Transmission Markets: Stretching the Rules for Fun and Profit

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© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00119-6

The Electricity Journal

Transmission Markets: Stretching the Rules for Fun and Profit

The evidence strongly suggests that under FERC’s Order No. 888, some players have the ability and incentive to impede competition to their advantage, in a way that is virtually impossible to police.

Narasimha Rao and Richard D. Tabors

he level of wholesale electric-ity price volatility experienced

across the United States in the summers of 1998 and 1999 was unprecedented. On certain days, generation and transmission facili-ties were stretched beyond their capability. Analysts expect prices in the summer of 2000 to be equally volatile. While this volatil-ity can be attributed in part to such unavoidable factors as adverse weather and supply outages, it can also be argued that competitive wholesale electric markets in the United States are still maturing, and that price volatility is an expected part of the transition in infant deregulated markets. It would be surprising, however, if a

consistent pattern of highly vola-tile market price behavior over three consecutive summers could be attributed only to market learn-ing and adverse demand and supply conditions.

This article focuses attention on yet another explanation for the price volatility seen specifically in the summer of 1999. We suggest that another form of learning has occurred, in which transmission providers who have remained ver-tically integrated have learned to profit largely

within the rules

for open access and market operations by effectively foreclosing competi-tion and limiting access to key markets to the benefit of their mar-keting and generation affiliates.

Narasimha Rao

is a Senior Analystwith Tabors Caramanis & Associates(TCA), Cambridge, MA, where he is

involved in power system modeling andeconomic policy analysis. He holds anM.S. in Electrical Engineering and an

M.S. in Technology Policy from theMassachusetts Institute of Technology.

Richard Tabors

is President of TCAand a Senior Lecturer in TechnologyManagement and Policy at MIT. He

has been active in the restructuring ofelectric power systems both in the

United States and internationally. Dr.Tabors holds M.S. and Ph.D. degrees

from the Maxwell School ofSyracuse University.

The authors gratefully acknowledge theassistance of Peter Capozzoli and

Prashant Murti in the preparation of

this article.

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This article provides results of extensive analysis of transmission market behavior in the summer of 1999 to illustrate that vertically integrated transmission pro-viders can, and very likely did, exploit the market rules profitably during these high-priced days. Due to the flexibility and discretion provided to, specifically, the larger transmission providers and the self-policing nature of rule enforcement, such behavior can pass unnoticed. Further, auditing such behavior to determine improper usage would require an extensive amount of information that is not available in the public domain to market participants.

How and why can such behavior occur? There are three reasons:

1. Transmission providers, par-ticularly those who cover a large geographic area and are also security coordinators (SCs) under the rules of the North American Electric Reliability Council (NERC), have an ability to exer-cise monopoly power. Most sim-ply stated, they “control all the knobs” of the transmission sys-tem because they own the wires, operate the system, define the capacity of the system (in close to real time), and thereby determine who has access to transmission. The fact that these same entities are also SCs provides additional “knobs” over which they have direct control, specifically the calling of transmission loading relief (TLR) and the ability to override the mechanical setting of transaction limits.

2. Transmission providers are one element of today’s profit-

maximizing utilities that also have merchant affiliates that mar-ket energy at market-based rates. The transmission provider that remains within the vertically inte-grated structure has (at mini-mum) an implicit incentive to continue to operate the transmis-sion system so as to complement the profitability of its generation assets. If the vertically integrated utility maintains a native load requirement, the same incentive

“bending, folding, or mutilating” the spirit or the reality of the rules of open transmission access.

Our detailed review of the trans-mission transactions in the Mid-west in the summer of 1999 shows that such anti-competitive behav-ior did occur. Data show that cer-tain vertically integrated transmis-sion providers operated so as to foreclose competition on certain days with high prices, which allowed their merchant functions to continue to sell or even increase sales into profitable load areas for prices that the market-ing affiliates were, in all likeli-hood, able to influence. Evidence shows a range of behavior from what may be violations of the rules to compelling evidence of exploitation of rules to the benefit of the providers.

ur conclusion from this anal-ysis is that the industry struc-

ture requires further change that must come from either regulatory order or legislative action if whole-sale competition is to flourish.

I. What Are the Market Rules?

There are three categories of transmission market rules that sig-nificantly impact competition in wholesale electricity markets:

•

Rules governing the supply of transmission service to the whole-sale energy market. These include rules for calculating, posting, and offering available transmission capacity (ATC) through Open Access Same-time Information Systems (OASIS).

•

Procedures governing trans-mission loading relief (TLR), the

Vertically integrated transmission providers can, and very likely did, exploit the market rules profitably during these

high-priced days.

exists to act to shield the cus-tomers from external competitors.

3. The current market structure relies entirely on self-enforcement of the rules contained in FERC Order No. 888 and the regulatory rulings that followed. The rules themselves are frequently opaque and, more critically, evidence of the bending of the rules is virtually impossible to assemble. Addition-ally, there has been little evidence of a willingness by FERC to respond to any but the most egregious of violations. The result has been that transmission providers have had a very low risk of detection and an even lower risk of punishment for

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mechanism currently used to address the real-time security of the interconnected grid.

•

Native load exclusion from FERC Order No. 888 open access rules, including reliability-related rules that allocate transmission reserve margins, such as capacity benefit margin (CBM).

A. OASIS

Transmission providers calculate available transmission capability (ATC) on an hourly basis for every path in their jurisdiction. These calculations are complex and their results depend on the physical state of the transmission system at any point in time (measured or estimated), as well as several other time-varying parameters, such as the transmission reliability margin (TRM) and allocated CBM on transmission paths. Access provi-sion is based on an “honor princi-ple” and relies on a self-enforcing system where customers file com-plaints before FERC if they dispute providers’ discretion in service provision. Thus, provider behavior is not, and probably cannot be, proactively audited. Providers therefore have ample latitude, dis-cretion, and authority to grant or deny service requests.

B. Transmission Loading Relief Procedures

TLRs are operating procedures developed by NERC to mitigate operating security limit violations. Any control area in the Eastern Interconnection (EI) may submit a request for a TLR to its security coordinator based on real-time operating conditions on a flow-

gate.

1

SCs possess discretion to implement a local line loading relief procedure or implement NERC’s TLR procedures.

n December 1998, FERC approved NERC’s proposed

revisions to TLR procedures to address parallel flows, and required utilities that adopted these revisions to incorporate them as an amendment to their

pro forma

Open Access Transmission Tariff. These revisions included proce-

exceeds 5 percent.

2

As a conse-quence, significant interruptions in power flows across the Eastern Interconnection can occur during TLRs; these have significant impact on energy market prices. Notably, SCs also possess discretion to over-ride a PTDF-based selection. Although TLRs have greater visibil-ity than ATC postings, exploitative behavior can still escape detection because no record is kept or audited of real-time operating conditions during the TLR occurrence.

C. Capacity Benefit Margin

CBM is the transfer capability set aside by load-serving entities (LSEs) to ensure access to genera-tion from interconnected systems so as to allow LSEs to reduce reserve requirements for physical generation within their territories. NERC has broad guidelines for calculating CBM, but so far has left the calculations to the discretion of LSEs.

3

Most of the guidelines are provided by regional reliability councils and focus on the mini-mum requirements for CBM calcu-lations, and are nonprescriptive.

CBM can be called upon during emergencies by load-serving enti-ties. An emergency is defined as a generation shortfall. Further, in some regions an LSE can call an emergency based on a generation shortfall in its own service terri-tory regardless of the supply situa-tion of the entire control area.

4

Pro-viders are required to designate their interface set-aside to resources, either generation or purchase contracts. As in the case of ATC, CBM reservation and use is not audited or monitored, except

Significantinterruptions in

power flows acrossthe Eastern

Interconnection can

occur during TLRs.

dures intended to better address parallel flows by broadening the scope of TLR operating procedures to allow the curtailment or restric-tion of incremental interchange transactions anywhere in the East-ern Interconnection. The NERC procedures call for different levels of response based on the expected severity and duration of the TLR. For all TLRs that reach Level 2, SCs may disallow any incremental interchange transactions on paths that impact the flowgate. An inter-change transaction would be selected where its power transfer distribution factor (PTDF) with respect to the flowgate in question

I

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pursuant to complaints filed by market participants, as recently was the case in

Aquila Power Corpo-ration v. Entergy Services.

5

esides CBM, vertically inte-grated utilities reserve a signif-

icant amount of their transmission capacity for network service—service to their native load from their generation and off-system con-tracts. This reserved capacity is off-bounds for the competitive whole-sale market, and, as will be shown later, can be used to facilitate sales by the providers’ merchant affiliate.

II. How Are the Market Rules “Stretched”?

Transmission market behavior during the summer of 1999 was analyzed to determine the poten-tial exploitation or violation of market rules to the benefit of trans-mission providers. Several utilities in the Midwest were selected for analysis because of the price spikes experienced, and because of the dominance of few, large transmis-sion providers. Note that all exam-ples below are actual evidence found through extensive analysis of OASIS data and TLR events, and are just a selection from numerous similar cases found. The individual utility players are not identified in the examples both to protect their anonymity and because our purpose is to identify the principal policy issues, not to prove fault. Other venues are available were that our objective.

A. OASIS Games

The latitude to update ATC post-ings with time allows transmission

providers to restrict competition in a manner that would require exhaustive auditing to detect. Sev-eral methods for foreclosing com-petition were found:

1. Denying requests for firm ser-vice on a day-ahead or longer basis on the grounds of insufficient ATC, despite there being sufficient ATC.

Data show significantly higher ATC postings than the cumulative refused requests on certain paths and on certain high-

of the requestor, suspecting the possibility of an unreasonable denial is much harder at the time of a request, when one does not have the benefit of trend analysis in hindsight using several months’ worth of data.

Figure 1

shows the discrepancy between ATC versus cumulative refusals by a transmission pro-vider A for a path into a sink B from utility C through A’s service territory, for the month of July. Although only one path has been illustrated, the same result was observed on that day for several other through paths into B. Most of these denied requests were for monthly and daily service. Although ATC can be updated on a shorter time scale closer to the date of service, the fairly constant level of ATC observed over the month reduces the likelihood that ATC drastically increased on a day-ahead basis relative to month-ahead. Clearly, based on available data, the refusals cannot be explained, especially since they were made on the grounds of insufficient ATC.

uch a result can arise due to genuine changes in the system,

spurious data, mistakes in calcula-tion, or deliberate market foreclo-sure. The first three could be tested only with a full-scale audit of a provider’s data, which is not in the public domain. Finding conclu-sive evidence of the fourth may also be impossible with available data. However, several instances were found, as shown in

Figure 2

, during which A’s merchant affili-ate (AM) had active

nonfirm

sales into B during days when

firm

price days. The only explanation of their legitimacy is that

at the time

of the request ATC may have been low, or set to zero due to TLR or other such restrictions, and subse-quently reset prior to the day of service. However, the final post-ings show very high numbers, bringing into question the likeli-hood of such a drastic, short-lived drop.

6

Notably, the time stamps on the request and ATC data appeared spurious. Therefore, without an extensive audit of the provider’s actions and calcula-tions, verifying the legitimacy of such a request denial would be impossible. From the perspective

Updating ATC postings with time allows transmission providers to restrict competition: detection

would be difficult.

B

S

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transactions from several paths into B were denied.

7

Most of AM’s transactions were on a day-ahead and hourly basis, which is on a much shorter time scale than most of the denied requests (monthly). Further, AM’s market share (per-cent of all accepted requests) into B on certain hours were markedly high, namely above 25 percent. This resembles—very much in qualitative terms—a case of mar-ket foreclosure leading to signifi-cant increase in market concentra-tion for supplier AM into B. Short of demonstrating the ability to actually influence price, provider A certainly was able to benefit from high prices. Notwithstand-ing, prices in B during those days where AM sales were high (July 6–7, July 22–23, July 28–30, as shown in Figure 2) were well above $200/MWh, and on some days above $1,000/MWh.

Note that what allows this transmission provider to partici-

access to the transmission system, even if such unequal footing were not deliberately created.

2. Other behaviors were also found that potentially foreclosed markets.

One example is discrep-ancies in the ATC postings between day-ahead or longer ser-vice increments on the one hand and hourly offerings on the other. In such situations, day-ahead ATC for a breadth of high-priced days was reported on OASIS as being zero. When looking at the hourly market for the same day, it was seen to be significant and positive. This would have the effect of diverting competition in the day-ahead market to other paths, since most traders’ operations cannot risk relying on the hourly market. The only players in the market able to take advantage of the hourly market would be those incumbents with either genera-tion capable of responding in an hourly market or those with “parked” (see below) energy

pate actively in the nonfirm mar-ket while denying firm requests is knowledge of the system, knowl-edge of the supply availability, and higher certainty of short-term, nonfirm request acceptance than other players. Such circum-stances impede Order No. 888’s objectives of nondiscriminatory

Figure 1: Discrepancy between ATC and Request Refusals Path: Company C through Provider A to Company B, July 1999

Figure 2: Provider A’s Merchant Affiliate Sales Path: Provider A to Company B, July 1999

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capable of being delivered over transmission that has been reserved under the native load exclusion of Order No. 888.

hese ATC discrepancies between day-ahead and hourly

could very well be the result of TLRs called on previous days that resulted in transaction restrictions (see TLR section following) for the next day, whose remediation allowed restoration of previous ATC levels in the hourly market of the next day. In fact, such a correla-tion was found in several cases. In these cases, however, hourly offer-ings on the day of the TLRs were not correspondingly reduced dur-ing the TLR. This fact coupled with the fact that the merchant affiliate of the transmission provider had sales during and after the TLR events in the hourly market can lead only to the supposition that the transmission provider had the incentive and all the possible con-trol to foreclose competition and benefit merchant affiliate sales.

The day-ahead versus hourly ATC discrepancies, even if due to legitimate reasons, creates unequal access to the transmission system. When refused service on a day-ahead basis, marketers do not often have the luxury to wait till the hourly market—they must go elsewhere. Merchant affiliates of transmission providers, on the other hand, may have a greater ability and knowledge to partici-pate successfully in the hourly market, particularly in adjacent load centers. Thus, this behavior gives them a competitive advan-tage, to the extent that their “through” (or more likely “out”)

path is an economically valuable path into that sink.

Determining whether such behavior actually occurred and further contributed to or exacer-bated the price spikes seen in the Midwest in the summer of 1999 would require exhaustive analysis and reproduction of real-time con-ditions. The conclusion that must be reached, however, is that these data show that the potential for such an impact

cannot be ruled out

, and that such behavior can occur

within the rules by rational, profit-maximizing entities with a high likelihood of passing unnoticed. One must ask whether this is another example of “where there is smoke there is fire”?

The second observation is that the data required to verify ATC postings and request refusals are voluminous, because numerous ATC postings and calculations would need to be verified for every such request. This would require extensive knowledge of the physi-cal state of the system, the model runs, and calculations that resulted in these postings. Since ATC post-ings may change over time, all his-

torical updates to a particular ser-vice offering for which a request was refused would need to be audited as well. Further, since requests may be withdrawn or annulled at any time, the status of all requests at the time of the refusal would need to be audited. Such an audit is rarely required, except pursuant to particular com-plaints, and therefore is not a stan-dardized procedure. Clearly it may be highly infeasible to enforce such a complex and time-intensive sys-tem of checks and balances.

B. TLRs

Since the implementation of NERC’s revised TLR procedures based on PTDFs in mid-1999, TLR occurrences have increased signif-icantly, as shown in

Figure 3

. The vast majority of these TLRs required some level of restriction on at least incremental inter-change transactions.

nalysis of some of these TLR events for a specific trans-

mission provider on high-priced days showed that interchange transactions seem to have been inconsistently restricted into par-ticular sinks (with regard to the PTDFs of the paths concerned), causing significant market foreclo-sure. Simultaneously, several con-firmed transactions for this pro-vider’s merchant affiliate into that sink were observed.

The following observation per-tains to the same sink B and trans-mission provider A referenced above for a TLR implemented by A (also the security coordinator) on July 21–22, 1999. On these days, A seemed to have reduced ATC to

Day-ahead versus hourly ATC discrepancies create unequal access to the

transmission system.

T

A

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zero on several paths

through

its territory into sink B, but allowed ATC to remain at high levels on other paths, including the path

out

from A to B.

Table 1

shows the ATC for a representative path from both categories of ATC behavior. Given the coincidence of this ATC behavior with a particular TLR, and the singular nature of the drop in ATC, there is a very high likeli-hood that the ATC behavior was a result of the TLR. This is substanti-ated by the fact that in this and other examples, the paths showing zero ATC were the paths that the TLR would require to be restricted. Further, it was verified that the other TLRs called on the same days on the basis of PTDFs did not have any impact on these paths.

The salient observation is that, as shown in Table 1, pursuant to the

sink B, and the fact that on July 21–22 AM sales were relatively high.

Again, no unequivocal conclu-sion can be drawn based on avail-able data as to the intentions or even the actual impacts of this behavior with regard to its anti-competitive nature. As mentioned earlier, SCs possess the discretion to restrict and allow transactions as they deem appropriate to rem-edy a security violation. Provider A may have reduced ATC for other

path PTDFs, even path A to B should have been restricted given that the transactions in question would have caused increases in flows across the flowgate that exceeded the 5 percent maximum level as set in the TLR procedures. Note that these PTDFs were obtained directly from provider A’s TLR log of that specific TLR event, and also from NERC’s TDF calcula-tor.

8

Figure 2 already shows the transactions secured by AM into

Figure 3: TLR Events (Level 2 or Higher), May 1998–September 1999

Table 1:

Path ATC and PTDF Comparison for TLR

Path Start DateDaily Firm

ATCNERC PTDF

Provider APTDF

Company A – Company B 21 July 1999 4743 8.00% 6.20%

Company E – (thru A) – Company B 21 July 1999 4587 9.00% 5.70%

Company F – (thru A) – Company B 21 July 1999 0 9.10% 6.10%

Company G – (thru A) – Company B

21 July 1999

Not Posted

8.80%

6.20%

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reasons such that the PTDFs may not be an appropriate metric for such behavior. Such behavior may be perfectly legitimate, and evi-dence of benefit through affiliate sales may be sheer coincidence. The important conclusion is that the system provides SCs (who are affiliated with vertically integrated utilities) the tools and discretion to act on any bias they may have toward the operation of their own system. The fact that their mer-chant function understands these behavioral patterns means that these events can occur without any need for actual, explicit communi-cation between the two parties (SC and affiliated merchant). The assumption of the regulatory struc-ture is that the code of conduct is sufficiently strong to assure that parties will not communicate. Our conclusion is that

they need not com-municate

to have virtually the iden-tical impact on market foreclosure.

C. Capacity Benefit Margin and Native Load Exclusion

Some companies reserve as much as 15 percent of their total interregional transfer capability for CBM. The benefits of CBM res-ervation can accrue to a vertically integrated transmission provider both when it is held as reserve and sold only on a nonfirm basis and when the transmission pro-vider is actually using the reserved capacity.

Figure 4

illustrates how CBM reservation can inhibit competition by restricting market access to high-priced load centers. A trans-mission provider A with excess generation that is adjacent to a

load center may restrict third par-ties from accessing the load center through its service territory due to the limited firm capacity available for “through” service. As a result, A may sell into that load center even if it is not the low-cost sup-plier, because third parties would have to pay pancaked rates over alternative transmission paths to reach that load.

lternatively, transmission pro-vider A could actually use

the CBM during a declared “emer-gency” (day-ahead or day-of), which may be due to a shortage in its own, or any other, load-serving entity’s service territory in the con-trol area to purchase energy for the purpose of selling out through its merchant function—a phenome-non known as “parking,” as illus-trated in

Figure 5

.Native load service, which com-

prises transactions

outside

the realm of open access and OASIS,

can be used for the same purpose. These transactions are not trans-parent, and are not tracked and posted on OASIS. Although OASIS has a provision for native load ser-vice, several utilities do not post their native load service reserva-tions on OASIS. Thus, this “hid-den” activity is effectively impossi-ble to monitor and, given the current rules under Order No. 888, any use that can be justified (and nearly all can) is perfectly accept-able. Analysis of a particular trans-mission provider in the Midwest shows significant sales through its merchant affiliate through the summer of 1999 that cannot be accounted for either by its excess supply or its OASIS-scheduled purchases from other areas. In other words, its merchant affiliate has

net sales out

of its service terri-tory in excess of estimated genera-tion surplus when there are no cor-responding

in

transactions. This

Figure 4: CBM Reservation Favoring Generation Arm of Vertically Integrated Utility

A

Figure 5: CBM Use for “Parking” Energy

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“parking” amounted to greater than 3,000 MW during periods of the summer of 1999. The only source of this energy can be off-system purchases made through the native load reservations, either CBM or network service.

The impact on competition of native load reservations is first and foremost the restriction of market size. CBM reservations, though significant, constitute only part of the “extra-open access tariff” mar-ket. Native load service reserva-tions for off-system generators and contracts also occupy a significant portion of interregional transfer capability. Second, it can also cre-ate preferential access to merchant affiliates of transmission pro-viders, as demonstrated above.

sion providers have native load and the majority of them now have merchant functions that have been approved to trade at market-based rates. Thus, there is a strong incen-tive to use the transmission system in a manner that increases overall profits, which ride mostly on the sales of the merchant function. These entities are monopoly pro-viders of transmission service who have all filed Open Access Trans-mission Tariffs under FERC Order No. 888. The interaction between the merchant function and the reg-ulated transmission provider can-not, we argue, be policed in a real-istic manner. Only through the FERC complaint process can a potential abuse be brought for-ward. Such complaints are costly and time-consuming. Only instances of the magnitude of the Aquila-Entergy complaint or of the AEP/CSW merger receive the detailed attention required to net a FERC action.

•

The complexity of ATC calcu-lation and access prohibits

ex-post

reproduction of events and condi-tions leading to particular service denials or acceptances without significant time and effort, a lux-ury market players cannot afford and that experience has shown do not result in a useful outcome in any event.

•

Certain transmission pro-viders are also security coordina-tors, and need to have discretion to respond to real-time emergency situations. This also, however, gives them the ability to use their control to their advantage.

•

Native load exclusion provides a risk-free access to transmission

III. Lessons Learned

A regulatory framework within which certain players have the abil-ity and incentive to impede competi-tion to their advantage

and

that is virtually impossible to police cannot be expected to fulfill the objectives of FERC Order No. 888 in the long run. The discussion above shows that these conditions in fact may very well exist in the current regime. No market can be perfect, and checks and balances have always been nec-essary to ensure competitive behav-ior. However, the analysis shows that the current regulatory structure would require a prohibitive amount of real-time information to monitor and enforce rules. The basic struc-ture needs change.

•

Vertically integrated transmis-

No market can be perfect, and checks and balances have always been necessary.

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29

capacity that prevents the develop-ment of a level playing field.

IV. Where Do We Go From Here

The solution to the issues described above will require the removal of either the incentive or the ability to impede competition. Technically, all system operators with real-time decision-making ability could “impede” competi-tion through their actions. How-ever, they need the ability to gauge system conditions and respond appropriately to ensure real-time system reliability. We believe that the preferred first step is to remove the incentive. This would mean (1) remove the native load exclusion, and (2) transfer transmission oper-ation responsibilities to a neutral body, such as a regional transmis-sion organization (RTO). FERC in Order No. 2000 began to move toward assuring neutral operation of the transmission system. It has further shown its awareness of at least some of these solutions, as is evident in its recent conditional approval of the AEP-CSW merger. Here, FERC ordered the compa-nies to transfer control of their transmission assets to an RTO as a condition of the merger, and in the interim required them to appoint an independent market monitor and ATC calculator.

hat is clear is that the speed of the transition to

equal

open access is not great. Working one utility at a time, even if that util-ity is as large as an AEP or Entergy, does not prevent others from con-tinuing the type of market behavior

described above. Transitions from regulated to less regulated markets are always difficult. If we have learned nothing else in the restruc-turing of telecommunications—and particularly of natural gas—it is that the parties become increasingly skilled in market manipulation and progressively entrenched as the transition is drawn out.

Where do the solutions lie? The most pragmatic point of departure is requiring that all transmission transactions use the OASIS structure—removal of the native load exclusion. This will bring far greater transparency to the setting of ATC when all players must use this information source to sched-ule all transactions. At the other end of the spectrum are the hard decisions, the complete separation of transmission from generation, load, and merchant functions. If the goal is to “get the incentives right,” we have argued that a large, regional for-profit transmis-sion company (transco) that owns and operates the system is the pre-ferred structure. While open to considerable debate, the transco option centralizes the operational control, provides an incentive structure that assures equal quality of service for all market partici-pants, and provides both observ-ability and regulatory efficiency. Between the Band-Aid and surgi-cal separation are a plethora of alternatives that operate to increase the operation of the com-petitive wholesale electric market. The only questions remaining are what alternatives will be chosen, how long we will have to wait before we see the end of the transi-

tion, and how much market abuse will occur in the interim.

j

Endnotes:

1.

A flowgate is a critical element within the Eastern interconnected transmission system as defined by NERC.

2.

See NERC Operating Manual, Policy 9,

Security Coordinator Procedures

, Appendix C.

3.

FERC and NERC have recognized the lack of transparency in CBM calcula-tions. In summer 1999, FERC ordered that utilities post the amount of capacity reserved for and method of determining CBM on their OASIS sites. The Commis-sion required a series of short-term solu-tions, while asking NERC to develop a single method for determining CBM as a permanent solution. The regional reli-ability councils have either developed or are in the process of developing regional standards of calculating CBM.

4.

See FERC Docket No. EL99-46-000, Capacity Benefit Margin in Computing Available Transmission Capacity, July 29, 1999.

5.

See recent FERC Docket No. EL98-36-000,

Aquila Power Corporation v. Entergy Services

, a complaint on Aquila’s part that Entergy failed to designate resources to its reservations of firm import capacity.

6.

Note that in other instances where ATC has drastically dropped to zero, an associated TLR has been identified, and such a zero posting remains as the final status for the offering of the day in question.

7.

It need be recalled that under the rules of FERC Order No. 888 priority is given to requests for firm service over requests for nonfirm under all conditions. In addition, longer contracts are given pri-ority over contract requests of shorter duration.

8.

These were calculated several months after the TLR. PTDFs are usually calcu-lated seasonally, with differences between calculations being attributable to physical changes, such as line or gen-eration outages.

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Documents

Transmission Markets: Stretching the Rules for Fun and Profit