alliance members for transactions also sinking in the combined RTO footprint. FERC added that it would consider crafting a hold-harmless cost adjustment scheme so that affected utilities would not lose the revenues otherwise produced by the RTOR and T&O tariffs.
- Softening the Blow. In a nod to protests from both RTOs and the utilities themselves, FERC devised a labyrinthine tariff known as "SECA" (Seams Elimination Charge/Cost Adjustment). SECA was designed to identify the transmission revenues that the RTOs and utilities would lose through the demise of RTORs and T&Os, and then to allow them (the RTOs and utilities) to recover the identical amount of revenue, as allocated under a classic true-up allowance.
These various elements form a large part of the theory underlying the recent AEP order. But a contradiction looms. On one hand, FERC's plan is founded on economic efficiency as the overarching goal in market design. On the other, the plan apparently saves little, if any, for consumers, since the costs slated for weeding out through RTO and tariff design are matched exactly by new costs reintroduced in rates in the SECA tariffs.
FERC's unsung ally in all of this may be Cinergy Corp., an electric utility with many economic and transactional ties to AEP. Behind the scenes, amidst the piles of paperwork filed in the various dockets involving AEP, MISO, and PJM, Cinergy urged FERC to fix the mess and sponsored testimony from three key expert witnesses-Michael B. Rosenzweig, Peter Fox-Penner, and Richard Tabors-cited by FERC as particularly persuasive in the ultimate formulation of policy.
Rosenzweig, for instance, offered up numerous anecdotes from interviews he had conducted with other utilities regarding pancaking of transmission rates. Tabors, a well-known technical expert of transmission transactions, appeared instrumental in convincing FERC that AEP's protocol of relying on TLR instructions (transmission loading relief) to reconcile grid congestion would be incompatible with PJM's LMP regime. And finally there was Fox-Penner, again sponsored by Cinergy. FERC cited Fox-Penner as authoritative in showing how AEP's historical trading patterns with MISO-member utilities would prove problematic if AEP was not made to join an RTO, even though his testimony was now several years old.
At the heart of it all lies the SMD, and its preference for the benefits that FERC claims are offered not only by organizing the grid into RTOs, as envisioned by FERC's Order 2000, but by imposing market protocols that go beyond that, including a day-ahead energy market, a market reconciliation of transmission congestion through locational marginal pricing (LMP), and a bid-based, security-constrained dispatch of generating and other energy resources.
Efficiency: Forging a New Footprint
Early on in the AEP saga, Cinergy Services had joined with Commonwealth Edison Co. (ComEd) to sponsor the testimony of Dr. Peter Fox-Penner, principal of the Brattle Group, regarding the merger of AEP and CSW (see AEP timeline). Showing that despite the passage of time, Fox-Penner's testimony (filed in April 1999) was still relevant, FERC cited Fox-Penner in its Nov. 25 AEP ruling. In FERC's eyes, Fox-Penner's evidence had shown why it was essential that AEP should participate in all of PJM's market structures, or else its post-merger control of transmission could be used to frustrate competitors' access to relevant markets.
In addition, however, and perhaps more important in terms of FERC's generic policy on transmission and RTOs, Fox-Penner's testimony appeared to be crucial in leading FERC to conclude that if it had to allow many of the former Alliance group companies to join PJM instead of MISO, then the commission ought to mitigate that apparent "mistake" by creating a virtual, combined MISO/PJM RTO that would integrate the markets. By creating a combined footprint, FERC would undo much of the damage (unneeded seams) created in the first instance by AEP and other former Alliance companies, by insisting on joining the "wrong" RTO.
In his testimony, for example, Fox-Penner had noted that 91 percent of merger-related power flows between the pre-merger AEP and CSW traveled on transmission systems owned by MISO members. By contrast, only 21 percent of power flows between and among other former Alliance group members would transit MISO member systems. The lesson here was that of the various former Alliance group members thinking about joining a substitute RTO, it was the post-merger AEP that showed the greatest degree of kinship with the MISO footprint, in terms of trading patterns.
As Fox-Penner put it, "If AEP joins the Midwest ISO, the Midwest ISO will have a significantly greater ability to mitigate problems associated with merger-related power flows than, for example, a potential future Alliance RTO with AEP as a member."
Left unsaid (who could know at that time?) was that a potential future PJM RTO with AEP as a member would fare even worse than a future Alliance RTO (versus MISO) in terms of dealing with problems arising from AEP power flows.
Fox-Penner continued on how many of the benefits promised by Order 2000 and RTO formation could be achieved "through AEP's membership in the Midwest ISO, even if other ECAR utilities should not immediately follow AEP's lead." In his view, AEP was clearly critical to the achievement of economic efficiency in power transfers in the Midwest, and the logical home for AEP was MISO.
In fact, Fox-Penner anticipated FERC's concern, not only with AEP's choice of RTO, to minimize internal seams, but also in eliminating artificial seams between ISOs and RTOs, as FERC now seeks to do in its RTOR and T&O decisions:
"Transactions that cross ISO boundaries are likely to face pancaked transmission rates, increased transaction costs, and inefficiencies, even when the provision of transmission service works very well within an ISO," Fox-Penner said.
"For example, even if an ISO's internal pricing and congestion management are adequate, the absence of a single entity with real-time information on the regional power market is likely to result in less-efficient congestion management for power transfers across ISO boundaries."
Thus, as far back as 1999, Fox-Penner was helping to convince FERC that if trading patterns show that a large percentage of transactions crosses from one region to another, then FERC must span those regions with consistent market structures. Therein lies the foundation for FERC's decision that it must treat MISO and PJM as two halves of a single combined footprint, especially if new members insist on joining the wrong half.
Tariffs: Ironing Out the Seams
The decision to eliminate RTORs and company-specific T&O rates was the correct one, according to Cinergy witness Dr. Michael B. Rosenzweig, senior vice president of National Economic Research Associates.
"If a supplier must cross a seam, its costs are increased by the through-and-out rate and its bid must reflect this additional, administratively imposed cost," Rosenzweig said. He likened the effect to a tax on trade: "The seam is imposing an artificial differential between the price that sellers taking transmission service out of MISO must ask for the energy they could supply to cover their costs and the price that their customers outside of MISO are being offered."
Rosenzweig interviewed several customers and suppliers, finding anecdotal evidence of financial harm from the existence of the RTORs in the combined region. He also reviewed transcripts of a FERC meeting during which executives from former Alliance companies had opted to join PJM over MISO, citing as one reason the harmful effects of the MISO RTORs.
The MISO seam was a "haphazard archipelago of islands, peninsulas and inlets," he said. It would take only one wheel from Illinois (Illinois Power) to New York, he added, but two wheels from Ohio (Cinergy) to New York, so a generator in Illinois that is twice as far from the customer as an identical one in Ohio could gain a significant cost advantage.
Rosenzweig examined transmission service requests before and after the initiation of the MISO RTORs and found a change in the pattern of such requests. He found that in the month MISO began operating, the level of transmission service from MISO to points of delivery outside of MISO fell dramatically from its level in the previous month. The following July, when MISO finished phasing in a series of discounts to the MISO RTORs after receiving complaints from member companies, the level of service returned, but not to the levels seen the year before.
He pointed to the city of Piqua, a full-requirements customer of Cinergy (Cinergy is in MISO, but Piqua is in the Dayton Power & Light control area outside of MISO). Piqua had signed a new contract with Cinergy at the start of 2002, extending the term of its full-requirements purchases. Previously, Piqua had to pay a transmission fee to both DP&L and Cinergy. (Its total cost for transmission from Cinergy was about $1,070/MW per month, or $2/MWh.) With the startup of MISO, Piqua expected that it would pay but one charge, saving money compared to the prior system of pancaked rates. Instead, as Rosenzweig learned from his interview with city officials, Piqua ended up paying transmission charges to both DP&L and MISO, since DP&L (a former Alliance company) was not joining MISO. The increase translated to a 4.5 percent increase in existing retail rates for Piqua residents.
Rosenzweig interviewed many other transmission customers, hearing many similar stories. FERC has cited this testimony as persuasive. It has formed a key element of the commission's decision to eliminate RTORs and utility specific T&O rates.
Operations and Dispatch: Merging the Markets
Another Cinergy witness, Dr. Richard Tabors, president of Tabors Caramanis & Associates, also appeared instrumental. His role was to convince FERC that if AEP was to join PJM, it would have to join all the way, with full participation in PJM's market structures, including LMP for congestion management.
Note, first of all, in order to overcome state objections, that AEP had proposed to join PJM only half-way; it would submit its grid assets to the functional control of PJM, and yield to the RTO on all other functions that FERC had defined as fundamental to RTOs in its Order 2000. Yet AEP would refrain from participating in PJM's day-ahead market and would not submit to PJM's centralized and security-constrained dispatch, nor PJM's LMP regime for market-based congestion management. Instead, it would rely on the non-market technique of TLRs to manage grid congestion. AEP had argued that when it had promised to join an RTO in exchange for FERC approval of its merger with CSW, it had envisioned such membership to include only those features described in Order 2000 as essential to RTOs. FERC had not yet announced its SMD, which listed LMP, day-ahead markets, and security-constrained dispatch as required elements of RTOs.
Responding to AEP's half-a-loaf proposal, Tabors had argued that AEP needed to be fully integrated immediately into PJM markets. RTOs, he said, should not be "hamstrung with a requirement to indefinitely depend upon an economically inefficient TLR interregional congestion management protocol for the AEP transmission system portion of the RTO's regions, while attempting to implement coordinated, LMP-based congestion management in the remainder of the surrounding regions."
Tabors, whose book, Spot Pricing of Electricity, documents the underlying mathematical theory of LMP-based electricity markets used in PJM, NY-ISO, and ISO-NE, told how LMP would prove superior to quantity-based rationing of transactions, which results from the TLR process. To support his conclusion, he discussed how various solutions for generation dispatch can affect power flows across a flowgate, as indicated by "sift factors described in the Interchange Distribution Calculator (IDC), developed by the North American Electric Reliability Council (NERC):
"The underlying LMP algorithm explicitly uses up-to-date shift factors-accounting for day-to-day topology changes-associated with each modeled generation unit to assess such generator's impact on a modeled constraint," he noted. That part of the algorithm explicitly produces components of LMP that represent congestion effects, Tabors added. It makes LMP more accurate because the LMP prices that result from a real-time security-constrained economic dispatch process (SCED) are directly related to actual, close-to-real-time shift factors and the associated generator's impact on each modeled flowgate constraint.
By contrast, as Tabors explained, a TLR-based system would rely on the power transfer distribution factor of the transaction, or the relative impact of the power flow across the flowgate. But Tabors called the TLR-based system an "economically inefficient" way of relieving a constraint, because it does not take into account the costs of redispatching to ease the constraint. Instead it forces a more inefficient redispatch by not allowing for the least expensive redispatch option to be implemented.
Thus, Tabors argued that a separate isolated control area of such size as AEP could influence the extent of congestion across a number of regional flowgates in an even greater manner than the static shift factors might indicate. So if AEP were allowed to operate its own congestion management system, he said, it would have the potential to significantly influence congestion both positively and negatively across flowgates within the region.
The SECA Surcharge: Softening the Blow?
With voiding of regional and company-specific through-and-out transmission rates, FERC breaks new ground on several fronts. Most importantly, the commission rejects a tariff not for reasons outlined in the Federal Power Act (unjust, unreasonable, or discriminatory), but on a hopeful theory-that because RTORs and T&Os represent artificial barriers to trade, their elimination should produce greater market efficiencies and, in the long run, positive cost savings for consumers.
In addition, however, the approval of the SECA surcharge to allow the affected utilities to recover the lost revenues through a different tariff assessed to a different class of customers appears controversial as well. That's because the SECA surcharge poses some problems in administration and carries with it a host of worries common to the design of other utility tariffs, timing differences, cost shifts, and intergenerational equity.
Opposing parties offered a number of reasons against attempting to recover the lost revenues one-for-one through the SECA, which takes the form essentially of an added license-plate transmission rate, to be imposed on customers in the zone (control area) in which the power transaction sinks, designed to match the total revenues that would have been collected otherwise on interregional transmission paths. Importantly, however, there would be no need to prove that customers paying the new SECA surcharge were the same ones who would have subscribed to transmission service subject to the voided RTOR or T&O charge, raising concerns of equity, among others:
- Timing Differences. Demand growth in the sink zone could add customers and load to the SECA charge base, causing the surcharge eventually to over-recover the eliminated RTOR and T&O revenues.
- Cost Shifting. In some cases, power wholesalers would have paid the RTOR or T&O, either directly, or through a lower margin, so recovering those lost revenues entirely from end users might shift some costs from producers to consumers.
- Fairness. An interregional transmission charge in theory is avoidable (use local generation instead of importing), so allowing its reimbursement through a nonbypassable surcharge represents a forced recovery of an operating expense that is not ordinary or necessary.
- Illegal Incentive. According to Detroit Edison, SECA would qualify as a financial incentive for RTO participation, thus requiring a cost-benefit analysis for justification under FERC's own policy statement (61 FERC 61,168) governing incentive regulation.
- Administrative Impossibility. Allocating the SECA surcharge on a license-plate basis to the load of a specific utility in a particular zone could prove impossible in PJM, since the entire PJM region is treated as a single zone (a single control area).
Illinois Power had ridiculed that last argument. The problem, said the company, was "akin to a group of diners in a Chinese restaurant who, having shared plates delivered to the table, inform the waiter that since they do not have a record of who ate how much of what, they will be unable to pay the bill."
At the end of the day, however, FERC faced an intractable problem: some of the utilities that benefit from revenues received from the RTOR and T&O tariffs had already counted those revenues in rate cases and rate settlements at state PUCs, and under rate freezes still in effect were powerless to go back to their states to gain reimbursement should they lose those revenues at the FERC.
Ameren, for example, noted it collected approximately $45 million (annually) in revenues from T&O rates applicable to transactions sinking outside its control area-revenues it would lose without recourse at the state level and without a SECA true-up. As is explained, its current retail rates in Missouri resulted from a "black box settlement" at the state PUC, with no specific line item identified in the settlement as attributable to RTOR revenue. Once lost, such revenue would be lost forever.
In the long run, it may prove difficult to verify if FERC's theory will hold: that by eliminating tariffs that are economically efficient, but not necessarily unjust or unreasonable-and then hitting consumers again for the very same rates, but in a different guise (the SECA surcharge)-it will make consumers better off.
Certainly, however, the SECA story is curious in one respect. According to FERC, in previous cases it had eliminated certain types of rate pancaking without imposing true-up adjustment clauses to capture the lost revenue. But, as the commission explains, those instances involved a voluntary surrender of pancaking revenues. Here, it says, the utilities and RTOs would not volunteer to give up their tariffs, but had to be carried along kicking and screaming, so that it was only fair to offer SECA as a carrot.
One might ask, at the very least, whether any utility ever again will volunteer freely to give up revenues from pancaked transmission rates, without assurance of a tit-for-tat surcharge.
RTO for AEP?
April 1998 - AEP, CSW file joint application at FERC to merge. Dec. 1999 - FERC issues Order 2000 (final RTO rules). Mar. 2000 - FERC OKs AEP/CSW merger, on condition of RTO membership. June 2000 - AEP, CSW consummate merger. July 2002 - FERC grants RTO choices of five utilities (Ameren, AEP, ComEd, Illinois Power, DP&L), but says MISO and PJM must combine markets. July 2002 - FERC OKs bid by FirstEnergy and NIPSCo to join MISO through participation in GridAmerica. Dec. 2002 - AEP signs agreement, agrees to transfer control of East Zone grid assets to PJM West, applies to Ind., Ky., Ohio, and Va. for permission to join PJM. Feb. 2003 - Virginia enacts law barring RTO membership w/o OK from state PUC. Mar. 2003 - State PUCs in Mich., Ohio, and Pa. propose RTO-lite plan, with AEP ceding functional grid control to any independent party, consistent w/ rules governing TransLink's membership in MISO. June 2003 - FERC staff suggests compromise: Split AEP East grid zone between "yes" and "no" states. July 2003 - Kentucky denies permission for AEP to join PJM. Sept. 2003 - AEP offers another plan: It would join PJM on limited (pre-SMD) terms, w/o markets, central dispatch, or LMP. Oct. 2003 - GridAmerica begins operations within MISO (Ameren membership pending).
Pieces to the Puzzle
How States, Utilities Fit in the Midwest
Because of its huge geographic scope, American Electric Power (AEP) has become the most important player in the creation of a larger PJM, exerting influence on how other utility companies would wheel their power to market.
AEP's Grid Network. AEP owns transmission assets over a broad geographic area located in Michigan, Indiana, Ohio, Kentucky, West Virginia, Virginia, and Tennessee. Its merger partner, Central and South West Corp. (CSW), operates in Arkansas, Louisiana, Oklahoma, and Texas.
Affected States. AEP so far has been stymied by the Kentucky PSC's denial of transfer of AEP's transmission facilities to PJM. (See Ky.P.S.C. Case No. 2002-00475, July 17, 2003, 227 PUR4th 156.) Virginia state law prohibits transfer of control of transmission facilities prior to July 1, 2004-and then only after approval by the Virginia commission. By contrast, regulators in Ohio simply threw up their hands, declaring, "there are too many unresolved issues beyond [our] jurisdiction for the commission to have a meaningful review."
The Illinois Outcrop. With some former Alliance group companies opting to join PJM, the state of Illinois would stand as the westernmost extension of PJM, with areas of MISO actually situated to the east, in Indiana and Ohio. Dynegy's Illinois Power, for example, had planned initially to join PJM, but later switched allegiance to MISO. At press time, Ameren Corp. confirmed it is in exclusive negotiations to buy Illinois Power Co.
The Dayton Island. DP&L is another company held hostage by geography. It also would connect to PJM via its interconnection with AEP, but the company has no firm transmission through AEP allowing it to connect to PJM. Even if it were operationally feasible to attempt to integrate DP&L into PJM prior to AEP, DP&L believes it would create a "peculiar" situation that would be costly to implement without any real benefit to consumers. But DP&L concedes that DP&L still intends to proceed toward integration into PJM concurrently with AEP. -L.A.B., B.W.R.
Other Commission News
Standards of Conduct A final rule was adopted by FERC setting standards of conduct that will apply uniformly to natural gas pipelines and transmitting public utilities. The rule governs the relationship between transmission providers and their energy affiliates. It retains the exemption in Order 889 permitting a utility transmission provider to use the same employee for its interstate transmission business and bundled retail sales business. FERC clarified that if a retail sales function employee engages in any wholesale sales, such as selling excess generation off system, the exemption will not apply. Docket o. RM01-10-000, 105 FERC 61,248, Order No. 2004, Nov. 25, 2003 (F.E.R.C.).
El Paso Corp. Settlement FERC approved a settlement calling for El Paso Corp. to pay $1.6 billion to resolve the California PUC's complaint alleging El Paso withheld natural gas supplies into California, affecting prices for both gas and electricity during the state's energy crises in 2000 and 2001. El Paso does not admit any alleged violations as part of the settlement, which is subject to modification. Docket Nos. RP00-241-000 et al., 105 FERC 61,201, Nov. 14, 2003 (F.E.R.C).
Market Behavior Rules FERC issued a set of market behavior rules designed to prevent market abuse, provide a more stable energy marketplace, and create an environment that will attract needed investment to the gas and electric industries. If a seller were found to have engaged in prohibited behavior, the seller would be subject to disgorgement of unjust profits plus non-monetary remedies such as revocation of a seller's market-based rate authority or blanket certificate authority. Docket Nos. EL01-118-000 and EL01-118-001, 105 FERC 61,218, Nov. 17, 2003 (F.E.R.C.) and Docket No. RM03-10-000, Order No. 644, 18 CFR Part 284, issued Nov. 17, 2003, effective 30 days after publication in the Federal Register.
New England Markets FERC accepted a joint filing by the New England Power Pool and ISO New England to implement a Forward Reserve Market in New England, which will enable the advance market-based purchase of 10-minute non-spinning and 30-minute operating reserves, thereby allowing suppliers with off-line resources a method to receive compensation for the reliability services they provide. Docket No. ER03-1318-000 and ER03-1318-001, 105 FERC 61,204, Nov. 14, 2003 (F.E.R.C.).-L.B.
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