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CRR Credit Policy Task Force Update

This update discusses the potential impact of a credit default in the Day Ahead Market and the appropriate margin requirements for CRR obligations. It also explores alternative solutions and concerns regarding the current credit policy.

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CRR Credit Policy Task Force Update

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  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 Amount dwindles Self-schedule Self Schedule Cost Day Ahead Market Cost + default tax VS

  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. Large Default Example Cont’d. • 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 $1.2 Million - Energy $195 Million $0.738 Million – A/S $0.720 Million – CRR Not even close! $2.658 Million

  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?

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