1. 1 CRR Credit Policy Task Force Update TPTF July 21, 2008

2. 2 Two Major Issues How a credit default would impact the Day Ahead Market The correct level of margin required for CRR Obligations

3. 3 DAM Benefits Allows for correction of position by hour of:  Energy  Ancillary Services  Transmission congestion risk (basis) Shock absorption of RT prices Rational unit commitment Optimization of energy and ancillary services Assigning defaults to DAM places market at risk

4. 4 Default Risk Example How would $90M default in PJM look here  Cost assigned to those owed money in DAM  $90M was over a roughly 6 mo. Period  For a year $90M – approx. $0.30/MWh on all MWhs (1 cent = $3M)  ½ year – approx. $0.60/MWh  Assuming bulk of loss occurred during a two week construction period 60% of loss over 1/13 the time – approx. $4.68/MWh The key is that this is on all MWhs

5. 5 Dwindling Pool of Risk Takers Defaults will be applied to those owed money in DAM:  Sellers of energy  Sellers of A/S  CRR holders owed money DAM is voluntary  MPs will take action to alleviate risk if possible

6. 6 Sellers of Energy PJM has large DAM pool due to ICAP requirements We have no such requirements After a default sellers have choice  Self schedule and add nothing  Offer in and add some unknown amount Value exists for marginal units, but default tax can eliminate and reverse value As size of those owed money diminishes – impact increases requirement Self-schedule Self Schedule Cost Day Ahead Market Cost + default tax VS Amount dwindles

7. 7 Sellers of A/S Similar to Sellers of Energy  Sellers will be pushed to forwards markets to avoid paying voluntary tax  Most if not all A/S self scheduled  Collapses A/S market Forwards Market Cost Day Ahead Market Cost + default tax VS

8. 8 CRR holders owed money Without energy buys/sells CRRs have zero value To redeem value, corresponding self schedules must be entered Schedules can flow up to full capability of system  Pro rata curtailment beyond? Entities may attempt to cash in on lack of basis, but pool will be small due to preallocation and lack of counterflow offers Sales are dependent on seller being on other side  However seller won’t be paid full amount  Seller would have to charge expected value + default tax premium  Buyer will not cover spread needed

9. 9 Back to Large Default Example For market to work without perversion, default “tax” would need to be nominal risk  Buyers select suppliers based on $0.10/MWh differential  At $50/MWh this is 0.2%  For the example we’ll increase this by an order of magnitude or $1.00/MWh (2%) Back to our original example:  $90M default, 60% in first two weeks or $54M  Equates to $3.9M per day (similar in scale to TCE default)

10. 10 What the market will pay  Market would need to be about $195M/day in size to absorb this cost without perversion (3.9M/.02)  Sellers of energy: Assume 1000MWs @ $50/MWh or $1.2M for the day  Sellers of ancillary services (1/2 of market) 1,250MW of RRS @ $15/MW = $450k 600MW of RGS Up & Dn @ $20/MW = $288k  CRRs: Assume 3,000MWs at $10/MWh spread for entire day = $720k  Doesn’t even cover $3.9M payment – Sellers get $0! Much smaller default could damage the market Large Default Example Cont’d. $1.2 Million - Energy $195 Million $0.738 Million – A/S $0.720 Million – CRR $2.658 Million Not even close!

11. 11 WMS Selected Alternative Fund defaults from CRR Balancing Account and CRR Auction Revenues  New step would be created before disbursement of fo CRR Auction Revenues and after payment of CRR short pays to pay defaults  Payments continue until default is fully funded  Benefit is money is unbudgeted (unexpected)  Concern with availability of funds (may need backup) NPRR written, but not yet submitted  Has been at ERCOT settlements for formula correction

12. 12 NPRR 130 CRR Obligation Margin Adder 16.11.4.6Determination of the Counter-Party Future Credit Exposure ACPE h, (j,k)$/MW per hour Auction Clearing Price Exposure for PTP Obligations with the source j and the sink k for hour h - Exposure level calculated as follows: if the PTP Obligation Auction Clearing Price is greater than $15 per MW, then 150 divided by the PTP Obligation Auction Clearing Price; if the PTP Obligation Auction Clearing Price is between $0 and $15 per MW, then $10 per MW; and if the PTP Obligation Auction Clearing Price is negative, then $10 per MW, plus the absolute value of the PTP Obligation Auction Price per MW. The bulk of CRRs that will be purchased will price less than $15/MW and will receive the full $10/MW margin adder for each hour of purchase Over the year this is a credit requirement of $87,600/MW for rights that will largely have a fraction of this value and even those CRRs that have positive value to the holder (ERCOT owes credit to counterparty) This will effectively eliminate the CRR Obligations market for any rights of any term NPRR 130 revises the $10 value to “X” and seeks input on what that variable should be revised to For reference NYISO and MISO use adders in the $0.24/MWh and less range

13. 13 Questions?