1 CRR Credit Policy Task Force Update WMS April 16, 2008

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

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 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 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 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 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 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 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 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 $50/MWh or $1.2M for the day  Sellers of ancillary services (1/2 of market) 1,250MW of $15/MW = $450k 600MW of RGS Up & $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 Proposed Alternatives (possible vote) Key problem with current method is avoidability Option 1: Fund defaults from CRR Balancing Account  New step would be created 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) Option 2: Uplift using the same mechanism for other defaults  Benefit is smoother timeline for recovery

12 CRR Obligation Margin Concerns Current Nodal Protocols contain a $10/MW-hr adder for CRR Obligations For a nominally valued CRR this equates to a $87,600MW-yr margin requirement A 1,000MW entity wishing to hedge from Hub to Load Zone would require $87.6M in margin just to put on the hedge By comparison NYISO has adopted a $2,000/MW-yr adder for Obligations Discussion continues on “rightsizing” credit requirement

13 TCR Shadow Price Example Important Considerations  Prices shown are similar to flowgates not true hub-hub  Prices do not go negative like you would see in actual market  These paths are noted for congestion potential, many CRRs will not cross these boundaries  Prices are average of all intervals, hourly SP’s would be even more volatile

14 Margining Alternatives Historic value plus adder is current mechanism Forward looking tool may be possible for ongoing margin requirement but not feasible for auction  “Lumpy” credit requirement wouldn’t react well with MIP clearing auction  Auction is most important time to catch requirement  Auction and ongoing credit req’s should match Enhanced statistical methods may be needed

15 Questions?