UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

__________________________________________
							)
San Diego Gas & Electric Company			)
		Complainant,				)
							)
		v.					) 		Docket No. EL00-95-031
							)
Sellers of Energy and Ancillary Services		)
into Markets Operated by the California 		)
Independent System Operator				)
and the California Power Exchange 			)
		Respondents.				) 
							)
							)		
Investigation of Practices of the 			)
California Independent System Operator 		)		Docket No. EL00-98-030 
and the California Power Exchange			)			and EL00-98-033  
							)
							)
California Independent System Operator		)		Docket No. RT01-85-000
Corporation						)			and RT01-85-001
							)
							)
Investigation of Wholesale Rates of Public		)
Sellers of Energy and Ancillary Services in the	) 		Docket No. EL01-68-000
Western Systems Coordinating Council		) 			and EL01-68-001
__________________________________________)

				
REQUEST FOR REHEARING AND CLARIFICATION
OF ENRON POWER MARKETING, INC. AND _________, CORAL POWER, L.L.C., 
AND EXELON CORPORATION

	Pursuant to 16 U.S.C. § 825l (1994) and 18 C.F.R. § 385.713 (1999), Enron Power Marketing, Inc. ("EPMI") and ________________, Coral Power, L.L.C. ("Coral"), and Exelon Corporation, on behalf of its subsidiaries PECO Energy Company and Commonwealth Edison Company ("Exelon") (jointly, "Marketers") hereby request rehearing of the Commission's June 19, 2001 order in this proceeding.  San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange, et al., 95 FERC ¶ 61,418 ("June 19 Order").  Marketers also seek clarification of several aspects of the Order.  In support of the instant requests for rehearing and clarification, we have appended the affidavit of Seabron C. Adamson, President, Frontier Economics, Inc. ("Adamson Affidavit"), who will address the economic consequences of the June 19 Order on markets in California and throughout the West.

I.
SPECIFICATION OF ERRORS

(1)	The Commission's decision not to allow marketers to submit cost justification filings based on their own costs is arbitrary, potentially confiscatory and unsound policy and will prevent marketers from participating in WSCC spot markets, thereby degrading liquidity and reliability, and leading to increased costs for the consumer; 

(2)	The Commission's decision to assess gas costs incurred by a generator on the basis of monthly averages understates the actual cost of gas; gas costs should instead be calculated on a daily basis; and

(3)	The Commission's decision to revise rates during non-reserve deficiency periods by capping them at the proxy price violates Section 206 of the Federal Power Act (“FPA”) since the Commission has never found that rates charged during those periods are unjust and unreasonable.

II.
BACKGROUND

The central feature of the June 19 Order is the revised Market Monitoring Protocol ("MMP" or "proxy price") that the Commission established for spot market electricity sales in the United States Western Systems Coordinating Council ("WSCC") during both reserve deficiency hours (i.e., when reserves fall below 7%) and non-reserve deficiency hours.  The revised MMP, which took effect on June 20, 2001 and will terminate on September 30, 2002, is based on a formula that attempts to derive the cost at which generation could be produced by the least efficient generator on line during a System Emergency, taking into account gas costs, heat rates, and emission costs, subject to a $6.00 per MWh O&M and a 10% creditworthiness adder for sales made into California.  Claiming that the MMP is a market based mechanism even though it is derived entirely from cost inputs, the Commission nevertheless forbade sellers from including opportunity costs or scarcity rents in their proxy prices.  The Commission also extended the MMP to spot sales in the entire WSCC purportedly to prevent sellers from seeking higher market prices outside of California during emergency periods.
	Although the Commission repeatedly claimed that the more limited MMP mechanism established under the April 26, 2001 order in this proceeding, 95 FERC ¶ 61,115 (“April 26 Order”), was working and had lowered prices, the Commission nevertheless greatly expanded the MMP in the June 19 Order.  In the April 26 Order, the proxy price was limited to periods when the ISO experiences a System Emergency.  However, in the June 19 Order, price controls were applied to sales in California spot markets even when reserves were not short, i.e., during non-reserve deficiency hours.  The price cap during non-emergency periods will be set at 85% of the highest hourly MMP in effect during the most recent prior Stage 1 emergency.  The Commission stated that it was necessary, as a "discretionary" matter, to extent extend price controls to periods even when supplies are not scarce "as an added measure in protecting customers."  June 19 Order, 95 FERC at 62,547.  Thus, price controls will now be in effect in California and throughout the WSCC during all hours of the day until September 30, 2002.
	In employing the market clearing price established by the the California Independent System Operator Corporation ("ISO") to set the maximum price for spot sales in the WSCC, the Commission reasoned that, although electricity markets throughout the West are integrated, no centralized clearinghouse for spot market sales in the WSCC exists outside the ISO markets.   Accordingly, the Commission found that the mitigation proposal must establish the same prices for all markets in order to prevent arbitrage where power is diverted from the lower priced market to the higher priced market.  The Commission concluded that it is critical to treat all sellers throughout the West alike in order to remove incentives to sell in one area versus another during both reserve deficiency and non-reserve deficiency hours.
	The June 19 Order was particularly harsh to marketers.  Declaring marketers to be price takers, the Commission precluded marketers from bidding higher than the generator market clearing proxy price. The Commission adopted this limitation in response to claims that generators could circumvent price mitigation by selling energy to a marketer at a "high" price, potentially the proxy price who, under this theory, would then bid the generation into markets operated by the ISO at a price in excess of the MMP, which it would justify on the basis of its acquisition cost.  As with all sellers, marketers will not be able to include opportunity costs in their bids; moreover, unlike generators, marketers will not have the opportunity to include a reasonable value-added charge to compensate them for justifiable costs associated with the risk management and administrative services that they provide.
	For the reasons discussed more fully below, the Commission’s mitigation plan is unnecessary and damaging to the development of a fully functioning electricity market in the WSCC.  The Commission's mitigation plan will degrade reliability and liquidity, and will inevitably lead to a new wave of generation project cancellations, inefficient utilization of existing baseload and peaking resources, unmitigated demand that will lead to artificial scarcity, muted demand for market-based risk mitigation tools, and the absence of appropriate demand side responses.  To make matters worse, the adoption of yet another mitigation plan is already causing uncertainty and confusion in the market.  In this request for rehearing and clarification, Marketers therefore ask that the Commission hold true to its own statement that:
Buyers and sellers need certainty and closure. To the extent possible, our price mitigation should have clear rules, should set prices before they are charged and should not subject prices to change or adjustment after financial settlement of the day's transactions. Similarly, it should not rely on costly and time consuming administrative processes to set, adjust or justify prices.

As we shall discuss below, the June 19 Order falls short of this objective in certain critical respects. 

III.
REQUEST FOR REHEARING

A.	By Shutting Marketers out of the Market, the June 19 Order is Based on Misplaced Logic and Flawed Economic Analysis; the Commission's Ruling Will Degrade Market Liquidity and Reliability

The June 19 Order prevents marketers from recovering costs incurred to sell their product in the spot markets in excess of the MMP ─ without regard to why those costs were incurred.   See 95 FERC at 62,564. The Commission’s determination is both irrational and unfair to marketers and, unless vacated on rehearing, will undermine the economic incentives that marketers require to participate in those markets.  The inevitable exodus of marketers will damage reliability, cause blackouts, and will lead to a liquidity vacuum in spot markets throughout the WSCC.  As we shall show, this is already causing prices to rise and reliability to be degraded.
As discussed, based on its finding that marketers are “price takers,” the Commission found that the same proxy prices applicable to generators should also be imposed on marketers, with the difference being that the marketer will be denied any opportunity to submit documentation of actual costs in excess of the proxy price.  The Commission provided but a scant explanation for this sweeping limitation, stating only that it is necessary to prevent generators from avoiding the proxy price by selling power to a marketer at a "high" price, who will then resell it to the California market a price in excess of the MMP.  CITE  The Commission adds that prohibiting marketers bidding above the MMP still gives them a "reasonable" opportunity to earn a return because the proxy price reflects the marginal cost of the last unit dispatched.  CITE
There are numerous flaws in the Commission's logic.  First, contrary to the Commission’s finding, there are times when irrespective of whether marketers are not price takers, but instead they must nevertheless be able to charge prices based on economic considerations peculiar to them, without regard to generator production costs.  For instance, at times marketers are required to purchase power at prices above the cap in order to fulfill a contractual obligation to deliver power without recourse.  This can occur if the marketer’s preferred supplier cannot deliver due to a unit outage or a schedule cut by the transmission provider.  Because the Commission’s rules apply to all spot trades and not just the ISO’s supplemental energy market, however, there is no guarantee that the replacement energy supplied to the marketer will equal the cost of replacement energy provided by the marketer will be less than the cap.  In fact, the cost could very well exceed the cap, resulting in losses for the marketer when it must sell the power at the capped price sold. 
Another example involves load following service.  A marketer operating a real time desk often will assume the role of proving providing real time power to a load serving entity.  The load serving entity may be willing to pay for power in excess of the cap in order to receive this service if that will help it preserve reliability and shift market risk to the marketer (who may be subject to penalties for nonperformance).  The marketer will fulfill these obligations by buying power above the cap if necessary.  These purchase costs may not be directly attributable to a generator's production costs and will not be reflected in the MMP.
Second, the June 19 Order completely overlooks the reliability role of marketers. Marketers are willing to take the financial and physical risks to move power throughout the Western grid in response to demand signals.  By not allowing marketers to recover their costs to move the power, such as actual generation costs, transmission costs, administrative costs incurred in arranging the transaction, etc., the power may not get supplied.  Avoidable black-outs may occur, such as what happened in Nevada on June 20, 2001, as discussed in more detail below.
Marketers, therefore, should be allowed to make sales at justifiable prices above the cap based on their own costs.  If not, marketers will be reluctant it will not be economic for marketers to continue providing these and other services.  Allowable costs should include the purchase price of power, applicable transmission costs, and a reasonable profit return.  Having said this, we do not dispute that marketers are price takers much of the time.  But this does not mean that, even then, marketers should not be compensated for the reliability, liquidity, administrative and risk management products that they provide for the market. By completely discounting the value of these services, the June 19 Order is arbitrary and unfair and must be revised if these services will continue to be available in the West.
Liquidity is the ability of buyers and sellers to easily transact in the market through the existence of an observable market price.  Marketers enhance reliability and provide liquidity through the many services that they provide, such as locating available power, scheduling energy transactions, arranging transmission and ancillary service, undertaking transaction settlement functions, and providing billing and credit services.  Without these services, which provide necessary lubricants for the market, buyers would have trouble finding and arranging for needed power, with the result that the number of transactions fall.  Confidence that the market price reflects true market conditions would also fall.  The net effect would be that transaction and information costs associated with the market will increase and reliability will decrease.
In light of their specialized ability to match generation to load, marketers help overcome these obstacles by providing liquidity for the market.  This is true even in California, where the ISO controls the transmission system and has a high degree of control over generators interconnected with that system.  Marketers still play an invaluable role in California by providing scheduling services to generators and by helping arrange out-of-state supplies.  This is important given the high degree of dependence that California has on imports to meet system loads, coupled.  Adamson Affidavit at 8; see generally id. at 7-8.  The services provided by marketers will remain important under the June 19 Order, given that a resource outside of California can comply with that Order by making its generation available in any Western spot market it chooses.  Id. 
As Mr. Adamson explains, marketers play a critical role in providing liquidity in the non-California WSCC, which is highly decentralized and which depends on bilateral trades and corresponding services of intermediaries (such as scheduling power resources and transmission capacity) for maintaining reliability.  Id. at 3, 6, 9.  "[T]he California ISO's auctions and transmission procedures cannot provide this function for the rest of the WSCC ─ for the simple reason that many of the parameters (e.g. flows on tie lines) are outside of its control area."  Id. at 8 (emphasis added).  In addition, while price outcomes in California are interrelated with the remainder of the WSCC, the location of the generator still matters in whether its generation can be provided across the WSCC. Because variations in marginal costs exist in the West, marketers thus play an important role in moving power to where it is most valuable.  For instance, if demand in one state cannot be met from local sources, it will need to be imported from resources potentially located one or more states away.  There is an important coordinating function for an intermediary whose role is to identify additional resources when they are required and to arrange for corresponding transmission capacity.  "This is the role of power marketers, who provide much of the 'market infrastructure' for the WSCC."  Adamson Affidavit at 8.
Without marketers, in fact, power will not flow efficiently and sometimes not at all.  This was demonstrated by the blackouts in Nevada on July __2, 2001 that were caused by the implementation of the MMP on June 20, 2001.  On that day, Nevada Power was unable to obtain adequate supplies of power at the capped price.  In an interview with Dow Jones, an official of Nevada Power explained how the Commission's MMP interfered with the clearing of the bilateral market and made finding power to meet customer load impossible.  Id. at 10.  The official explained that "a marketer with a real-time desk would have been able to find available generating capacity in the WSCC, to organize transmission on an expedited basis, and to provide energy to Nevada Power as needed in order to prevent blackouts."  Id.  (In fact, many marketers have extensive scheduling capabilities that make last minute, interregional sales possible.)  The Nevada Power official explained how the Commission's proxy price methodology made it uneconomic for a marketer to perform this role, even at a nominal or zero profit return, since, by not being able to recover transmission costs, the MMP would have caused it to lose money.  As a result, Nevada experienced blackouts.
Another example involves a recent transaction between [Exelon ] and a QF that wished to sell its power into the grid since it was not being paid by the host utility.  Although the Commission issued an order in this proceeding that permitted such sales to be made, CITE 95 FERC ¶ 61,226, the QF was unable to deliver its power to the grid since it had no contracts in place with the ISO.  In order to facilitate this deal, [Exelon ] agreed to take title to the power and resell it to the ISO.  Once the June 19 Order was issued, however, [Exelon ] was no longer able to recover its costs (namely, the cost of the QF generation) by bidding into the market, and accordingly terminated the deal.  This has resulted in a resource that was operationally available being precluded from providing energy into California because the marketer that facilitated the deal was unable to recover its costs at a bid in excess of the MMP.
The Commission continues to undervalue or ignore the willingness and capability of marketers to respond to continually changing market and regulatory conditions on both a long-term and emergency basis, by taking on risks to deliver any available power from anywhere on the grid to anywhere it is needed, when it is needed.  This risk-taking maximizes reliability by enabling the utilization of all available resources.
 It should come as no surprise that, if marketers are going to continue to participate in Western spot markets and provide these services, they must be able to recover their costs and make a fair profit return.  Otherwise, they will spurn those markets be precluded from participating in the market.  Marketers must therefore be compensated for the reliability, liquidity, risk management and other services that they bring to the market.  This is the case irrespective of whether those costs would be in excess of the MMP.  The Commission’s determination not to allow marketers the right to petition to recover their actual costs is thus unfair, potentially confiscatory, and shortsighted regulatory policy.ŠThe policy.  The better approach would be to allow marketers to charge in excess of the generator proxy price, subject to justification based on their actual costs plus a reasonable profit. Alternatively, the proxy price available to generators could be assessed on a netback basis. Under this approach, marketers would include in their justification filings the cost of transmission and other expenses (including reasonable profit) necessary to make the generation available to the market. To the extent the delivered cost exceeds the MMP, the difference would be subtracted from the amounts the ISO pays to the generator as part of its clearing function return. 

B.	
The Commission's Decision to Utilize Monthly Gas Prices for Determining the MMP was Flawed; the Commission must return to a Daily Gas Price

In a move that had little to do with the Commission's primary goal under the June 19 Order of applying mitigation to the entire WSCC in all hours, the Commission changed the gas price used as the basis of the MMP.  The Commission apparently accepted, without critical analysis, the illogical statements from the ISO and the California Electricity Oversight Board ("EOB") that monthly gas prices somehow provide a better measure of marginal costs than daily gas prices.  See 95 FERC at 62,560.  The Commission’s decision was misguided and will skew the reasonableness and accuracy of the MMP.
It is indisputable that a daily market for natural gas exists in California.  Indeed, the mitigation method established under the April 26 Order in this proceeding was based on daily prices.  Thus, on reserve-deficiency days, the daily price of natural gas will more accurately reflect market conditions than the month-ahead price, which is set during the latter half of the previous month.  Because generators cannot be reasonably expected to possibly know in advance their gas burns on future reserve deficiency days, it is unreasonable for the Commission to find that month-ahead gas prices reflect a generator's gas costs during a System Emergency.
In his report to the Commission at the conclusion of the recent settlement conference convened in this proceeding, Chief Judge Curtis L. Wagner recommended that refunds be based on the June 19 Order proxy price, subject to certain modifications.  One of those modifications is the use of daily prices (rather than monthly averages) to replicate generation costs.  See "Report and Recommendation of Chief Judge and Certification of Record" ("Wagner Report") at 6-7, issued July 12, 2001.
Judge Wagner’s recommendation is supported on the public record by the testimony of John Stout, Senior Vice President, Assets Commercialization, Reliant Energy Wholesale Group.  Mr. Stout testified that, in California, no entity knows from day to day exactly how much gas it needs or when it is going to need it.  A bid week monthly index price only works where the seller sells into a long-term market; only then would be prudent to buy monthly gas or long-term gas.  In California, by contrast, sellers must purchase gas in the spot market to make spot market electricity sales to the ISO and PX.  [CORRECT?] It is impossible to arrange this gas on a month-ahead basis.  “Instead, you basically have to get the gas as you’re dispatched by the ISO . . . you’re buying it at daily spot prices, not month-ahead index prices.”  Testimony of John Stout, tr Tr. 601.  Mr. Stout concluded that using a monthly pricing methodology for the October 2000–May 2001 period for SoCal Large Packages results in gas costs that are 16 percent lower than the average of actual daily gas prices for the same delivery point.  “That introduces basically a 16 percent error in the calculation.”  Id. at 602.
	At a minimum, therefore, if the Commission is to cap prices on the basis of a proxy price that attempts to replicate actual costs for the least efficient generator, the Commission must utilize consistent time averages in constructing its mitigation measure.  Indeed, the Commission  has chosen hourly heat rates because the heat rates better reflect marginal costs in such hours.  There is no reason why the Commission should not do the same for gas costs.  Using similar logic as it employed in setting heat rates, the Commission should therefore utilize the most disaggregated gas market for gas prices:  the daily market.
C.	The Imposition of Price Mitigation During Non-Reserve Deficiency Hours ─  When Supplies in California and WSCC Spot Markets are Not Tight and Prices Have Not Been Found to be Unjust and Unreasonable ─ Exceeds the Commission’s Statutory Authority under Section 206

	The Commission’s action throughout this proceeding have been taken pursuant to its limited remedial authority under FPA Section 206.  Because there has been no finding that prices in California and WSCC markets during non-emergency hours have been, are, or will be unjust and unreasonable without mitigation, the Commission is thus without authority to revise them under Section 206.  The Commission’s decision nevertheless to revise the rates of sellers previously authorized under their market based rate certificates to sell electricity at market prices ─ by capping them at 85% of the proxy price established during the most recent Stage 1 emergency ─ exceeds its statutory authority.
1.	There is No Evidence in the Record and Indeed the Commission has Never Found that Rates During Non-Emergency Hours are Unjust and Unreasonable and in Need of Mitigation.

As the Commission correctly observed in this proceeding, under Section 206, it “may establish new rates only if it first has a record to determine that the existing rates are unjust, unreasonable, unduly discriminatory or preferential.  Further, once such a finding is made as to existing rates, the Commission must have a record to support the new rate it establishes as just and reasonable."  San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange, et al., 92 FERC ¶ 61,172 at 61,606 (2000); December 15 Order, 93 FERC ¶ 61,294 at 62,019;  see also Cities of Batavia, et al. v. FERC, [CITE] [OTHER CASES].  No such finding has ever been made here.
	In its November 1, 2000 order in this proceeding, the Commission found that "there is clear evidence that the California market structure and rules provide the opportunity for sellers to exercise market power when supply is tight and can result in unjust and unreasonable rates under the FPA."  93 FERC ¶ 61,121 at 61,350, 61,367 (2000) (emphasis added).  The Commission added that, "[u]nder such conditions,” it “is obligated under FPA section 206 to take action to establish market rules, regulations and practices that will ensure just and reasonable rates in the future."  See id. at 61,350.  This finding was reaffirmed in the December 15, 2000 order herein, when the Commission stated that the market structures and rules for wholesale sales of electric energy in California were seriously flawed and, in addition to the supply and demand imbalances in California, have caused, and continue to have the potential to cause, unjust and unreasonable rates for short-term energy under "certain conditions." 93 FERC ¶ at 61,998-99 (2000).  While somewhat vague on what those “certain conditions” are, the Commission, in its March 9, 2001 order in this proceeding, 94 FERC ¶ 61,245 at 61,862 (2001)(emphasis added), reaffirmed its finding that the potential for unjust and unreasonable rate rates in ISO and PX real-time markets relates to periods of reserve deficiency, stating that, after analyzing generators' weekly transaction reports, "potential market power is most likely to be exercised during periods of the most severe supply/demand imbalance."  (Emphasis added)
Stated more directly, at no time, including in the June 19 Order, has the Commission ever found that unjust and unreasonable prices or market manipulation exist or would exist when supply and demand are in balance and no individual generator has a dominant market share.  To the contrary, in the June 19 Order, the Commission found that during periods of reserve sufficiency, "prices should be disciplined sufficiently and should reflect an accurate measure of the shortage confronting the West and provide a clear price signal to induce new supply."  June 19 Order, 95 FERC at 62,547.  The Commission added that it "view[s] prices above the marginal cost of generation in [non-reserve deficiency] hours as a necessary reflection of the supply shortage at hand." Id.  The Commission also acknowledged that "regulators are ill-equipped to replicate the premiums which a functioning market assigns to a diminishing supply," and stated that, for this reason, it decided in its April 26 Order to rely on prices in reserve sufficiency hours to send the correct price signals.  Id.   The Commission reasoned that “recent data show that during hours of sufficient operating reserves, the average hourly Imbalance energy price has been at zero and at times a negative value. . . . indicat[ing] that either there were no transactions in this market or that generation actually exceeded load during these hours.” Id. at 62,568.
Notwithstanding these findings, the Commission then contradicts itself by revising rates in Western wholesale markets during the same non-emergency periods its own findings show are in no need of revision.  It does so on the basis of its claimed "discretionary” powers.  Id. at 62,547.  Although the Commission’s "statutory responsibility . . . gives it broad authority to adapt it's ratemaking policies to the practical realities facing it," id. at 62,549, this does not give the Commission discretion to arbitrarily revise rates through mitigation when supplies are plentiful that it has not found to be unjust and unreasonable. To the contrary, the Commission has authority to act under Section 206 only where it first expressly determines that the existing rates are unjust and unreasonable.  CITES  In this instance, the Commission has made the opposite finding, namely, that rates in California and WSCC markets during non-reserve deficiency hours are just and reasonable.  The Commission is thus barred as a matter of law from capping rates in California and WSCC spot markets during non-emergency periods. 

2.	Even if, Arguendo, the Commission Adequately Justified the Need for Mitigation During Non-Emergency Hours, It Nevertheless Acted Capriciously By Adopting the 85% Factor Based Upon Prices During the Last Stage 1 System Emergency.

	The Commission has offered no reason for capping prices during non-reserve deficiency hours at 85% of the highest ISO hourly market clearing price during the last Stage 1 Emergency. Nowhere has the Commission provided a rational connection between facts found and the use of the 85% factor.  Why not an 87% factor, or a 90% factor, and so forth?  The Commission is not authorized to act where its actions are "arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law." Michigan Consolidated Gas Co. v. FERC, 883 F.2d 117,120 (quoting 5 U.S.C. § 706(2)(A)).  Rather, “reasoned decisionmaking requires a rational connection between the facts found and the choice made.”  Kansas Gas & Electric Company v. FERC, 758 F.2d 713, 721 (D.C. Cir. 1985)(citations omitted). The Commission's decision to cap prices during non-reserve deficiency periods at 85% of a benchmark price, without any explanation for why 85% is the correct factor, is thus arbitrary and capricious, and must be adequately justified or abandoned on rehearing.
Nor did the Commission deal with the very real concern that a proxy price based on the last Stage 1 Emergency could result in outdated gas costs affecting current ceiling prices.  Whether such a price will remain relevant to current conditions depends in part on when the last Stage 1 Emergency occurred.  As time passes, the proxy price in effect during the last Stage 1 Emergency will become increasingly irrelevant.  If gas costs go down in the interval, the proxy price may overstate the current cost of generating electricity.  Conversely, if gas costs go up, the proxy price envisioned by the Commission will not adequately compensate sellers.
In light of the ISO's ability to unilaterally determine when Stage 1 Emergencies exist, the Commission's proposal thus invites gaming by the ISO and its California sponsors to artificially and unfairly reduce the MMP below real clearing prices.  If an existing proxy price during the most recent Stage 1 Emergency is to the ISO's liking, it can manipulate downward the clearing price in effect by not declaring another Stage 1 Emergency in order to avoid a higher updated proxy price.  In fact, there are allegations that this has already been the case.[CAN WE DOCUMENT?]
For these reasons, the proxy price during non-reserve deficiency periods, assuming arguendo that one should even be imposed, should not be based on conditions during the last Stage 1 Emergency.  This is the conclusion reached by Chief Judge Wagner in his July 12, 2001 Report to the Commission at the conclusion of the recent settlement conference.  Judge Wagner found that the use of a historical Stage 1 proxy price would not recreate a competitive market for purposes of calculating retrospective refunds during non-reserve deficiency periods.  Wagner Report at 8.  Ironically, the cap that has the most arbitrary basis is on the one that will likely be in place in most hours.  The disconnect between this cap and the actual marginal cost of power will likely be greatest this winter when California is unlikely to be in a reserve deficiency and the Pacific Northwest experience experiences its annual peak loads.  
If the Commission is to retain a cap in non-reserve deficiency hours (over our objections), Marketers therefore request, at a minimum, that the Commission’s current non-reserve deficiency cap be rescinded and replaced with one that is clear and certain, consistent with the Commission’s own stated goals.  CITE  Such a cap should be known in advance and track marginal costs in the entire West.  A cap While we believe that caps are harmful to the market and should not be imposed, if there is to be a cap, one that would minimize the harmful effects of a cap, as compared with more onerous forms, is one that meets this goal would be set at the heat rate of the highest heat-rate unit available in the West times the highest daily gas spot price at either Sumas, Malin, PG&E Citygate, or Topock.  Such a cap is essentially the same as the proxy price method already adopted by the Commission in its earlier refund orders, except that it would reflect daily gas prices.  Since this cap would apply only during non-reserve deficiency hours, it need not be fine tuned to hourly marginal costs in California. 

IV.
REQUEST FOR CLARIFICATION 

Marketers request that the Commission clarify the June 19 Order in the following respects:
A.	The Commission Should Clarify that the Proxy Price Cap Will be Known at the Time a Deal is Confirmed

While Marketers are opposed to caps in general, if a cap is to be imposed, the cap for a  given hour must be certain and known in advance.  As quoted earlier, the Commission has already observed in this proceeding that buyers and sellers need certainty and closure and that, to the extent possible, the mitigation plan should have clear rules, should set prices before they are charged and should not be subject prices to change or adjustment after financial settlement of the day's transactions.  See 95 FERC at 62,547-48; see also Adamson Affidavit at 11.  Marketers therefore request that the Commission clarify that the relevant cap is the proxy price in place when a deal is confirmed.  
This is a significant consideration.  Although the spot market involves only trades that occur on the day before or day of delivery, circumstances can change significantly during the course of even one day.  For instance, the ISO could go into a reserve deficiency, in which case the cap could change.  Liquidity will be degraded if suppliers are subject to refunding revenues based solely on whether the cap falls between the confirmation and delivery hours, a circumstance beyond the ability of the marketer to control or affect.  Given a choice between doing a trade that may be subject to refund or foregoing the trade altogether, marketers may choose the latter.  Generators may still be obligated to offer power but, as discussed, without marketers, the generator’s power may not find the market that values the power the most region that values it the most to meet demand, or may find no market at all because the generator was not willing to take the risks or did not have in place the arrangements necessary to move its power to any market. 
	Clearly, the current cap, which can change hourly and without notice, does not provide the certainty the Commission supports.  A simple solution is for the Commission to clarify that it will exclude from review any spot transaction that is at or below the cap at the time the deal is confirmed.  Other solutions are possible, such as changing the way the cap is set so that it is known in advance of trading.  

B.	The Commission Should Clarify the Types of Transactions that Are and Are not “Marketer” Transactions 

There are a number of market participants that perform functions that resemble those performed by marketers, but which differ in critical respects. In order to avoid confusion, we
	In the event rehearing is not granted so as to allow marketers to justify their actual costs even if in excess of the MMP, as discussed above, Marketers request that the Commission clarify that the following entities are not “marketers” for purposes that perform functions that resemble those performed by marketers, but which differ in critical respects, are not to be treated as "marketers" within the scope of the mitigation mechanism established by the June 19 Order:. 
1.	Scheduling Coordinators and Agents.  For some transactions, marketers fulfill functions normally provided by a Scheduling Coordinator (“SC”) for a specific generator, or otherwise acts as the generator’s agent, such as Exelon did for the QF discussed earlier.  In some cases, due to longstanding arrangements, the marketer takes legal title to the power for accounting convenience or to internalize the risk of making a short-term dispatch decision on behalf of the generator, thus making the power being sold to the ultimate customer a “marketer” transaction. [ALAN: GIVE ME A BENIGN REASON WHY A MARKETER WOULD DO SO]
A marketer should not be penalized for providing this service; nor should it be precluded from filing to recover costs incurred if it acts a SC, irrespective of whether those costs push the overall cost of a particular transaction above the otherwise applicable MMP, so long as the marketer can show that a specific generator supplied the power for that transaction.  The justified costs in this circumstance would not be based upon the purchase price, but would be based upon the generator’s direct marginal costs (i.e., the costs that are otherwise allowed as justification by generators).  The Commission should also allow for reasonable SC or agent fees, which could be verified by a certification letter from the generator.
2.	Tolling Arrangements.  Tollers are entities that typically provide the fuel to a generator for the generation that they produce and take title to the output from the plant.  Tollers do not own a generator; they essentially lease or rent the plant.  The Commission should clarify that a toller, which has exclusive rights to the generator for the duration of a transaction, has the same rights as the generator itself for such discrete transactions, including the ability to sell above the cap with justification.

C.	The Commission Should Clarify that Option Agreements that are Exercised for  Spot-Market Sales Should Not Themselves be Considered as Involving Spot Sales

The June 19 Order is silent as to whether option agreements fall under the Commission’s definition of spot transaction.  In a typical option agreement, an entity has the right to buy power at a specified strike price.  The holder has the right to exercise the option up until its expiration.  Clearly, option agreements that are negotiated and expire in advance of the day-before/day-of deliver hour are not subject to the MMP.  
Many option agreements, however, are structured to expire on the morning of the day before delivery.  If the buyer exercises the option, it can obtain the power at the strike price.  In some cases, the strike price, which is agreed to in advance, may be above the cap.  Thus, while the ultimate confirmation of the trade occurs during the spot transaction period, the price and the option to buy were negotiated in advance of the spot period.  The Commission’s rationale for regulating spot markets is that buyers have few supply alternatives in the spot market and therefore mitigation is required.  This logic does not extend to options since the buyer made its purchase decisions in advance of the spot market time frame.  Consistent with this logic, the Commission should clarify that option agreements are exempt from the proxy price cap. 

D.	The Commission Should Clarify that the Only Above-Cap Bids that Require Justification are Those that are Accepted

Finally, we request clarification that justification for above-cap bids is required only for those that are accepted.  This clarification is made necessary by statements made by the ISO in its July 10, 2001 compliance filing in response to the June 19 Order, where the ISO argues that justification should be provided even for bids that are not accepted:
However, regardless of whether or not bids above the maximum Market Clearing Price are accepted by the ISO, the ISO believes that all Market Participants that submit such bids should be required to provide a justification for the bids. All bids above the maximum Market Clearing Price, whether accepted or not, should be justified in order to identify potential inappropriate or anticompetitive behavior.

Trans. Ltr. at 18.  
The ISO's position is untenable.  In the June 19 Order, 95 FERC at 62,547, the Commission stated that it “will allow sellers other than marketers the opportunity to justify prices above the market clearing price during reserve deficiency hours and we will provide guidance on the specific showing that a seller must make.”  In other places, the Commission refers to "transactions" and "bids" when referring to cost justification.  CITE  The only logical interpretation of the June 19 Order is that justification need be provided only for accepted bids. If the ISO receives all the power it needs for it to fulfill its mandate to maintain reliability, it can evaluate market power by examining the marginal, accepted bids. Examining unaccepted bids adds nothing to the analysis, creates an administrative burden, smacks of an attempt to intimate intimidate market participants, and is a waste of resources given that cost justification is a WSCC-wide requirement.  
For these reasons, the Commission should reject the ISO’s attempt to broaden the June 19 Order beyond its intended scope and clarify that the only bids that require justification are those that were accepted by the ISO or other spot market buyer.  

V.
CONCLUSION

	The Commission should grant rehearing in order to (1) allow marketers to make cost justification filings based on their own costs plus a reasonable profit return; (2) use daily gas costs for calculating the MMP, and (3) disclaim any intent to impose proxy prices on sales during non-reserve deficiency periods.  The Commission should also grant the clarifications requested herein. 
						Respectfully submitted,

						_____________________________________
Ronald N. Carroll
Jacqueline R. Java
Bracewell & Patterson, L.L.P
A Registered Limited Liability Partnership
2000 K Street, N.W., Ste. 500
Washington, D.C.  20006
(202) 828-5800

Attorneys for Enron Power Marketing, Inc.

July 19, 2001

	CERTIFICATE OF SERVICE

Pursuant to Rule 2010 of the Commission's Rules of Practice and Procedure, I hereby certify that I have this day served a copy of the foregoing document on all persons designated on the official service list compiled by the Secretary in this proceeding.

Dated at Washington, D.C., this 19th day of July 2001.

_____________________________________
           Ronald N. Carroll

145352.3

145352.4

---------------------- REVISION LIST ----------------------

The bracketed numbers refer to the Page and Paragraph for the start of the paragraph in both the old and the new documents.

[1:32 1:32] Changed	"AND _________" to ", CORAL POWER, L.L.C., "
[1:32 1:33] Add Para	"AND EXELON CORPORATION"
[1:33 1:34] Changed	"and ________________ " to ", Coral Power,  ...  ("Exelon") "
[3:1 3:1] Changed	"extent " to "extend "
[4:2 4:2] Changed	"reasonable value-added charge" to "reasonable charge"
[4:2 4:2] Changed	"for the" to "for justifiable  ...  associated with the"
[5:1 5:1] Changed	"will inevitably" to "will degrade  ...  inevitably"
[5:7 7:4] Changed	"reliability and" to "reliability,  ...  blackouts, and"
[6:2 8:1] Changed	"contrary to  ...  times when " to "irrespective of whether "
[6:2 8:1] Changed	"are not price" to "are price"
[6:2 8:1] Changed	"but instead " to "they "
[6:2 8:1] Changed	"must be" to "must nevertheless be"
[6:2 8:1] Changed	"replacement  ...  equal the " to "cost of replacement  ...  the capped "
[6:2 8:1] Changed	"price sold." to "price."
[7:1 8:2] Changed	"proving " to "providing "
[7:2 8:3] Add Para	"Second, the June  ...  more detail below."
[7:2 9:1] Changed	"marketers  ...  reluctant " to "it will not  ...  marketers "
[7:2 9:1] Changed	"profit" to "return"
[7:3 9:2] Changed	"costs associated  ...  increase." to "costs will  ...  decrease."
[8:1 9:3] Changed	"loads, coupled." to "loads."
[9:1 11:1] Changed	"__" to "2"
[9:1 11:1] Changed	"profit" to "return"
[9:2 11:2] Changed	"between [Exelon]" to "between Exelon"
[9:2 11:2] Changed	"[Exelon] and" to "Exelon and"
[9:2 11:2] Changed	"order that" to "order in this proceeding that"
[9:2 11:2] Changed	"CITE" to "95 FERC ¶ 61,226"
[9:2 11:2] Changed	"deal, [Exelon]" to "deal, Exelon"
[9:2 11:2] Changed	"[Exelon] agreed" to "Exelon agreed"
[9:2 11:2] Changed	"however, [Exelon]" to "however, Exelon"
[9:2 11:2] Changed	"[Exelon] was" to "Exelon was"
[10:1 12:1] Add Para	"The Commission  ...  available resources."
[10:1 12:2] Chgd All	"profit" to "return"
[10:1 12:2] Changed	"spurn those markets" to "be precluded  ...  the market"
[10:1 12:2] Changed	"policy.ŠThe " to "policy. The "
[11:3 14:3] Changed	"expected to " to "possibly "
[12:1 15:1] Changed	"PX. [CORRECT?] It" to "PX. It"
[12:1 15:1] Changed	"Stout, tr." to "Stout, Tr."
[13:5 16:5] Changed	"(2001) (emphasis added)," to "(2001),"
[13:5 16:5] Changed	"rate " to "rates "
[13:5 16:5] Changed	"imbalance." " to "imbalance." (Emphasis added)"
[17:3 20:3] Changed	"did Commission" to "did the Commission"
[18:1 21:1] Changed	"fact, this" to "fact, there  ...  that this"
[18:1 21:1] Changed	"case. [CAN WE DOCUMENT?]" to "case."
[18:2 21:2] Changed	"experience " to "experiences "
[18:3 22:1] Changed	"A cap " to "While we believe  ...  forms, is one "
[18:3 22:1] Changed	"that meets this goal would" to "that would"
[20:1 23:1] Changed	"market that  ...  power the most" to "region that  ...  any market"
[20:4 24:2] Changed	"There are  ...  confusion, we " to "In the event  ...  Marketers "
[20:4 24:2] Changed	"are not “marketers” for purposes " to "that perform  ...  the scope "
[20:4 24:2] Changed	"by the June" to "by June"
[20:4 24:2] Changed	": " to ". "
[20:5 24:3] Changed	"agent." to "agent, such  ...  discussed earlier."
[20:5 24:3] Changed	"power," to "power for  ...  generator,"
[20:5 24:3] Changed	"transaction.  ...  WOULD DO SO] " to "transaction. "
[23:1 26:4] Changed	"bids. If the  ...  Examining" to "bids. Examining"
[23:1 26:4] Changed	"intimate " to "intimidate "
[25:3 28:3] Changed	"profit" to "return"
[27:6 30:6] Changed	"145352.3" to "145352.4"

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original document   : I:\DOCSOPEN\CARRRN\0145352.03
and revised document: I:\DOCSOPEN\CARRRN\0145352.04

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