DC_DOCS_A 1049583 v 10

UNITED STATES OF AMERICABEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

DIGHTON POWER ASSOCIATES LIMITEDPARTNERSHIP, FPL ENERGY, L.L.C.,SOUTHERN ENERGY NEW ENGLAND,L.L.C., and SOUTHERN ENERGY KENDALL,L.L.C.

v.

ISO NEW ENGLAND INC.

)))))))))

Docket No. EL00-40-000

ANSWER OF ISO NEW ENGLAND INC.

Pursuant to Rules 206(b) and 213 of the Commission’s Rules of Practice and Procedure,

18 C.F.R. §§ 385.206(b) and 213 (1999), ISO New England Inc. (the “ISO”) hereby answers the

complaint (the “Complaint”) filed jointly by Dighton Power Associates Limited Partnership, FPL

Energy, L.L.C., Southern Energy New England, L.L.C., and Southern Energy Kendall, L.L.C.

(collectively, the “Complainants”).

The Complaint alleges that the ISO has administered the New England Power Pool

(“NEPOOL”) Operable Capability (“OpCap”) market in a manner contrary to the terms set forth

in the applicable rate schedules on file with the Commission. Complainants also allege that the

ISO violated the Federal Power Act (“FPA”) and the Filed-Rate Doctrine by establishing clearing

prices in the OpCap market prior to August 5, 1999 according to rules and procedures approved

by the Commission for application beginning August 5, 1999. The ISO answers and denies these

and other related allegations, as set forth herein.

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I. EXECUTIVE SUMMARY, INTRODUCTION AND STATEMENT OF FACTS

A. EXECUTIVE SUMMARY

The OpCap Market for the period from May 1, 1999 through August 5, 1999 is being

settled consistent with the NEPOOL market rules that were in effect prior to August 5, 1999, as

interpreted by the ISO.

• Settlement of the OpCap market for the period in question required the ISO tointerpret existing Market Rules in accordance with the authority of the ISO asrecognized by the Commission. (Section II)

• These interpretations were appropriate and consistent with the filed Market Rules.(Section III)

• The ISO’s interpretive actions were within the ISO’s authority and did not requirea filing, as confirmed in Commission precedent involving independent systemoperators; indeed, the ISO’s authority to interpret the market rules is an essentialelement of the ISO’s independence, is necessary for the ISO to meet itsresponsibility to administer and settle the markets and fulfills a key role under themarket-based rate precedent. (Section IV)

Accordingly, settlement of the OpCap Market during the period from May 1, 1999

through August 5, 1999 is in accordance with the filed Market Rules and the Operating

Procedures and not in violation of the FPA.

The Complaint’s reliance on the Filed Rate Doctrine is misplaced (see Section V), in part

because of two incorrect assertions by Complainants. To correct these assertions, the ISO

provides evidence that:

• The ISO has not applied the price cap added to Market Rule 10.4.5 to settlementsfor the period prior to the August 5, 1999 effective date of the price cap.

• The ISO has not applied the interpretive amendments retroactively to the pre-August 5 period. Instead, it made, and publicized to market participants, itsinterpretations well in advance of August 5. The filing of the interpretiveamendments with the Commission was simply designed to increase markettransparency by incorporating the interpretations into the market rules on a going-

1 ISO New England Inc., 88 FERC ¶ 61,316 (1999)(the “September Order”).

2 The current version of the ISO Agreement was filed in Docket No. EC97-35-003.

3 The Market Rules are posted on the ISO’s web site (www.iso-ne.com/market_system/).

DC_DOCS_A 1049583 v 10 3

forward basis.

Finally, the Commission’s September 30, 1999 order in Docket No. ER99-40021 is

consistent with the ISO’s position and does not suggest that the ISO’s actions have been

improper. (see Section VI)

B. INTRODUCTION AND STATEMENT OF FACTS

1. The ISO and its Operational Responsibilities

The ISO is the private, non-profit Independent System Operator for New England.

Pursuant to the Interim Independent System Operator Agreement (the "ISO Agreement")

between the ISO and NEPOOL,2 the ISO administers seven product markets for NEPOOL,

namely: (1) Energy; (2) Ten-Minute Spinning Reserve (“TMSR”); (3) Automatic Generation

Control (“AGC”); (4) Ten-Minute Non-Spinning Reserve (“TMNSR”); (5) Thirty-Minute

Operating Reserve (“TMOR”); (6) OpCap and (7) Installed Capability (“ICAP”) (each, a

“Market”, and collectively, the “Markets”). The ISO operates the Markets pursuant to the

Restated NEPOOL Agreement (the “RNA”) and a series of rules and appendices thereto (each, a

“Market Rule” and collectively, the “Market Rules”), all of which have been filed with the

Commission).3

OpCap is the Installed Capability (i.e., the maximum dependable load-carrying ability of

generating unit(s)) that is operating or available to respond within an appropriate period to: (1)

the ISO’s call to meet Energy and/or Operating Reserve and/or AGC requirements of the

NEPOOL Control Area during a scheduled dispatch period, or (2) a Participant-submitted

4 RNA § 1.67.

5 That is, the OpCap clearing price is calculated as part of the subsequent Settlementfunction (see Market Rule 10.3), rather than on the day of trading.

6 RNA § 12.6(a).

7 RNA § 12.6(b).

8 ISO Agreement § 6.6.

9 The OPs are also posted on the ISO’s website (http://www.iso-ne.com/operating_procedures/documents/Contents_&_Links.html).

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schedule for that hour.4 The OpCap Market is an after-the-fact market (rather than a real-time

market5) which provides that to the extent that a Participant’s OpCap Settlement Obligation

(defined in the Market Rules as the sum of load and reserve obligation) is not satisfied through its

own resources or purchases, it shall have been considered to have purchased OpCap in the spot

market6 at a clearing price equal to the highest accepted bid in the market.7 The OpCap Market is

operated pursuant to Market Rule 10; the TMSR, TMNSR and TMOR Markets are operated

pursuant to Market Rules 6, 8 and 9, respectively.

The ISO operates the New England bulk power system pursuant to the ISO Agreement,

the RNA and the NEPOOL Open Access Transmission Tariff (“NOATT”). Under the ISO

Agreement, the ISO has the responsibility to ensure the short-term reliability of the

New England control area.8 Operation of the bulk power system in New England by the ISO is

in accordance with a series of documents known as “Operating Procedures” or “OPs.”9

For the discussion that follows, two OPs are particularly important – OP 8 and OP 4. OP

8 sets forth the criteria for establishing and administrating Operating Reserve and Automatic

10 NEPOOL filed OP 8 with the Commission in Docket No. OA97-237 as part of thecomprehensive settlement with respect to the NOATT.

11 Ten Minute Reserve may be either synchronized (i.e., TMSR) or nonsynchronized (i.e.,TMNSR) to the system. The split between the two types of reserves is determined by thecontrol area’s past performance in meeting reliability criteria and pursuant to the discretionafforded the ISO in OP 8.

12 OP 4 was invoked on June 1, 2, 7, 8, 28 and 29, and July 5, 6, 19, 29 and 30, 1999.

13 The ISO purchased emergency power on June 1, 2, 7, 8, 28 and 29 and July 5, 6 and 30,(continued...)

DC_DOCS_A 1049583 v 10 5

Generation Control in the New England control area.10 Operating Reserve is defined to include

capacity available within ten minutes (both online and offline) and capacity available within thirty

minutes.11 OP 8 defines the level of Ten-Minute Reserve and Thirty-Minute Reserve that must be

maintained by the ISO pursuant to applicable reliability requirements of NEPOOL and the

Northeast Power Coordinating Council.

OP 4 establishes criteria and guides for emergency actions during capacity deficiencies, as

directed by the ISO and as implemented by the ISO and satellite control centers. OP 4 specifies

15 actions that may be directed by the ISO, including: (a) curtailing interruptible loads, (b)

purchasing emergency capacity and energy from other pools and control areas, (c) allowing

TMOR to go to zero, (d) reducing TMSR requirements, (e) voltage reduction and (f) appeals for

load curtailment. OP 4 is consistent with NERC criteria for emergency situations.

2. Capacity Shortages Occurring In June and July 1999; Related OpCapSettlements

In June and July 1999, the ISO experienced shortages in available reserves and was

forced to invoke OP 4.12 In several of these instances, the ISO was required to purchase

emergency capacity and energy from neighboring control areas pursuant to longstanding

interconnection agreements between the NEPOOL Participants and those areas.13 The ISO

13 (...continued)1999.

14 Settlement procedures are described in Market Rule 18.

15 A lag in settlement is consistent with the after-the-fact nature of the OpCap Market. Inorder to settle the OpCap Market, the ISO must obtain meter and bilateral contract dataand other information that is not available until a number of days after the day at issue.

DC_DOCS_A 1049583 v 10 6

administers these agreements under Section 6.10 of the ISO Agreement.

In the ordinary process of settling the OpCap and other Markets,14 the ISO sends

preliminary settlement statements to the Participants, subject to further review. In the process of

determining the preliminary settlements for the OpCap Market beginning on June 1, the ISO

realized that the impacts of OP 4 actions, including emergency purchases of energy and capacity,

upon Participants’ obligations and resources were not explicitly addressed in Market Rule 10,

which contains the rules for settling the OpCap Market. In order to settle the OpCap Market, the

ISO interpreted Market Rule 10 and related contracts, rules and procedures.

On June 28, 1999, the ISO posted on its website a notice (Attachment A to the

Complaint) that the ISO had completed its preliminary settlement of the hourly markets for June 7

and 8. The notice indicated that the settlement was “being reviewed by the ISO and...SUBJECT

TO CHANGE.”15 Because of the need for further review, the notice stated that in the preliminary

settlement reports being released that day, the OpCap settlement data would reflect an OpCap

Market Clearing Price of $0.00 for all hours of June 7 and 8. Further, the notice stated that

Revised Settlements would be performed and revised reports published after the ISO has

completed its review.

On June 30, 1999, the ISO posted on its website another notice (Attachment B to the

Complaint) reflecting its further review of the preliminary settlements, describing the ISO’s

DC_DOCS_A 1049583 v 10 7

interpretation of the impacts of OP 4 actions and emergency purchases on the settlements in the

OpCap Market. The notice listed the settlement prices for the hours of June 7 and 8, and stated:

ISO New England interprets Market Rule and Procedure 10 – Operable Capabilityto provide for allocation of the Operable Capability associated with EmergencyPurchases to those entities paying the cost of those Emergency Purchases (entitieswith a negative Adjusted Net Interchange [“Negative ANI”]).

Preliminary Settlements will be performed using the Operable Capability ClearingPrices listed below. These prices represent an estimate of the impact of thisinterpretation on the Clearing Prices for June 7 and 8. The results of theseSettlements will be included in the bill for June, 1999. These PreliminarySettlements will not reflect the allocation of Operable Capability to thoseParticipants with Negative ANI.

Resettlements will be performed at a later date to reflect the allocation of theOperable Capability to Participants with Negative ANI. The results of thoseresettlements may include revised Clearing Prices for those hours in whichEmergency Purchases occurred. The resettlement results will be included as anadjustment to the bill for a subsequent month.

On July 13, 1999, the ISO sent a memorandum (Attachment 1 hereto) (the “July 13

Memorandum”) to members of the NEPOOL Regional Market Operations Committee (including

representatives of the Complainants) explaining the interpretations the ISO was applying to settle

the OpCap Market for hours in which OP 4 had been implemented:

The ISO has implemented the following interpretations of the Market Rules andProcedures that are applicable to the OpCap market during implementations ofOperating Procedure No. 4 – Action During a Capacity Deficiency (OP 4).

1. During all OP 4 Trading Intervals, the MWs of Operating Reservedesignated by the ISO is compared to the MWs of ISO Operating Reserverequirement in each of the three (3) Operating Reserve markets. To the extent thatthe MWs designated in a market is less than the MWs required in that market, theMWs required are set equal to the MWs designated for that market for thatTrading Interval. This action has the impact of reducing the total OpCaprequirements for that Trading Interval by an equal amount.

2. During OP 4 Trading Intervals in which the ISO purchases emergencyassistance from neighboring control areas, Operable Capability credit, in an amountequal to the total MWh of Emergency Capacity and Energy purchased during the

16 See Affidavit of Charles R. Ide, Attachment 2 hereto (the “Ide Affidavit”), at ¶ 2.

17 The potential infirmities of the OpCap Market’s design were addressed in the report ofProfessors Peter Cramton and Robert Wilson included in the Market Assessment filed bythe ISO on September 9, 1998 in Docket Nos. OA97-237, et al. Recently, NEPOOLfiled with the Commission its proposal to eliminate the OpCap Market. See December 30,1999 Filing of the NEPOOL Participants Committee in Docket No. ER00-985-000.

18 The material filed by the ISO in Docket No. ER99-4002 on August 5 will be referred toherein as the “August 5 Filing.”

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Trading Interval, is allocated to those Participants with a Negative Adjusted NetInterchange (Energy market) for the Trading Interval.

As this course of conduct indicates and as verified in the attached affidavit of the ISO’s

Manager-Settlements, Charles R. Ide,16 settlements for the period from June 1 through August 5

are in accordance with these interpretations of the Market Rules, made and publicized by the ISO

well in advance of ISO’s filing with the Commission on August 5, 1999. A detailed description of

the basis for these interpretations (the “Interpretations”) -- demonstrating that they were

appropriate, correct and consistent with the filed Market Rules -- is contained in Section III of

this Answer.

3. The ISO’s August 5 Filing and the Complainant’s Response

During June and July, the ISO’s analysis of the performance of the OpCap Market

indicated that it had serious design flaws, especially evident during OP 4 conditions.17 In

response, the ISO developed an interim remedy: a price cap mechanism implemented through an

amendment to Market Rule 10.4.5 (the “Price Cap Amendment”). The ISO filed the Price Cap

Amendment on August 5, 1999 (in Docket No. ER99-4002-000), as an emergency rule pursuant

to its authority under Section 6.17(e) of the ISO Agreement.18

Since the ISO was already filing changes to Market Rule 10 for the Price Cap

Amendment, the ISO determined that it would be appropriate to increase the transparency of

19 On page 11 of the August 5 Filing, the ISO specifically described its interpretive actions todate:

The ISO has interpreted Market Rule 10 to mean that the requirement forOperating Capability is equal to the sum of the energy and units actuallydispatched for operating reserve, and the Amendment to Market Rule 10 herewithformally makes that interpretation part of the rule....The emergency Amendment toMarket Rule 10 filed herewith also makes formal a second ISO interpretation ofMarket Rule 10 which gives Operable Capability credit for emergency powerpurchase by the ISO. (emphasis added)

20 See Ide Affidavit ¶ 6.

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market mechanisms by including with the August 5 Filing other amendments to Market Rules

10.4.1, 10.4.2 and 1 reflecting the ISO’s prior Interpretations mentioned above and described in

detail in Section III of this Answer. In the August 5 Filing, the ISO informed the Commission

that the amendments (the “Interpretive Amendments”) had their genesis in existing Interpretations

and were being filed simply to formalize these Interpretations.19 The ISO requested an effective

date of August 5, 1999 for the Price Cap Amendment and the Interpretive Amendments. The

ISO is not using, and has never proposed to use, the Price Cap Amendment to settle the

OpCap Market for the period before August 5, 1999.20

Each of the Complainants intervened and filed protests in the proceeding in Docket No.

ER99-4002, including – as discussed in Section VI below – protests grounded on the same faulty

theories and mischaracterizations found in the Complaint. On September 30, 1999, the

Commission issued its decision in that docket, accepting for filing both the Price Cap Amendment

and the Interpretive Amendments.

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II. SETTLEMENT OF THE OPCAP MARKET FOR THE PERIOD IN QUESTIONREQUIRED THE ISO TO INTERPRET EXISTING MARKET RULES INACCORDANCE WITH THE AUTHORITY OF THE ISO AS RECOGNIZED BYTHE COMMISSION

Even though NEPOOL and the ISO have diligently attempted to make the Market Rules

and Operating Procedures clear and comprehensive, there may be circumstances that are not

explicitly addressed in the Market Rules. In these circumstances, the ISO is required to use its

authority to interpret the Market Rules by referring to the RNA, the OPs and the other Market

Rules to determine how to appropriately administer the market. As explained below, settlement

of the OpCap Market during periods of OP 4 conditions was one of those circumstances.

In order to settle the OpCap Market for any hour, the ISO must calculate for each

Participant its OpCap requirement and its OpCap resources. For OP 4 conditions, this required

the ISO to make two interpretations of Market Rule 10. First, the ISO had to determine whether

the reduction in reserve requirements contemplated by OP 4 reduced a Participant’s OpCap

requirements. The second necessary interpretation was what impact, if any, OpCap from

emergency purchases would have on the settlement.

To make the interpretations necessary to settle the OpCap markets, the ISO examined the

text of the relevant Market Rules and Operating Procedures and the related definitions. The

Interpretations were made by the ISO under its specific authority to do so under the ISO

Agreement. This authority of the ISO was recognized by the Commission in its June 25, 1997

Order authorizing the establishment of the ISO and is consistent with other Commission

precedent, as described in Section IV below. As described in this Section III, the ISO’s

Interpretations were consistent with the filed Market Rules, the filed RNA, the filed ISO

Agreement and the Operating Procedures.

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Failure of the ISO to make the Interpretations of Market Rule 10 would have resulted in

the inability of the ISO to calculate a Participant’s OpCap requirements and resources because:

(1) the reduction in reserves during OP 4 conditions either has to be reflected or not reflected in

the OpCap requirement, and (2) capacity from emergency purchases on behalf of the Participants

collectively either has to be included in or excluded from a Participant’s OpCap Settlement

Obligation. The result sought by Complainants -- to ignore reserve reductions and to exclude

Participant’s emergency capacity purchases -- is an interpretation inconsistent with OP 4, OP 8

and Market Rules 6, 8 and 9 and unsupported by the pricing provision of Market Rule 10 itself.

A failure of the ISO to make the Interpretations would have other ramifications, as well, as set

forth in Section III.C., below.

The discussion below sets forth the reason each interpretation was required, the resulting

interpretation, and analysis of the interpretation sought by Complainants and its effect in the

market.

III. THE INTERPRETATIONS WERE APPROPRIATE AND CONSISTENT WITHTHE FILED MARKET RULES

As discussed above, in order to settle the OpCap Market for any hour, the ISO must

calculate for each Participant its OpCap requirement and resources. In OP 4 conditions during

June and July 1999, reserve requirements were reduced and emergency capacity and energy were

purchased. As demonstrated herein, the ISO made reasonable interpretations of the RNA, Market

Rules and OPs to determine the impacts of these actions on OpCap requirements and resources.

The ISO set forth these interpretations in its July 13 Memorandum to market participants

(Attachment 1 hereto). These are the interpretations applied by the ISO to the settlement of the

21 See Ide Affidavit, ¶¶ 4, 5.

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OpCap Market for the pre-August 5 period.21

A. THE INTERPRETATION REASONABLY RESOLVED THE ISSUE OFTHE LEVEL OF OPCAP REQUIREMENTS DURING OP 4 CONDITIONS

As explained herein, the only reasonable interpretation of Market Rule 10 is that

reductions in reserve requirements implemented by the ISO in OP 4 conditions reduce

Participants’ OpCap requirements (i.e., its Settlement Obligations) as well. The Complainants’

argument to the contrary cannot withstand analysis, because the determination of the OpCap

requirement is simply a matter of applying a series of linked definitions in documents on file with

the Commission, beginning with the provisions of Market Rule 10 itself.

1. The Definition of OpCap Settlement Obligation Contained in MarketMarket Rule 10

Market Rule 10 governs the operation of the OpCap Market. Prior to its

amendment effective August 5, 1999, Market Rule 10.4.1 stated:

A Participant’s hourly Settlement Obligation for Operable Capability is equal to the sum ofthe following:

a) The Participant’s Electrical Loadb) The Participant’s share of the non-specifically assigned NEPOOL Control

Area TMSR, TMNSR and TMOR Requirements, allocated on itsproportionate share of the NEPOOL Electrical Load

c) The Participant’s Specifically Assigned TMSR, TMNSR and TMORRequirements.

Thus, in order to determine a Participant’s OpCap Settlement Obligation, the ISO must refer to

the Participant’s TMSR, TMNSR and TMOR Requirements, and also determine whether and

how these requirements change under OP 4 conditions.

22 See preamble to Market Rule 1.

23 OP 8, Part III, Section I.A.1 (emphasis added).

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2. Definitions of TMSR, TMNSR and TMOR Requirements in MarketRule 1 and Context

The TMNSR and TMOR Requirements are defined in Market Rule 1 as follows:

132. TMNSR Requirement - the Ten-Minute Non-Spinning Reserve Requirement is therequired MW quantity and capabilities of non-spinning reserve required inaccordance with Operating Procedure No. 8 – Operating Reserve.

* * *135. TMOR Requirement - the Thirty-Minute Non-Spinning Reserve Requirement is

the required MW quantity and capabilities of 30-Minute Spinning Reserve requiredin accordance with Operating Procedure No. 8 – Operating Reserve.

The TMSR Requirement is not defined in the Market Rules. However, Market Rule 1

states: “Where a term is not listed here, the definition of any capitalized term shall be as defined

in the context of the relevant Market Rule.”22 The defining context in Market Rule 10 suggests

that the TMSR Requirement be treated identically to the TMNSR and TMOR Requirements and

should be determined in accordance with OP 8.

3. TMSR, TMNSR and TMOR Requirements Under Normal Conditions

In order to determine the TMSR, TMNSR and TMOR Requirements under OP 4

(capacity-short) conditions, one must read OP 8 to examine how those requirements are

determined under normal conditions. OP 8 states:

During normal conditions, ISO New England shall maintain a quantity of Ten-Minute Reserve at least equal to the amount required to replace the FirstContingency Loss in New England. The energy associated with the AGC ReserveRequirement (Section VII), that is available within ten minutes may be utilized tosatisfy the Ten-Minute Reserve Requirements.23

In OP 8, the TMNSR Requirement is defined as a component of the Ten-Minute Reserve,

as being that part of Ten-Minute Reserve that may be reliably replaced by nonsynchronized

24 Id.

25 OP 8, Part III, Section I.B. (emphasis added).

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reserve.24

Thirty-Minute Reserve is defined in OP 8, Part III, I.B:

In addition to Ten-Minute Reserve, ISO New England shall maintain a quantity ofThirty-Minute Reserve at least equal to fifty percent (50%) of the SecondContingency Loss. Any excess Ten-Minute Reserve can be counted as Thirty-Minute Reserve.

During periods when system conditions threaten to reduce Ten-Minute Reservebelow prescribed levels, Thirty-Minute Reserve may be redispatched to maintainTen-Minute Reserve.25

Thus, in normal conditions, OP 8 dictates that the TMSR Requirement (a term not

defined in the Market Rules) means the Ten-Minute Reserve Requirement (defined in OP 8)

minus the nonsynchronized reserve permitted to replace Ten-Minute Reserve. Pursuant to

Market Rule 1(132), the TMNSR Requirement means the nonsynchronized reserve permitted to

replace Ten-Minute Reserve under OP 8, and under Market Rule 1(135), the TMOR Requirement

is the amount of Thirty-Minute Reserve required under OP 8.

4. TMSR, TMNSR and TMOR Requirements Change In Response toAbnormal (OP 4) Conditions

Having determined the reserve requirement levels specified for normal conditions, it is

clear from the emphasized language in the definitions of Ten-Minute Reserve and Thirty-Minute

Reserve quoted above that the levels of these requirements are not the same in OP 4 (capacity-

short) conditions. In the case of Ten-Minute Reserve, the definition is limited to “normal

conditions” and in the case of Thirty-Minute Reserve, the level of Thirty-Minute Reserve is

allowed to decrease when Ten-Minute Reserve levels are threatened. Therefore, by definition, the

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TMSR, TMNSR and TMOR Requirements are different during periods of capacity shortages than

the requirements during normal conditions. Because the OpCap Settlement Obligation set forth in

Market Rule 10.4.1 is defined by reference to TMSR, TMNSR and TMOR Requirements,

changes in the latter requirements during periods of capacity shortages will also necessarily result

in changes to the OpCap Settlement Obligation in such periods.

5. Changes to Reserve Requirements Permitted by OP 8 During OP 4Conditions

As stated in Part IV of OP 8, when capacity is insufficient to maintain normal

reserve levels, the ISO is authorized to implement OP 4 actions in an attempt to optimize the

quantity and quality of available reserves. During these periods, it is authorized to lower Thirty-

Minute Reserve, synchronize TMNSR (thereby converting it to TMSR) and reduce TMSR. OP 4

Action 11 allows the ISO to reduce Thirty-Minute Reserve to zero. OP 4 Action 12 allows the

ISO to reduce Ten-Minute Reserve. All of these actions under OP 8, and OP 4 actions

authorized by OP 8, change the TMSR, TMNSR and TMOR Requirements. During non-

normal (i.e., OP 4) conditions, then, the OPs recognize that a theoretical construct of

reserves is not appropriate since reserve levels are inadequate. That is why the OPs do not

define specific Ten-Minute Reserve or Thirty-Minute Reserve requirements during OP 4

conditions and the OP 8 definitions are not applicable when determining the TMSR, TMNSR and

TMOR Requirements in OP 4 conditions. By their terms these definitions apply only “during

normal conditions.”

6. The Operating Reserve Requirements in OP 4 Conditions Are theActual Levels of Reserves Designated, and these Actual Levels, inTurn, Determine the OpCap Settlement Obligation

While neither OP 4 nor OP 8 explicitly specify the applicable Operating Reserve

26 See, e.g., Market Rules 8.4.3(a) and 8.2(f). The ISO only designates reserves that areactually available.

27 That amendment states:

For trading Intervals during which there is insufficient Operating Reserve in one ormore category(ies) available to meet the NEPOOL Control area requirement [i.e.,

(continued...)

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Requirement levels when reserves are reduced during OP 4 conditions, both NERC guidelines and

ISO operating procedure require that all available reserves be used when less than the normal

requirement is available. Market Rules 6, 8 and 9 -- the rules that govern the TMSR, TMNSR

and TMOR Markets -- reflect this practice. Those rules contain procedures for determining

compensation to market participants for the quantities of reserves provided during all conditions,

including OP 4 conditions. Under these rules, reserve market purchasers are charged only for the

reserves actually designated, and reserve market sellers are compensated only for the reserve

actually designated.26 As the OpCap Settlement Obligation is the sum of TMSR, TMNSR and

TMOR Requirements, and these requirements are not defined at a pre-set, empirically determined

level during OP 4 conditions (but are clearly defined as not equal to their levels during normal

conditions), the ISO reasonably interpreted the rules to mean that the operating reserve

components of the OpCap Settlement Obligation (as specified in Market Rule 10.4.1(b)) must be

equal to the amount of TMSR, TMNSR and TMOR actually designated (i.e., provided) during

OP 4 conditions as defined in Market Rules 6, 8 and 9.

7. Conclusion

As demonstrated by the content of the July 13 Memorandum, the ISO made -- and

announced that it was using -- the Interpretation described above well in advance of August 5.

The Interpretive Amendment filed on August 527 simply shortened the number of steps required to

27 (...continued)OP 4 conditions], this component of the Settlement Obligation for OperableCapability [the 10.4.1(b) requirement] will be determined using the quantity ofOperating reserve designated pursuant to Market Rules 6, 8 and 9 during theTrading Interval.

28 Complaint, at 17.

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determine (utilizing Market Rule 10 and the related filed documents) the OpCap Settlement

Obligation, thereby making it clearer and easier for market participants to understand. The

amendment did not change Market Rule 10, as argued by Complainants;28 it just saves

Participants the trouble of referring to eight different documents to arrive at a figure for the

OpCap Settlement Obligation, thereby increasing market transparency. Accordingly, the

Complainants’ argument must be rejected.

B. THE INTERPRETATION REASONABLY RESOLVED THE ISSUE OFTHE ALLOCATION OF EMERGENCY OPCAP PURCHASED FROMOTHER CONTROL AREAS DURING OP 4 CONDITIONS

Market Rule 10.4.2, as it existed prior to August 5, 1999, specified the components of a

Participant’s Hourly Settlement Resources that collectively could be compared with the

Participant’s Hourly Settlement Obligation under Market Rule 10.4.1 to determine whether the

Participant had an excess or a deficiency to be settled through the OpCap Market:

10.4.2 Participant Hourly Settlement Resources for Operable Capability

The Operable Capability Credit (in MW) of a Generator or External Transaction ina Trading Interval is as recorded by the ISO and determined according to theprocedures defined in Appendix 10-B.

The Operable Capability Credit (in MW) of a Dispatchable Load in a TradingInterval is as recorded by the ISO and determined according to the proceduresdefined in Appendix 10-B.

A Participant’s total Settlement Resources for Operable Capability in a TradingInterval is equal to the sum of the following:

DC_DOCS_A 1049583 v 10 18

a) The Operable Capability Credit of Generators in which theParticipant has an Operable Capability Entitlement during the houras an owner.

plus

b) The Operable Capability Credit of Generators in which theParticipant has an Operable Capability Entitlement during the houras a buyer under a Unit Contract.

minus

c) The Operable Capability Credit of Generators in which theParticipant has sold an Entitlement during the hour as the sellerunder a Unit Contract.

plus

d) Rights to receive Settlement Resources for OperableCapability as the buyer under System Contracts or Firm Contracts.

minus

e) Obligations to supply Operable Capability as the seller underSystem Contracts or Firm Contracts.

plus

f) The Operable Capability Credit of Dispatchable Loads inwhich the Participant has an Operable Capability Entitlement duringthe hour as either an owner or as a buyer under a BilateralContract.

Complainants argue that under this version of Market Rule 10.4.2, emergency capacity

purchased by Participants (collectively) from neighboring control areas during OP 4 conditions

should not be credited to a Participant’s OpCap Settlement Resources. It supports its argument

as follows:

each Participant’s hourly Settlement Resources were thus defined [in Market Rule10.4.2] by a formula which made specific additions and reductions to the resourcesattributable to the Participant as specified in clauses (a) through (f). Theunderscored provisions of clause (g) [i.e., the amendment filed by the ISO on

29 Complaint, at 20.

DC_DOCS_A 1049583 v 10 19

August 5] put into effect prospectively by the Amended MRPs, however, plainlyaltered the original rule by including an additional ‘credit’ equal to the pro-ratashare of emergency purchases from outside of the Pool.29

Once again, the Complainants have failed to examine the provisions of the RNA, and the

interlocking definitions contained in the Market Rule and other filed documents. As the following

discussion indicates, the ISO’s reasonable and straightforward interpretation -- made and

publicized to Participants well in advance of the August 5 Filing -- of the pre-August 5 version of

Market Rule 10.4.2, the RNA and related filed rules and agreements led to the result that the

emergency capacity must be credited to purchasing Participants as an OpCap settlement resource.

The amendment to Market Rule 10.4.2 filed by the ISO on August 5 -- here again – simply

shortened the number of steps required to determine the OpCap Hourly Settlement Resources

under Market Rule 10.4.2, thereby making it clearer and easier for market participants to

understand. The amendment did not change Market Rule 10, as argued by Complainants; it just

saves Participants the trouble of referring to six different documents to arrive at a figure for the

OpCap Settlement Obligation, thereby increasing market transparency.

In particular, Complainants assert that the clause (g) added to Market Rule 10.4.2 is an

“additional credit” to the Settlement Resources credited to customers. This is incorrect; instead,

as explained herein, Market Rule 10.4.2(g) simply explicates a credit which is already accounted

for in an existing clause of Market Rule 10.4.2.

1. Emergency Purchases of Capability and Energy Under RNA § 14.6(a)

Section 14.6(a) of the RNA provides that the NEPOOL Participants Committee is

authorized to enter into contracts on behalf of and in the names of all Participants with power

30 Emphasis added.

31 The ISO arranges for these purchases (and administers these contracts) pursuant toSection 6.10 of the ISO Agreement.

32 The New Brunswick Interconnection Contract refers to capability as “capacity.”

33 The ISO has credited OpCap only for emergency purchases of bundled energy andcapacity. See Ide Affidavit, ¶ 7. Occasionally, the ISO purchases only Energy under theInterconnection Contracts, because capacity is not available from neighboring regions.

34 RNA Section 14.6(a) states, in full:

The Participants Committee is authorized to enter into contracts onbehalf of and in the names of all Participants (i) with power poolsor other entities in one or more other control areas to purchase or

(continued...)

DC_DOCS_A 1049583 v 10 20

pools in other control areas to purchase “emergency Energy (and related services).”30 Capacity

(i.e., OpCap) is one such “related service.” The ISO, on behalf of NEPOOL Participants,

arranges for their collective purchases of emergency energy and related services during OP 4

conditions from neighboring control areas pursuant to two longstanding NEPOOL

interconnection contracts, one with the New York Power Pool (now the New York Independent

System Operator) and the other with New Brunswick (the “Interconnection Contracts”).31

The Interconnection Contracts specifically contemplate the purchase by NEPOOL

Participants of energy backed by capability32, and call for the payment of two charges by

NEPOOL Participants in those circumstances: one for capability and one for the associated

energy. This bundled energy and capability was one of the products purchased on behalf of the

NEPOOL Participants during the shortages occurring in June and July, 1999, and at issue in the

Complaint.33 Under Section 14.6(a), the Energy is “deemed furnished to, and paid for by,

Participants entitled to or requiring such Energy in the hour...” and credited to purchasers pro

rata.34 Thus, it is clear that any capability (i.e., OpCap) bundled with energy

34 (...continued)furnish emergency Energy (and related services) that is available forthe System Operator to schedule in order to ensure reliability in theNEPOOL Control Area or neighboring control areas, and (ii) withNon-Participants pursuant to which ancillary services will beprovided by the Participants pursuant to the Tariff. The terms ofany such contractual arrangement shall not require the furnishing ofemergency service to any other control area until the service needsof all Participants have been provided for with the least expensiveresources practicable. Energy purchased in any hour from Non-Participants under a contract entered into pursuant to this Section14.6(a) shall be deemed to be furnished to, and paid for by,Participants entitled to or requiring such Energy in the hourpursuant to this Section 14 at the higher of the Energy ClearingPrice for the hour or the price paid to the Non-Participant for theEnergy.

See also Appendix 5E to Market Rule 5 which states: “In circumstances where the ISOpurchases emergency assistance, the excess cost, if any, of emergency assistance over theEnergy Clearing Price will be treated as an Uplift Charge and allocated on a pro-rata basisto net purchasers of Energy in the relevant Trading Intervals.”

DC_DOCS_A 1049583 v 10 21

-- i.e., the “related services” described at the beginning of Section 14.6(a) -- should be

credited pro rata to the Participants paying for it, as well.

2. Confirmation of this Interpretation by Market Rule 10.4.2(d): Creditfor Capability Purchases Under System Contracts

This interpretation is confirmed by the provisions of Market Rule 10.4.2(d). Under that

rule, as it existed prior to August 5 and afterward, Participants receive credit for Operable

Capability from “[r]ights to receive Settlement Resources for Operable Capability as the buyer

under System Contracts or Firm Contracts.” The term “System Contract” is defined in Market

Rule 1 as follows:

126. System Contract – is any wholesale contract for the purchase for resale of InstalledCapability, Operable Capability, Energy, Operating Reserves, and/or AGC, otherthan a Unit Contract or Firm Contract, pursuant to which the purchaser is entitledto a specifically determined or determinable amount of such Installed Capability,

35 “(RNA)” at the end of this definition indicates that the definition is taken directly from theRestated NEPOOL Agreement.

DC_DOCS_A 1049583 v 10 22

Operable Capability, Energy, Operating Reserve and/or AGC. (RNA) 35

The Interconnection Contracts, though not entered in the Market System by an individual

Participant, fit the Market Rule 1 definition of a System Contract quoted above. The

Interconnection Contracts are contracts for wholesale purchases of energy. Through the

Interconnection Contracts and RNA Section 14.6(a), the NEPOOL Participants requiring

Operable Capability in the hour were the buyers of any emergency Operable Capability under the

System Contracts (i.e, the Interconnection Contracts). The purchases at issue here called for the

delivery of capacity (i.e., OpCap) which, pursuant to the RNA, is allocated on a pro-rata basis

among those Participants buying the service. Therefore, they have the “rights to receive

Settlement Resources” for that OpCap under Market Rule 10.4.2(d).

3. Confirmation of this Interpretation by Market Rule 12

The conclusion that purchasers of bundled capability and energy under the

Interconnection Contracts should obtain OpCap credit is confirmed by reference to Market Rule

12 which defines standard terms for External System Contracts. Market Rule 12.2.2 defines a

product, Energy 2, which is:

Energy that is not sold out of the Operating Reserve of the seller or the seller’sControl Area. An Energy 2 transaction provides an Operable Capability resourceto a purchasing Participant and an increased obligation to a selling Participant.

Market Rule 12.2.2 recognizes two types of Energy available under External System Contracts:

Energy 1 and Energy 2. Energy 1 has no associated Operating Reserve and does not affect a

buyer’s Operable Capability resources. Energy 2 has associated Operating Reserve and “provides

an Operable Capability resource” to the purchaser. Appendix 12-B-2 to Market Rule 12 goes on

DC_DOCS_A 1049583 v 10 23

to state that a “System Contract for Energy 2 provides the purchaser with...(2) an OpCap

Entitlement.”

Emergency bundled capability and energy purchased pursuant to the Interconnection

Contracts is, by definition, not sold out of control area reserves and thus is, in substance, Energy

2. Accordingly, Market Rule 12 confirms by analogy that these purchases also should provide an

OpCap Entitlement for the purchaser.

4. Conclusion

To summarize, under the ISO’s reasonable interpretation, each Participant receives an

Operable Capability Credit equal to its pro-rata share of the capability (OpCap) bundled with the

emergency assistance purchased. Because this credit is received pursuant to a System Contract

that gives the purchaser (i.e., Participant) a right to OpCap, it is, by definition, part of the credit

determined under Market Rule 10.4.2(d). Thus, the OpCap Credit for bundled emergency

purchases is already added into the total credits for each Participant. Market Rule 10.4.2 (g) --

added in the August 5 Filing -- does not change the substance of the Market Rule. It simply

clarifies the Market Rule and allows readers to understand the implications of clause (d) with

regard to emergency assistance without referring to the definitions and the RNA.

Once again, the Complainants have failed to read the Market Rules and trace the

relationships between the Market Rules, the defined terms and the other documents which govern

the relationship between the ISO, NEPOOL, the individual Participants and the markets. This is

exactly why the ISO amended Market Rule 10 to make these provisions and implications

abundantly clear without reference to other documents.

36 See, e.g., AEP Generating Co., Opinion No. 266-A, 39 FERC ¶ 61,158, at p. 61,626(1987)(Commission rejected a party’s proffered interpretation of a filed agreement thatwould have created an incongruous result that was also inconsistent with principles ofmutuality, citing Penn Central Co. v. General Mills, Inc., 439 F.2d 1338, 1340-41).

DC_DOCS_A 1049583 v 10 24

C. COMPLAINANTS’ INTERPRETATION OF MARKET RULE 10 IS NOTCONSISTENT WITH OTHER PROVISIONS OF THE MARKET RULESAND OPERATING PROCEDURES, IT RESULTS IN MARKET FAILUREAND COULD RESULT IN DOUBLE PAYMENTS

As clearly demonstrated above, the ISO’s settlement of the OpCap Market using the

Interpretations is in accordance with the filed rate. Complainants’ interpretation of Market Rule

10 -- as recognizing no change in reserve requirements in OP 4 conditions and as excluding

purchased emergency capability from crediting as OpCap -- finds no support in the Market Rules,

Operating Procedures and RNA, which collectively constitute the filed rate. The Complainants’

interpretations result in untenable conclusions and collectively, result in market failure. The

Commission should reject the Complainants’ interpretations.36

First, Market Rule 10.4.1 defines a Participant’s Hourly Settlement Obligation for OpCap

as its Electrical Load plus its share of NEPOOL Operating Reserve Requirements. Therefore, the

level of reserve requirements must be determined. Complainants never state what the Operating

Reserve Requirements must be, but, in order to make any sense of their argument, we read their

Complaint to state that the TMSR, TMNSR and TMOR Requirements specified in Market Rule

10.4.1 before it was amended are always equal to the TMSR, TMNSR and TMOR Requirements

under normal operating conditions. As demonstrated in Section III.A., above, this interpretation

ignores OP 8, OP 4 and the reserve designation provisions of Market Rules 6, 8 and 9, which

collectively direct that the reserve requirement be adjusted to the actual (rather than the

theoretical) level of reserves during OP 4 conditions. To accommodate Complainants’ argument

37 Emphasis added. This sentence was retained in the version of Rule 10.4.5 filed on August5; new Market Rule 10.4.5(a) reflected the ISO’s prior interpretations set forth in SectionsIII.A. and B. above; new Market Rule 10.4.5(b) is the Price Cap Amendment not applied

(continued...)

DC_DOCS_A 1049583 v 10 25

would mean that Participants would pay for reserves that weren’t available to be purchased.

Second, under Market Rule 10, each Participant’s Hourly Settlement Obligation is

compared to its Hourly Settlement Resources (defined in Market Rule 10.4.2) to calculate an

OpCap excess or deficiency position (under Market Rule 10.4.3). Complainants would exclude

capacity bundled in emergency purchases from the Participant’s Hourly Settlement Resources.

Their position means that OpCap resources associated with emergency purchases -- which are

resources Participants have paid for -- should nevertheless be excluded in calculating the

Participants’ deficiencies. As demonstrated in Section II.B. above, this position is inconsistent

with the RNA and the other Market Rules and could result in double payments by Participants for

OpCap. If Participants who pay for emergency OpCap purchases are not credited with that

OpCap, they may still be considered deficient in their OpCap Settlement Obligations and may be

required to purchase OpCap (if available) in the market. Thus, under the Complainant’s

interpretation, even though they have already met their obligations through the emergency

purchases, they could still be forced to supply those same requirements a second time through the

purchase of OpCap through the NEPOOL markets.

Third, the Complainants’ interpretation leads to market failure, because under their

interpretation it is impossible to calculate a price for OpCap in OP 4 conditions. Prior to its

amendment on August 5, 1999, Market Rule 10.4.5 stated:

The highest Operable Capability Bid Price for a MW of excess Operable Capabilityneeded to supply the total Operable Capability deficiencies of all buyers is theOperable Capability Clearing Price for that Trading Interval.37

37 (...continued)to the pre-August 5 period.

DC_DOCS_A 1049583 v 10 26

Complainants’ insistence on utilizing a theoretical and unattainable reserve requirement level

during OP 4 conditions sets an unattainable OpCap requirement, and together with their insistence

on denying Participants credit for purchased emergency capability, dictates that the OpCap supply

curve cannot intersect with the OpCap demand curve under OP 4 conditions. Stated another

way, the inconvenient consequence of Complainants’ position is that a clearing price for OpCap

can not be calculated (or paid to them) because there is no Operable Capability bid that, combined

with the other bids, can “supply” the “deficiencies of all buyers” and set the Operable Capability

Clearing Price pursuant to Market Rule 10.4.5. This results in market failure.

The implication of Complainants’ argument is that they wish to change Section 10.4.5

retroactively, by calculating the OpCap Clearing Price as the Bid Price of the highest priced

OpCap available, whether or not the associated OpCap megawatts (combined with the megawatts

of the other available OpCap bid into the Market) can satisfy all the deficiencies or not. This --

unlike the ISO’s interpretation -- would represent a change in the Market Rules that would indeed

violate the Filed Rate Doctrine. Second, if this change were accepted by the Commission --

implicitly or explicitly -- each Participant bidding in OP 4 conditions would have market power

and there would be no competitive limit to the escalation of bids. As discussed more fully in

Section IV below, the Commission has not and could not grant market-based rates where the

structure of the market assures that market power can be exercised. The Commission should not

accept an interpretation of the Market Rules that would cause a violation of the principles on

which market-based rates were granted.

IV. THE ISO’S INTERPRETIVE ACTIONS WERE WITHIN THE ISO’S

38 New England Power Pool, 79 FERC ¶ 61,374, at p. 62,584 (1997)(the “June 1997Order”).

DC_DOCS_A 1049583 v 10 27

AUTHORITY AND DID NOT REQUIRE A FILING, AS CONFIRMED INCOMMISSION PRECEDENT INVOLVING INDEPENDENT SYSTEMOPERATORS; INDEED, THE ISO’S AUTHORITY TO INTERPRET THEMARKET RULES IS AN ESSENTIAL ELEMENT OF THE ISO’SINDEPENDENCE, IS NECESSARY FOR THE ISO TO MEET ITSRESPONSIBILITY TO ADMINISTER AND SETTLE THE MARKETS ANDFULFILLS A KEY ROLE UNDER THE MARKET-BASED RATE PRECEDENT

The Complainants challenge the ISO’s fundamental authority to make the Interpretations

and to apply the Interpretations (without a filing with the Commission) to fulfill its duties to settle

the OpCap Market. This challenge flies in the face of the plain language of the Commission-

approved ISO Agreement, the Commission order authorizing the ISO and other relevant

Commission precedent. Moreover, it ignores the key role that the ISO’s reasonable interpretive

authority plays in ensuring market function.

A. THE ISO’S INTERPRETIVE ACTIONS WERE WITHIN THE ISO’SAUTHORITY AND DID NOT REQUIRE A FILING

Section 6.17(i) of the ISO Agreement states:

The ISO shall have sole authority to interpret and implement the System Rules andProcedures developed pursuant to this Section 6.17 as it performs its operatingresponsibilities under this Agreement.

In accepting the terms of the ISO Agreement, the Commission specifically recognized that

the ISO has “sole authority to interpret the System Rules and Procedures as it carries out its

operating functions.”38 Indeed, the Commission found that the ISO’s authority to interpret the

market rules was a significant component of the ISO’s independence.

The Commission has recognized the appropriateness of interpretive authority for other

39 See, e.g., Northern Maine Independent System Administrator, Inc., 89 FERC ¶ 61,179(1999).

40 Complainants attempt (at p. 26) to erase Section 6.17(i) from the ISO Agreement --despite its affirmation by the Commission -- by claiming that the recognition of the ISO’sinterpretive authority would deprive the Commission of its Section 205 jurisdiction. TheCommission should resist this claim as demagoguery by Complainants. While the ISO ‘sauthority to interpret the Market Rules cannot diminish the authority of the Commissionunder the FPA, the Complainants’ argument that the ISO must file each clarifyinginterpretation of the existing Market Rules is directly contrary to established Commissionprecedent. In fact, under this precedent, the ISO’s authority under Section 6.17(i) isconsistent with the Commission’s FPA authority.

The Commission should also reject the Complainants’ argument (at p. 26) that Section6.17(i) does not support the authority of the ISO to interpret the Market Rules inappropriate circumstances in the absence of a prior filing with the Commission, and onlyaddresses the allocation of interpretive authority as between NEPOOL and the ISO. Thisargument makes no sense. If the ISO has “sole” authority, as Section 6.17(i) provides,then the ISO must by definition have some authority or there would be no need for theprovision. Moreover, if Complainants are arguing that every ISO interpretation must befiled with FERC, there is – in effect – no room for interpretations, only rate filings,rendering Section 6.17(i) as surplusage. The Commission’s specific recognition ofinterpretive authority in the June 1997 Order precludes treatment of Section 6.17(i) assurplusage.

DC_DOCS_A 1049583 v 10 28

independent regional transmission entities, as well.39 Under the ISO Agreement and established

Commission precedent, then, the ISO possesses interpretative authority with respect to System

Rules and Procedures.40

The ISO properly applied its authority under Section 6.17(i) to make the Interpretations.

The Interpretations involve the terms of the Market Rules which, in Section 2.33 of the ISO

Agreement, are included in the definition of “System Rules and Procedures.” Moreover, the ISO

clearly made the Interpretations in the context of performing “its operating responsibilities” under

the ISO Agreement, because these responsibilities obviously include administering OP 4, OP 8

and the market settlements process.

The Interpretations were clearly within the scope of the ISO’s authority since the ISO had

41 See Ide Affidavit, ¶ 6.

DC_DOCS_A 1049583 v 10 29

to make determinations (as detailed in Section II of this Answer) to fulfill its responsibility to

settle the OpCap Market. The ISO had to decide whether to include the OpCap associated with

emergency purchases or exclude it, and whether OpCap requirements should reflect unavailable

reserves in order to calculate the bills of Participants who bought or sold OpCap during periods of

emergency purchases and OP 4 actions that reduced reserves. Stated another way, making and

applying the Interpretations to the pre-August period fulfilled the ISO’s obligation to operate the

market in accordance with the terms of the RNA and the Market Rules.

The ISO’s authority to take unilateral action to ensure that the Market settlements are

consistent with the Market Rules was emphasized by the Commission’s recent order regarding a

revised version of Market Rule 15. In finding that Market Rule 15 was unnecessary in order to

correct implementation errors relating to Market prices, the Commission found that “the filed rate

doctrine already provides the ISO with the authority to correct errors in charging the filed rate.”

To have failed to make the Interpretations would have resulted in prices that were not consistent

with the Market Rules, thus violating the Filed Rate Doctrine.

Moreover, the Interpretations do not constitute an attempt by the ISO to usurp the

Commission’s rate-setting authority and policy, as Complainants incorrectly suggest. In an

attempt to whip up indignation, Complainants resort to muddying the clear distinction between

the Price Cap Amendments and the Interpretive Amendments. As stated above, the ISO is not

using, and has never proposed to use, the Price Cap Amendments to settle the pre-August 5

OpCap Market.41 The Complaint (pp. 22-23) points to statements attributed to ISO officials in

news accounts from August 1999 period as though they relate to the Interpretations, when a fair

42 Indeed, the Boston Herald article relates to actions taken in the reserve markets, and notin the OpCap market.

43 California Independent System Operator Corporation, 88 FERC ¶ 61,146, at p. 61,487(1999).

DC_DOCS_A 1049583 v 10 30

reading (assuming the officials were quoted accurately) indicates that they relate to the Price

Cap, if they relate to OpCap at all.42 By doing so, the Complainants inaccurately accuse the ISO

of unilaterally changing prices it doesn’t like. Instead, as shown in this Answer, the

Interpretations were necessary in order to settle the OpCap Market in accordance with the RNA

and the Market Rules.

The September Order was consistent with prior Commission precedent with respect to

independent system operators. In a recent proceeding involving the California Independent

System Operator Corporation (“CalISO”), a protestor complained that CalISO was required to

make a tariff filing change rather than use its interpretive authority with respect to the

methodology for calculating payments and charges to bidders in CalISO’s real-time markets.

Specifically, the protestor (Reliant) argued that:

the ISO failed to incorporate into the tariff changes that it recently enactedunilaterally to its internal operating procedures that materially change the methodused to calculate payments and charges to bidders whose Imbalance Energy bidsand Adjustment bids are selected out of economic merit order. According toReliant, the ISO revised how it calculates payments to bidders whose ImbalanceEnergy bids are selected out of sequence, effective June 1, 1999. Since the ISOmade these changes to its internal operating procedures rather than to its Tariff,Reliant argues that the Commission should require the ISO to file to incorporatethese procedures into its Tariff for Commission review.43

CalISO responded that:

none of the changes cited by Reliant require additional tariff changes. The ISOstates that the changes to its operating procedures are consistent with tariffchanges already approved...and reflect permissible interpretations of existing tariff

44 Id. at p. 61,488 (emphasis added).

45 Id. (emphasis added).

46 This result is also consistent with the Commission’s order in Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ¶ 61,257 (1997), in which the Commission foundthat there are “many areas” in which procedures that interpret or implement tariff languagerules can be reflected in an independent system operator’s operating procedures rather

(continued...)

DC_DOCS_A 1049583 v 10 31

language.44

The Commission agreed with CalISO, and did not require a tariff change or the filing of the

pertinent section of the operating procedures, holding that:

In response to Reliant's allegations regarding the ISO's unilateral changesto its operating procedures, we agree with the ISO that its June 1, 1999, changesin the way that it compensates Imbalance Energy bids and Adjustment bids takenout of economic merit order are consistent with its existing Tariff. The ISO Tariffauthorizes, but does not require, the ISO to exclude certain bids from setting theImbalance Energy price. For resources submitting different price bids for differentblocks of energy for use in Intra-Zonal Congestion Management, Section 7.3.2 ofthe ISO Tariff can be interpreted to permit the ISO to pay resources selected forIntra-Zonal Congestion Management either (1) the separate bid price for eachseparate energy block, or (2) the resource's highest accepted bid for all of theresource's accepted energy.45

The circumstances described in the Complaint bear striking parallels to those presented in

the CalISO proceeding. In that case, existing market rules on file with the Commission required

interpretation in order to settle markets. The interpretation was made by an independent system

operator without a Section 205 filing, affected the compensation of market participants, and was

consistent with the existing market rules. A protestor argued (to no avail) that the interpretation

had to be reflected in a document filed with the Commission. This is precisely the situation

presented in the Complaint. Given these parallels, the Commission should apply its precedent

here to confirm that the ISO’s interpretive actions to clarify and enforce the OpCap Market Rules

were within the ISO’s authority and did not require a prior Section 205 filing.46

46 (...continued)than filed with the Commission. See 81 FERC ¶ 61,257 at n.50.

47 See, e.g., New England Power Pool, 85 FERC ¶ 61,379 (1998); New England PowerPool, 87 FERC ¶ 61,045 (1999); New England Power Pool and ISO New England Inc.,87 FERC ¶ 61,055 (1999).

DC_DOCS_A 1049583 v 10 32

B. THE ISO’S AUTHORITY TO INTERPRET THE MARKET RULES IS ANESSENTIAL ELEMENT OF THE ISO’S INDEPENDENCE, ISNECESSARY FOR THE ISO TO MEET ITS RESPONSIBILITY TOADMINISTER AND SETTLE THE MARKETS AND FULFILLS A KEYROLE UNDER THE MARKET-BASED RATE PRECEDENT

The market-based rates approved for NEPOOL are prices derived in auctions held under

complex market rules. The rates cannot be calculated from a tariff or contract, but rather are

derived from software analysis of hundreds of bids submitted by Participants. The software is

based on Market Rules that in turn are based on the RNA. The Markets are administered by the

ISO pursuant to the ISO Agreement under which the ISO acts as an independent agent of

NEPOOL.

As is demonstrated by the interpretive analysis in Section III above, all of these sources of

authority together define the operation of the markets. Before the Commission permitted the

Markets to begin operating, it reviewed and approved all of the foregoing rules and agreements.47

This is consistent with and, indeed, necessary under the standards that the courts and the

Commission have developed for market-based rates. Moreover, an independent entity with the

authority to monitor and interpret in order to ensure proper market function is similarly essential

to the satisfaction of the standards set forth in this precedent, discussed below.

The Commission has worked consistently since the 1980s to introduce market-based rates

in workably-competitive utility sectors subject to its rate-making jurisdiction. In reviewing the

Commission’s early efforts, the United States Court of Appeals for the District of Columbia stated

48 734 F. 2d 1486, 1509 (1984)(“Farmers Union”)(emphasis added).

49 See, e.g., Louisiana Energy and Power Authority v. FERC, 141 F. 3d 364, 365 (1998). See also Public Service Company of Indiana, 51 FERC ¶ 61,367 (1990).

50 Promoting Wholesale Competition Through Open-Access Non-discriminatoryTransmission Services by Public Utilities and Recovery of Stranded Costs by PublicUtilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (May 10, 1996),FERC Stats. & Regs. ¶ 31,036 (1996)(“Order 888"), Order No. 888-A, 62 Fed. Reg. 12,274 (March 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh'g, Order No.888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046(1998).

51 Order 888, FERC Stats. & Regs. ¶ 31,036 at 31,684.

DC_DOCS_A 1049583 v 10 33

in Farmers Union Central Exchange v. FERC that the Commission had an ongoing obligation to

determine if rates were just and reasonable because prices might:

exceed the “zone of reasonableness” by definition unless competition in the oilpipeline market drives the actual price back down into the zone. But nothing inthe regulatory scheme itself acts as a monitor to see if this occurs or to check ratesif it does not.48

Following Farmers Union, the Commission has utilized careful analysis of the possibility that

market-based rates could be influenced by the exercise of market power and has, in appropriate

circumstances, sought mechanisms to assure that there are no such influences.49 An independent

system operator administering a power exchange is an effective satisfaction of the Farmers Union

requirement that the regulatory scheme include a “monitoring” element .

In its efforts to lighten regulatory regimes, the Commission moved beyond case-by-case

approval of market-based rates and instituted industry-wide restructuring, first in the gas industry

and then in the electric industry. In Order No. 888, the Commission required all jurisdictional

public utilities to file open access transmission tariffs.50 The Commission’s purpose was to end

discrimination and secure for consumers the benefits of competitive generation.51 In its order, the

Commission identified independent system operators as a appropriate means of assuring

52 Order 888, FERC Stats. & Regs. ¶ 31,036 at 31,730.

53 See New England Power Pool, 83 FERC ¶ 61,045 at 61,258 (1998); and New EnglandPower Pool, 86 FERC ¶ 61,962 (1999).

54 New England Power Pool, 79 FERC ¶ 61,374 at 62,584 (1997).

DC_DOCS_A 1049583 v 10 34

independent non-discriminatory operation of the transmission system in accordance with trading

rules established by a control area governing body.52

The Commission to date has permitted the establishment of four power exchanges as an

integral part of a control area restructuring. In each case, the power exchange is operated by an

independent entity that has no commercial interest in the markets: the independent system

operator in PJM, NEPOOL and New York and a separate power exchange in California. In each

case, the Commission -- before granting market-based rates to participants in a power exchange --

has scrutinized not only the potential for exercise of market power and the market rules, but also

the governance, market power monitoring, and operational arrangements.

The ISO believes that -- under the core standards enunciated by the courts and the

Commission in considering market-based rates -- a power exchange can only be operated by a

truly independent entity with sufficient authority to effectively administer complex competitive

markets. In the case of NEPOOL, the Commission has required revisions of both the ISO

Agreement and NEPOOL governance in order to insure the independence of the ISO.53 The

Commission has reviewed the ISO Agreement and has approved the ISO’s power to interpret

rules and to make emergency rules.54

The ISO believes that an independent operator with the ability to interpret the market

rules is necessary to the orderly functioning of a power exchange. This is consistent with the

findings of the Commission in its recent final rulemaking order regarding Regional Transmission

55 89 FERC ¶ 61,285; FERC Stats & Regs., ¶31,089 (1999). ("Order 2000").

56 Order 2000, FERC Stats & Regs., ¶31,089 at 31,027.

DC_DOCS_A 1049583 v 10 35

Organizations:55

We believe that some degree of deference can be granted on certain issues toindependent RTOs that have appropriate procedural mechanisms in place to ensurefair representations of viewpoints.56

In the absence of such an independent administrator, complex markets such as NEPOOL’s would

quickly break down in squabbles over the meaning of the rules. The markets could not be settled,

and no price certainty could be achieved. For sound policy reasons, then, the Commission should

support the interpretive authority of the ISO where -- as here -- interpretation is necessary,

reasonable and produces a rate consistent with the totality of the filed rules.

V. THE COMPLAINANT’S RELIANCE ON THE FILED RATE DOCTRINE ISMISPLACED

The Complainant’s argument that the Filed Rate Doctrine forbids the ISO from utilizing

its interpretive authority without a filing is, quite simply, a red herring. The ISO is not attempting

to deprive Complainants of the price (i.e., the rate) to which it is entitled under the Market Rules.

Instead, the ISO is simply carrying out its job to calculate the rate by properly applying the

Market Rules to the settlement process. This is not a violation of the Filed Rate Doctrine and its

purposes, as is verified by comparing caselaw with the facts presented here.

The Filed Rate Doctrine was originally articulated by Justice Brandeis in Keogh v.

Chicago & Northwestern Railway Company. The opinion stated:

The legal rights of shipper as against carrier in respect to a rate aremeasured by the published tariff. Unless and until suspended or setaside, this rate is made, for all purposes, the legal rate, as betweencarrier and shipper. The rights as defined by the tariff cannot be

57 260 U.S. 156 at 163 (1922).

58 Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 577 (1981).

59 National Steel Corporation v. Long, 718 F. Supp. 622, 626 (1989).

DC_DOCS_A 1049583 v 10 36

varied or enlarged by either contract or tort of the carrier.57

As between a utility, a common carrier or another entity with regulated rates and the entity’s

customer, the Filed Rate Doctrine protects the regulated entity from a collateral attack on its filed

rates based on the misfeasance of the regulated entity. It has principally been used as a defense to

antitrust claims as it was in Keogh.

The Filed Rate Doctrine has also been said to forbid:

a regulated entity to charge rates for its services other than thoseproperly filed with the appropriate federal regulatory authority.58

In this formulation, the doctrine serves to protect purchasers and:

to preserve the federal agency’s primary jurisdiction overreasonableness of rates, thereby assisting in enforcement of thesupremacy of federal law.59

The factual pattern at issue before the Commission here bears no relationship to the

posture of cases decided under the Filed Rate Doctrine. In the Markets, NEPOOL Participants

with energy to sell bid to supply energy, and Participants with real-time load are deemed to buy it.

Similarly, Participants with available Operating Reserves, Automatic Generation Control,

Operable Capability and Installed Capability bid to provide it, and the cost of system requirements

is allocated to Participants with real-time load who are deemed to buy it. The Participants who

are net sellers are the regulated entities, and the Participants with net load are the customers.

In the current proceeding, no customer challenges the rates charged by the Complainants.

Rather, the Complainants argue that they have not received the rates to which they are entitled.

60 That is, at what rate can the particular market clear and settle in a given hour?

61 See Oglethorpe Power Corp. v. Georgia Power Co., 69 FERC ¶ 61,208 (1994), reh’gdenied, 72 FERC ¶ 61,065 (1995)(filed rate doctrine not violated, and Georgia Power notrequired to make Section 205 filing, when it added certain capacity to the list of resourcesavailable for off-system sales as permitted by silence of provisions of filed tariff andagreement; Oglethorpe’s charges under tariff had increased as a result).

62 August 5 Filing, at 11.

DC_DOCS_A 1049583 v 10 37

The question involved here is not whether the Complainants are entitled to receive the filed rate,

which the ISO does not dispute, but rather the propriety of the interpretation (and the authority)

used in calculating the filed rate itself.60 While the Commission undoubtedly has jurisdiction to

answer the latter question, the Filed Rate Doctrine is of no assistance in doing so.61

VI. THE COMMISSION’S SEPTEMBER ORDER IS CONSISTENT WITH THEISO’S POSITION HEREIN AND DOES NOT SUGGEST THAT THE ISO’SACTIONS HAVE BEEN IMPROPER

The Commission’s September Order is consistent with the ISO’s authority to make the

Interpretations (without a rate filing) in order to settle the markets. Further, the September Order

indicates that the ISO’s interpretive actions were proper, especially because Southern Energy

protested the ISO’s interpretation, which protest was not sustained by the Commission.

In its August 5 Filing, the ISO specifically stated that:

The ISO has interpreted Market Rule 10 to mean that the requirement forOperating Capability is equal to the sum of the energy and units actuallydispatched for operating reserve, and the Amendment to Market Rule 10 herewithformally makes that interpretation part of the rule....The emergency Amendment toMarket Rule 10 filed herewith also makes formal a second ISO interpretation ofMarket Rule 10 which gives Operable Capability credit for emergency powerpurchase by the ISO.62

As noted, all of the Complainants, as well as other parties, protested, intervened and

63 See Motion of Dighton Power Associates for Leave to Intervene and Protest in DocketNo. ER99-4002-000 (August 24, 1999); Motion to Intervene and Protest of FPL Energy,Inc. in Docket No. ER99-4002-000 (August 25, 1999); and Motion to Intervene andProtest of Southern Energy New England, L.L.C., Southern Energy Kendall, L.L.C. andSouthern Energy Canal, L.L.C. in Docket No. ER99-4002-000 (August 25, 1999) (the“Southern Protest”).

64 Southern Protest at pages 22-23 (emphasis in the original, footnotes omitted).

65 See the August 30, 1999 filing of Northeast Utilities Service Company in Docket No.ER99-4002-000 at pages 10-11; and the August 25, 1999 filing of PG&E in Docket No.ER99-4002-000 at page 14.

DC_DOCS_A 1049583 v 10 38

became parties to that proceeding.63 At that time, several intervenors, including Southern Energy

New England, L.L.C. and Southern Energy Kendall, L.L.C. (collectively, “Southern Energy”)

protested the retroactive application of the interpretive provisions of Market Rule 10. For

example, Southern Energy stated:

The Commission should be aware that ISO-NE is now attempting to resettle pricesfor June 7-8 through a unilateral and unsupported interpretation of Market Rule10. In fact, ISO-NE is claiming that it already has the inherent authority to reduceOpCap demand and increase OpCap supply as it formally proposes to do in thisdocket via the Market Rule 10 Price Cap Amendments.

To the extent that ISO-NE seeks to make retroactive rate changes, eitherthrough its alleged existing authority under Market Rule 10, or via new price capauthority that it ultimately may gain in this docket, these attempts should berejected by the Commission. First, the Commission has stated that all changes tothe Market Rules must be made on a prospective basis – an idea that was originallyproposed by NEPOOL. Second, the Southern Parties assert that any attempt byISO-NE to change prior market clearing prices using its alleged authority underMarket Rule 10, or any new price cap authority ultimately gained in this docketconstitutes retroactive ratemaking. Retroactive ratemaking is illegal. In sum, theCommission should specifically state that it will not countenance any practice onthe part of ISO-NE which would permit ISO-NE to resettle prior market pricesusing new authority, new market rules, or new interpretation of existing rules.64

Other parties in that proceeding also suggested that the ISO should be directed not to

settle the pre-August 5 OpCap Market in accordance with the Interpretations.65 It was clear from

these pleadings -- for example, the first paragraph of the previously quoted portion of the

66 Complainants urge the Commission (at n.10 of the Complaint) to disregard thesestatements of the ISO because “the Commission rejected ISO-NE’s response.” This isincorrect. The Commission rejected the ISO’s answer only ”insofar as it responds to theprotests.” September Order, at p. 61,971. The ISO’s statements quoted above do not“respond” to the protests; instead they confirm the correctness of the protestor’sstatements about the ISO’s application of the Interpretations to the pre-August 5 period.

67 September Order, at p. 61,970.

DC_DOCS_A 1049583 v 10 39

Southern Protest -- that the parties were aware that the ISO was already using the Interpretations

in settling the OpCap market pursuant to its asserted existing interpretive authority. The ISO

reconfirmed the correctness of this perception in its September 9, 1999 filing in Docket No.

ER99-4002 -- through its description of the result of applying the Interpretations to the OpCap

Markets for June 7 and 8, 1999, and its statement that it “has not requested action with respect to

its interpretations prior to [August 5].”66

The present Complaint is substantively identical to the protests of the Complainants of the

August 5 amendments. Therefore, the Complainants’ arguments that the ISO is retroactively

applying the August 5 amendments to Market Rule 5 have already been raised before the

Commission. In the September Order, the Commission specifically accepted the interpretive

amendments to Market Rule 10, noting that, explicitly with respect to Market Rule 10.4.1, these

amendments were made to “clarify” the Market Rules.67 Aware both that the ISO was already

applying these interpretations to the pre-August 5 period and that this application was

objectionable to certain market participants, the Commission chose -- through its silence -- to

deny the requested relief. That is, the Commission refused to issue the requested admonishment

to the ISO that it could not use these interpretations for the pre-August 5 period. Accordingly,

the September Order must be viewed as consistent with the ISO’s interpretive actions. In no way

68 Indeed, given the specific framing of the issues in the protests, it is fair to read the silentdenial of the Complainants’ requested relief as a substantive disposition of the Complaint,in which case all of the Complainants, as parties to that proceeding, are bound by thatdisposition. The Complainants who did not file for rehearing of the September Orderwithin the appropriate time period have waived their rights to seek relief. See, e.g.,Pacific Gas Transmission Co., 46 FERC ¶ 61,072 (1989); Montana-Dakota Utilities Co.v. Colorado Interstate Gas Co., 23 FERC ¶ 61,418 (1983). As demonstrated herein,there is no reason for the Commission to change this disposition.

DC_DOCS_A 1049583 v 10 40

does the September Order suggest that these actions were improper.68

VII. COMMUNICATIONS

All communications regarding this matter should be directed to the following individuals, whose

names and addresses should be included in the official service list in this proceeding:

Howard H. ShaffermanBallard Spahr Andrews & Ingersoll, LLP601 13th Street, NWSuite 1000 SouthWashington, DC 20005-3807(202) 661-2205

Kathleen A. CarriganVice President, General Counsel andSecretaryISO New England Inc.One Sullivan RoadHolyoke, MA 01040-2841(413) 540-4260

DC_DOCS_A 1049583 v 10 41

VIII. CONCLUSION

For the reasons discussed herein, the ISO requests that the Commission deny the relief

requested by the Complainants and dismiss the Complaint with prejudice.

Respectfully submitted,

_________________________________Howard H. ShaffermanKenneth J. LabachBallard Spahr Andrews & Ingersoll, LLP601 13th Street, N.W., Suite 1000 SouthWashington, D.C. 20005202-661-2200

_________________________________Kathleen A. CarriganVice President, General Counsel & SecretaryISO New England Inc.One Sullivan RoadHolyoke, MA 01040413-540-4260

_________________________________Robert C. GerlachC. Baird BrownBallard Spahr Andrews & Ingersoll, LLP1735 Market Street, 51st FloorPhiladelphia, PA 19103215-665-8500

Date: February 22, 2000

July 13, 1999

From: Charles Ide

To: NEPOOL Regional Market Operations Committee

Subject: Administration of the Operable Capability Market During June 1999

This letter is intended to provide information to the NEPOOL Regional Market Operations Committee(RMOC) related to administration of the Operable Capability (OPCAP) market during the month of June1999. The emphasis is placed on administration of the market during when the NEPOOL capacity situationwas tight. The memo describes the process we will use in settling the OPCAP market during times of OP-4. At this time, until we are able to complete a detailed resettlement of the Market for those hours affectedby emergency purchases. The OPCAP prices and settlement data are preliminary.

General Information

In the ISO’s OPCAP Settlement software, is a routine that verifies, for each Trading Interval, that the sumof the OPCAP surpluses is equal to or greater than the sum of the OPCAP deficiencies. In the case of aTrading Interval for which this is not the case, the positions of the OPCAP market participants are adjusted(see example below) such that the sum of the surpluses is equal to the sum of the deficiencies prior tocalculating the market Settlement.

Example:Market Position

Pre Adjustment Post Adjustment

Participant A -5 (- means deficiency) -3.75Participant B -15 - 11.25Participant C +15 +15

Surplus minus Deficiency -5 0

Once this calculation is completed, the OPCAP market is then cleared using the Participant bids for theresultant surplus OPCAP for each Participant.

Information Specific to Trading Intervals When OP 4 is Implemented

The ISO has implemented the following interpretations of the Market Rules and Procedures that areapplicable to the OPCAP market during implementations of Operating Procedure No. 4 – Action During aCapacity Deficiency (OP 4).

1. During all OP 4 Trading Intervals, the MWs of Operating Reserve designated by the ISO is comparedto the MWs of ISO Operating Reserve requirement in each of the three (3) Operating Reserve markets.To the extent that the MWs designated in a market is less than the MWs required in that market, theMWs required are set equal to the MWs designated for that market for that Trading Interval . Thisaction has the impact of reducing the total OPCAP requirements for that Trading Interval by an equalamount.

2. During OP 4 Trading Intervals in which the ISO purchases emergency assistance from neighboringcontrol areas, Operable Capability credit, in an amount equal to the total MWh of Emergency Capacityand Energy purchased during the Trading Interval, is allocated to those Participants with a NegativeAdjusted Net Interchange (Energy market) for the Trading Interval.

Application of the Above During the Month of June 1998

In the Settlements included in the June Bill, the positions of OPCAP market participants were adjusted suchthat surpluses equaled deficiencies in the following Trading Intervals:

Day Trading Interval (hour ending)

June 7 1700, 2100

June 8 1300, 1400, 1500, 1600, 1700, 1800

June 28 1400, 1500, 1600, 1700, 1800

In the Settlements included in the June Bill, Operating Reserve Requirements were adjusted down to beequal to Operating Reserve Designations in the following Trading Intervals:

Day Trading Interval (hour ending)

June 1 1400, 1500, 1600, 1700

June 2 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900

June 7 1000, 1100, 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900, 2000, 2100, 2200

June 8 1000, 1100, 1200, 1300, 1400, 1500, 1600, 1700, 1800, 1900, 2000

June 28 1300, 1400, 1500, 1600, 1700, 1800

June 29 1400, 1500, 1600

In the Settlements included in the June Bill, OPCAP associated with purchases of Emergency Capacity andEnergy was not allocated to Participants with Negative Adjusted Net Interchange (Energy market) in anyTrading Intervals. For the June Bill, the impact of allocating the OPCAP to Negative ANI Participants wasestimated to arrive at estimated OPCAP Clearing Prices for certain Trading Intervals (listed below). TheOPCAP Settlements for all June hours in which Emergency Capacity and Energy were purchased will bererun with any resulting adjustments (including Clearing Price) to the Settlements to be included in asubsequent month’s bill.

Hours for which Emergency purchase impact on Clearing Price was estimated.

Day Trading Interval (hour ending)

June 8 1300, 1400, 1500, 1600, 1700, 1800

June 28 1300, 1400, 1500, 1600, 1700, 1800

DC_DOCS_A 1049823 v 1

UNITED STATES OF AMERICABEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

DIGHTON POWER ASSOCIATES LIMITEDPARTNERSHIP, FPL ENERGY, L.L.C.,SOUTHERN ENERGY NEW ENGLAND, L.L.C.,and SOUTHERN ENERGY KENDALL, L.L.C.

v.

ISO NEW ENGLAND INC.

)))))))))

Docket No. EL00-40-000

AFFIDAVIT OF CHARLES R. IDE

I, Charles R. Ide, hereby depose and state as follows:

1. My name is Charles R. Ide. I am Manager of Settlement Operations for ISO

New England Inc. (the “ISO”), the system operator and market administrator for the New

England Power Pool (“NEPOOL”). My business address is One Sullivan Road, Holyoke, MA

01040-2841. My responsibilities include settlement of the seven NEPOOL Markets and the

NEPOOL Open Access Transmission Tariff. I have had these responsibilities since

September 1994.

2. The purpose of this affidavit is to confirm certain facts relating to the complaint

made in the referenced docket.

3. I am responsible for settling the Operable Capability Market for the period

between its inception on May 1, 1999 and August 5, 1999.

DC_DOCS_A 1049823 v 12

4. My July 13, 1999 memorandum attached to the Answer of the ISO in this

proceeding accurately describes the interpretations the ISO has made in order to settle the

Operable Capability Markets prior to August 5, 1999.

5. My July 13, 1999 memorandum attached to the Answer was sent by the ISO

to the members of the NEPOOL Regional Markets Operation Committee on July 13, 1999.

6. The ISO is not using and has never proposed to use the price cap provisions of

Market Rule 10.4.5 (filed with the Commission and made effective August 5, 1999) to settle

the Operable Capability Market before August 5, 1999.

7. In settling the Operable Capability market for the period from May 1, 1999 to

August 4, 1999, I am crediting Participants with Operable Capability from emergency

purchases only in circumstances where both capacity and energy were purchased from

neighboring control areas.

Further affiant sayeth naught.

_____________________________Charles R. Ide

Sworn to before me the 18th day of February, 2000