The Master Wholesale Electric Contract

1. The MasterWholesaleElectricContract Patricia Dondanville Schiff Hardin & Waite David M. Perlman Constellation Power Source J.W. Marriott Houston March 7, 2000

2. WhyWholesaleElectric Contract Standardization? • Each transaction has common commercial terms, e.g. 50MW on-peak, into Cinergy, for July-August • Business people treat transactions as identical, as “hedges” for one another • Traders presume “infrastructure” exists, as in other markets

3. Why WholesaleElectric Contract Standardization? • Lack of or differences in legal terms, “infra-structure,” only become critical in times of market stress • 1998 June price spikes and market defaults focused discussion on lack of documents and credit concerns • 1999 market events focused discussion on tariff/ contract inconsistencies

4. Why Wholesale Electric Contract Standardization? • Variety of Trading Documentation • Cost-based tariffs • Market-based rate tariffs (and service agreements) • Unilateral contracts • Bilateral contracts • Pool-enabled transactions • Other

5. Why a Master Agreement at All? • Why not just do business under two one-way tariffs or one tariff and one agreement? • Payment netting, creditworthiness and other bilateral issues • Inconsistencies in rights/obligations are not priced into transactions • Choice of different laws • Is an oral transaction binding? • Does the UCC apply? • Dueling damages calculations • Imprecise and inconsistent product definitions

6. Why a Master Agreement at All? • Most tariffs do not contain • Remedies which reflect bilateral nature of counterparties’ relationship (“can I stop delivery to X if X doesn’t deliver to me?”) • Reliance waivers • Recording consents • Force majeure language which recognizes the existence of a market for electric power • Closeout netting under master agreement - bankruptcy law issues • If don’t ask for authority reps, nonreliance reps, don’t assume

7. Why the EEI Master Agreement? • Each market participant has own preferences • Bilateral negotiation can take months – while traders continue to trade and create risk • Consensus document – flexible, workable, even-handed, reciprocal framework • Industry/market development = liquidity • More consistent power products and hedging possibilities = certainty and reliability

8. What the EEI MasterAgreement Does Not Address • Dispute resolution mechanism • Provisions re tax or regulatory changes • Significance of bookouts, circles or daisy chain transactions • FERC treatment of documentary conflicts • Education – what does “firm” mean? What does “into” mean • Administration of confirmations and other time sensitive obligations • Back office operational risk - Contract Administration deadlines • Credit and collateral administration • Cross-collateralization and cross defaults with financial transactions • Risk management, hedging decisions and stress testing • Idiosyncratic products/needs – “But I need the power!?!” • Transmission issues

9. ADVANTAGES Uniformity in obligations and responsibilities Balance of negotiating power Shorter time negotiating masters, if widely adopted Review confirmations on exception basis DISADVANTAGES Confirmation administration – standardizes time sensitive performance obligations If always seller or buyer, different provisions and/or product definitions may be required Party with greater bargaining leverage loses ability to “impose” favorable provisions Contract Administrators/Lawyers

10. ADVANTAGES Product Consistency =Hedging Certainty DISADVANTAGES Don’t need to deal with lawyers as often Risk Managers

11. ADVANTAGES Consistent payment and netting terms Consistent counterparty evaluation and monitoring process Clear events of default and unwind mechanisms DISADVANTAGES Don’t need to deal with lawyers as often Chief Financial Officers/Credit Managers

12. ADVANTAGES Focus on price, product, quantity, delivery point, duration Liquidity DISADVANTAGES Don’t need to deal with lawyers as often Traders

13. ADVANTAGES Liquidity = Reliability Self-Regulating Market Education Consensus DISADVANTAGES None Regulators

14. Wholesale Electric Contract Standardization • Process Initiated- Fall 1998 EEI Legal Committee Meeting • Group Progress • Kick-off meeting- January 29 • Group effort defined • Drafting Group established • Drafting Group Product • Issues Identified • Proposed Standardized Terms

15. Wholesale Electric Contract Standardizationric • Group Progress (Cont.) • Follow- up meetings - March, May, June 1999 • Summer 1999 - intense Drafting Group meetings and calls • Presentation to larger group - September 24 • Input from expanded participation • Discussion of Drafting Group efforts • Refinement of issues • Distribution of Consensus Draft - mid-October • EEI/NEMA Workshop- November 17, 1999 in Washington D.C.

16. Wh Wholesale Electric Contract Standardization olesale Electric Contract Standardization • Group Progress (Cont.) • Product Definitions discussed in December 99 Working Group meeting • Product Definitions refined by Drafting Group in January 2000 • Working Group adopts product definitions on January 26, 2000 • Meeting with FERC Staff on February 2, 2000.

17. Participants in Developing StandardizedMaster Wholesale Electric Contract • DRAFTING COMMITTEE • Constellation Power Source • Schiff Hardin & Waite • American Electric Power • Dynegy, Inc. • Entergy Power Marketing • Enron North America • Jones Day Reavis & Pogue • Reliant Energy • Statoil Energy • Edison Electric Institute

18. Steering Committee Participants Midamerican Energy Company GPU Energy First Energy Corp Western Resources GPU Service, Inc. New Century Energies New England Electric System Superior Water, Light & Power Rochester Gas & Electric Kansas City Power & Light TECO Energy Inc. Conectiv Illinova Energy Marketing PECO Energy Power Team Minnesota Power Aquila Midland Cogeneration Venture Citizens Power Cinergy Energy Trading Northern States Power Indiana Power & Light Company Steel Manufacturers’ Association Northeast Utilities Northern Indiana Public Service Company Commonwealth Edison Company Ameren Energy Williams Company Duke Energy Trading Enserch Energy Services Virginia Power Dynegy PG&E Energy Trading Prebon Yamane Southern Company Energy Marketing PSE&G Pepco Consumers Energy Detroit Edison Reliant Energy DTE Energy Trading Arizona Public Service Consolidated Edison Niagara Mohawk Energy Ontario Power Generation TXU Energy

19. Let’s Make a Deal: Transactions Under A Standardized Master Power Contract • Products • Prices • Delivery points • Oral trading • Confirmation process

20. Master Agreement ProcessASSUMPTIONS • Both parties have model streamlined tariff and service agreement without substantive terms and conditions • Parties have negotiated no changes to master agreement • Parties have negotiated options and cover sheet • notices • applicable tariffs, if any • acceleration of liquidated damages payment • cross defaults • guarantee amounts • choice of credit mechanisms

21. Formation of a Trade Party A Party B Oral TransactionBinding -Product -Writing not required -Price unless stated -Delivery -Time Phone Phone 3 Days 3 Days Seller Sends Confirm Buyer Sends Confirm No Seller & Buyer Sends Confirm Confirm No Confirm Sent or Received 2 Days 2 Days Recipient Signs Confirm Seller Doesn’t Object Seller Objects Buyer Objects Buyer Doesn’t Objects Binding Confirmation

22. Non-firm Unit firm System firm Firm with liquidated damages Into delivery point Firm with noforce majeure Increasing performance obligations on both parties Products

23. Non-Firm Product Deliver and receive Fail to deliver or receive forany reason or no reason Non-performance for anyreason or no reason excused Payment Failure to pay

24. Unit Firm Product Generating unitnot operating Generating unit operating Liquidated damages Deliver and receive Force majeure event Full or partial generating unit outage Failure to pay Payment Performance excused

25. System Firm Product Identified System’s Generation and Purchased Power Seller’sforce majeure event Pre-existingsystem reliabilityand reserve requirements Identified system’s integrity orstability Deliver/receiveat identified system’ssource Deliver & receive Other party’s default Native load/firm service obligation Performance excused without liability Payment Failure to pay Failure to pay Payment

26. Firm with Liquidated Damages Product Claimed Force Majeure Event Deliver & Receive Transmission to Seller’s Point of Delivery Performance Excused Not Timely Scheduled Non-firm Transmission Curtailed Firm Transmission Curtailed Due to Force Majeure Event Liquidated Damages Failure To pay Payment Plus other Factors

27. Into Product Buyer has risk of curtailment (from Interface, but not prior) 1. Timely Request for and if cut, Seller has performed No and Buyer has not. Buyer Firm by Buyer? repsonsible to Seller for damages, if any. Yes No No 4. Timely Rejection 2. Firm Available? Notice by Buyer? Yes Yes No 3. Firm Purchased by Buyer? Seller has risk of curtailment (to and Yes from Interface, but not beyond Control area), and if cut must select ADI. If Seller is unable to deliver at the ADI or at a subsequently selected ADI (or buy inside the control area), Seller responsible to Buyer for damages, if any. NY:1086384v1[PowerPoint]

28. EXAMPLE #1 DP&L e BUYER AND SELLER BOTH PURCHASE FIRM AND BUYER’S FIRM GETS CUT. e Firm NIPSCO Firm Cinergy X Wabash Valley AEP LG&E Assumptions: 1. Seller sells 50 MW for delivery “Into Cinergy, Seller’s Daily Choice” 2. Seller preschedules day-ahead by 11:00 a.m. CPT by notifying Buyer of source and designated interface, DP&L. Seller purchases Firm transmission from source in DP&L to DP&L/Cinergy interface. 3. Buyer puts in request for Firm transmission within 30 minutes of Seller’s notification and request is accepted and purchased by Buyer. Entergy is sinking in Cinergy. Hypothetical: On delivery day, Cinergy cuts Buyer’s Firm transmission. Results: Seller must move to another interface (either on Cinergy’s border (NIPSCO, LG&E, AEP. . .) or in Cinergy’s control area (Wabash) at which Buyer can receive energy such that energy can sink in Cinergy. Seller can require Buyer to purchase Non-Firm transmission (or Firm, if available) but each party will be responsible for any additional transmission costs incurred to reschedule to another delivery point. If Seller cannot reschedule and deliver, Seller will owe LDs to Buyer on Seller’s failure to deliver. Same Result If: 1. Seller’s generation gets cut. 2. Seller’s Firm transmission gets cut. 3. Seller’s Non-Firm transmission gets cut.

29. EXAMPLE #2 DP&L BUYER PURCHASES NON-FIRM THOUGH FIRM WAS AVAILABLE, AND NON-FIRM GETS CUT. e e Firm NIPSCO Non-Firm Cinergy X Wabash Valley LG&E AEP Assumptions: 1. Seller sells 50 MW for delivery “Into Cinergy, Seller’s Daily Choice” 2. Seller preschedules day-ahead by 11:00 a.m. CPT by notifying Buyer of source and designated interface, DP&L. Seller purchases Firm transmission from source in DP&L to DP&L/Cinergy interface. 3. Buyer puts in request for Firm transmission within 30 minutes of Seller’s notification and receives response that Firm is available. Buyer purchases Non-Firm instead. Entergy is sinking in Cinergy. Hypothetical: On delivery day, Cinergy cuts Buyer’s Non-Firm transmission. Results: Seller’s obligation was met and Seller has no obligation to attempt to deliver to another interface. Curtailment was due to quality of transmission utilized by Buyer. Buyer will owe LDs to Seller on failure to receive (Definition Section 3C). Same Result If: 1. Following Seller’s notification regarding availability of next-day Firm transmission, Buyer fails to make a timely request for Firm transmission (Definition Section 3D). 2. Following Seller’s notification regarding availability of next-day Firm transmission, Buyer makes a timely request for Firm transmission, but fails within 15 minutes of receiving the transmission provider’s notice of rejection to notify Seller of same (Definition Section 3D).

30. EXAMPLE #3 DP&L BUYER IS ATTEMPTING TO BRING PRODUCT OUTSIDE OF TRANSMISSION SYSTEM BORDER, AND PATH IS CUT. e e Non-Firm NIPSCO Firm LG&E Cinergy Firm X Wabash Valley AEP Assumptions: 1. Seller sells 50 MW for delivery “Into Cinergy, Seller’s Daily Choice” 2. Seller preschedules day-ahead by 11:00 a.m. CPT by notifying Buyer of source and designated interface, DP&L. Seller purchases Non-Firm transmission from source in DP&L to DP&L/Cinergy interface. Hypothetical: On delivery day, LG&E cuts Buyer’s path because of the Non-Firm transmission purchased upstream by Seller. Results: Seller’s obligation was met, and Seller has no obligation to attempt to deliver to another interface. The scheduled delivery was interrupted as a result of Buyer’s attempted delivery of the Product beyond Cinergy. Buyer will owe LDs to Seller on Buyer’s failure to receive (Definition Section 4A).

31. Firm with No Force Majeure Product Delivered and received Liquidated damages Failure to pay Payment

32. Remedies for Failure to Deliver/Receive Example 1. Party A agrees to sell Party B 50MWh/h for Peak Hours on the next weekday for delivery at PJM Western Hub. The Product is Unit Firm and Party A fails to deliver because Party A's generation source is forced out. Outcome: No damages payable. There is no unexcused failure to perform. In this case the Product sold is Unit Firm, and by definition, the obligation to deliver Unit Firm Product is excused by forced outage of the relevant generation asset.

33. Remedies for Failure to Deliver/Receive Example 2. Party A agrees to sell Party B the same 50MWh/h for Peak Hours on the next weekday for delivery at PJM Western Hub. The Product is Firm (LD) and Party A fails to deliver because Party A is prevented from doing so by Force Majeure. Outcome: No damages payable. Because Party A's performance was prevented by Force Majeure, there is no unexcused failure to perform.

34. Remedies for Failure to Deliver/Receive Example 3. Yesterday, Party A agreed to sell Party B 50 MWh/h for Peak Hours today. The delivery point is COB, and price is $30/MWh. The Product is Firm (No Force Majeure) and Party A fails to deliver. Party A has no excuse (e.g., Party B's failure to perform). Today's price for the Product at the delivery point exceeded $30. Outcome: Party B's options are as follows: 1. Acting in a commercially reasonably manner, buy replacement Product at COB and receive from Party A the excess of (a) the purchase price of such replacement Product, (plus reasonably incurred costs and transmission costs to COB, if any), expressed in US$, over (b) $30/MWh x 50 MWh/h x 16h.

35. Remedies for Failure to Deliver/Receive Example 3 (contd.) OR 2. Acting in a commercially reasonably manner, determine the market price of replacement Product at COB and receive from Party A an amount determined by reference to such market price, as follows: Assume that MW Daily Market Report's Weighted Average Index for COB deliveries today is $32.69/MWh; the amount receivable from Party A is the excess of (a) $32.69/MWh x 50 MWh/h x 16h, over (b) $30/MWh x 50 MWh/h x 16h.

36. Remedies for Failure to Deliver/Receive Example 3 (contd.) Party B is entitled to receive this amount: (a) whether it covers or not (b) if it determines the market price in a commercially reasonable manner, i.e., not the published high or low (c) if the market price determined is for a financial firm product, delivered at or adjusted to the delivery point (d) even if it declines to produce replacement Product using its own generation assets that could have been employed to produce replacement Product.

37. Remedies for Failure to Deliver/Receive Example 4. Party A agreed to sell Party B 50MWh/h for Peak Hours for the month of November, 1999 for delivery into Cinergy, at a price of $30/MWh. Party B opts for non-firm transmission, suffers an interruption on November 17, and as a result Party A cannot and does not deliver on November 17. On November 17, the price on November 17 for the Product balance of the month of November is $28. Outcome: Since, in accordance with the definition of "Into" Product, Party B is deemed to have failed to receive the Product, Party A's options are as follows: 1. Acting in a commercially reasonable manner, resell the Product and receive from Party B an amount equal to the Contract Price less the sales proceeds (reduced by reasonably incurred costs and additional transmission changes, if any). Assuming a net resale price of $28, the amount receivable from Party B would be ($30 MWh-$28 MWh) x 50 MWh/h x 16 h/day x 9 days.

38. Remedies for Failure to Deliver/Receive Example 4 (Contd.) OR 2. Acting in a commercially reasonable manner, determine the market price of the Product for the balance of the month of November, e.g. from MW Daily's Market Report, and receive from Party B an amount determined as above, but using the market price instead of the net sales proceeds. Party A is entitled to receive this amount: (a) whether or not the Product was actually resold (b) ) as long as the market price was determined in a commercially reasonable manner, taking into account relevant available market data (c) even if Party A held a trading position (e.g., a put) that would have entitled it to sell the Product at a price in excess of the Contract Price, and elected not to use its trading position to eliminate the loss caused by Party B's failure to receive

39. Transaction Netting Bilateral outstanding transactions between same parties, by subsequent agreement, may be offset Amount of energy owed a party offset by energy owed to counterparty Single transaction contract for net energy delivered and received Offsetting transactions terminated Payment netting

40. When the Deal Does Not Go Down • Remedies for failure to deliver and receive the product • Force majeure events

41. Performance of a Transaction Option Exercised Option Expires Transaction Netting/Bookout Physical Transaction Potential Event of Default (during cure periods) Suspend Performance of “anyor all” transactions (for up to 10 days) notice Scheduling Delivery & Receipt Resume Performance Credit -Exposure Amount -Downgrade Event -Security Interest Delivered & Received Failure to Perform notice Liquidated Damages Event of Default Claimed Force Majeure Event Other Party’s Failure to Perform Payment Made Unexcused Failure to Perform Payment Process Failure to Pay notice

42. Liquidated Damages Seller’s Unexcused Failure to Perform Buyer’s Unexcused Failure to Perform Replacement Price - Contract Price if positive Contract Price - Sales Price if positive Option for payment in 5 days • Sales Price • Commercially reasonable manner • Resale of product at delivery point • Option: market price at delivery point • Book out upstream considered resale of product • Reduced by additional, incidental and transmission costs • Excludes penalties • Not required to utilize seller’s generation or market positions/options • Contract Price • US $ Amount • Specified in Transaction • Replacement Price • Commercially reasonable manner • Purchase of replacement product at delivery point • Option: market price at delivery point • Book out downstream considered as replacement product • Includes additional costs, including transmission costs to delivery point • Excludes penalties • Not required to utilize buyer’s generation or market positions/options Payment Process

43. Claimed Force Majeure Events Event that prevents performance and cannot be avoided or overcome, not anticipated, not within reasonable control or result of negligence Excludes loss of Buyer’s markets, uneconomic resale, loss of Seller’s supply, ability to sell at higher price Transmission Provider Interruption Contracted For Non-Firm Transmission Product Definition can Alter Affect of Event Contracted for Firm Transmission Unexcused Failure To Perform Force Majeure Event Excusing Performance Interruption due to Force Majeure Other Factors and circumstancesestablish performance was prevented

44. Show Me the Money • Payment • Payment netting • Billing disputes • Audit rights/confidentiality

45. Payment Process Calendar Monthly Invoice Due on the later of 20th day or 10 days after invoice; exceptions: accelerated LDs (if selected) and option premium due 2 days after invoice receipt; 12 months to challenge accuracy Dispute of Invoice Amount Failure to Pay Pay by Electronic Funds Transfer Pay Undisputed Amount Notice of Dispute & Reasons Accrue Interest at Interest Rate Event of Default Litigation Adjusted Invoice

46. Payment Netting Mutual debts and payments due on same date Summation of mutual payments, liquidated damages, option premiums, interest, credits due--exclude performance assurance and guaranty amounts No mutual obligations-- Pay when due If event of default or notice given in writing, include in netting the amount of performance assurance Party owing greater amount pays net amount when due

47. Audit Rights • Normal business hours, at requesting party’s expense, solely for verifying statements, charges or computations. • Waiver of objection and right to audit 12 months after rendering statement or payment.

48. Major Meltdowns • Events of default • Winding down trading relationships • Termination payments • Netout • Closeout setoff

49. Other Provisions of Legal Importance • Limitation of Remedies/Liability/Damages • Taxes — Seller liable before delivery point, buyer liable at and after • Representations and warranties • duly organized • regulatory authorizations • corporate authority • legally enforceable obligations • no pending bankruptcy or materially adverse legal proceeding • no event of default or potential event of default has occurred • using own business judgment, no reliance on other party • forward contract merchant status • ability to make or take delivery • for an option, party is merchant for business-related purposes

50. Other Provisions of Legal Importance • Title, risk of loss and indemnity —seller liable before delivery point, buyer at and after • Assignment prohibited without consent, except to creditworthy affiliate or to successor of assets • Governing law is New York; waiver of jury trial • Tariff amendment shall not effect outstanding transactions • Inconsistent tariff language not assertable as defense • No intended third party beneficiaries