Internal and Confidential to EESMay 16, 20011 Illinois Market Marc L. Ulrich.

May 16, 2001 1 Internal and Confidential to EES

Illinois MarketMarc L. Ulrich


State of IL Composition

G T D TotalComEd 54.51 3.77 12.33 70.61 Illinois Power 50.06 1.40 11.04 62.50 AmerenCIPS 35.83 4.47 15.16 55.46 AmerenUE 35.72 1.54 14.76 52.02 CILCO 35.70 1.79 15.40 52.89 Interstate Power 31.48 5.71 12.57 49.76 Mid-American 30.70 4.01 16.66 51.37

1998 Embedded Costs ($/mwh)

ComEd 51,048 66%Illinois Power 12,754 16%AmerenCIPS 5,478 7%CILCO 3,976 5%AmerenUE 3,204 4%Mid-American 1,125 1%Interstate Power 272 0%

1998 C&I Retail Sales (GWH)

Com Ed

Illinois Power

Ameren/CIPS

CILCO

Ameren/UE


Direct Access

• 12/97 House Bill 362, “The Electric Service Customer Choice and Rate Relief Act of 1997” was enacted

• The HB 362 provides mandated rate cuts and customer choice for all non-residential by January 2001 and for residential by May 2002

• Competitive Transition Charges (CTC) are allowed to be recovered by utilities until December 2006

• HB 362 has a clause that states that it can be completely dissolved anytime if market is not significantly competitive (very vague)

• Switching as of December 2000:– About 12% of ComEd’s eligible customers representing 50% of their load

switched suppliers– Illinois Power had about 6.9% customer switching– AmerenCIPS had about 6.8% customer switching


Direct Access

• Retail Access Implemented:– 10/1/99 33% of C & I customers through lottery system– 6/1/00 All manufacturing– 1/1/01 All C & I– 1/1/02 All residential

• All non-residential customers have direct access. These customers can choose one of three options…– Benchmark Bundled Rate (BBR) - bundled tariff

– Power Purchase Option (PPO) - unbundled, discounted

– Alternative Retail Electric Supplier (ARES)

• To choose either of the last two the customer must be on a delivery service rate (ComEd = RCDS 24 mo. initial term, 12 mo. Renewals)


Rate Components

• “Residual CTC” means the CTC rate depends on the value of other components, mainly the market value (MV) of generation (a.k.a. Lost Revenue Method)

• Transition Charges are calculated as…CTC = BBR - DS - MV - MF

CTC = Customer Transition ChargeBBR = Bundled Base RateDS = Delivery Service (T&D)MV = Market Value of GenerationMF = Mitigation Factor (Mandatory Discount)

• BBR, DS, and MF are predetermined fixed components and therefore the CTC varies inversely with MV

• The resulting CTC calculation (revised each March) is used for PPO and ARES bill calculations


Rate Components

Mitigation Factor

Greater of mills/kWh PercentTill 2003 5 8%2003-04 5 10%2005 6 11%2006 9 12%


ComEd’s Customer Class

• Small Customers– 0 - 25 kW– 25 - 100 kW– 100 - 400 kW– 400 - 800 kW– 800 - 1,000 kW– 1,000 - 3,000 kW

• Large Customers– 3,000 - 6,000 kW– 6,000 - 10,000 kW– 10,000+ kW

• Small and Large Customer CTC’s are calculated differently


Rate Components

• The MV component shows up in the CTC and the PPO

• PPO is calculated as…PPO = DS + CTC + MV

Small CustomersCTCCL= BBRCL - DSCL - MVCL -

MFPPOi = DSi + CTCCL + MVi

Where

MVCL MVi

Large CustomersCTCi= BBRi - DSi - MVi - MFPPOi = DSi + CTCi + MVi

so,

PPOi = BBR - MF


Market Value Calculation

• Market value calculations are as simple as Price times Quantity (PQ)

Jan Dec

P

Market ValueCustomer A (LLF) $35.13 > Class Avg.Customer B (HLF) $21.06 < Class Avg.Customer C (Class Avg.) $26.07 = Class Avg.

Jan Dec

Q

A (LLF)

B(HLF)

C (Class)


Forecast & Regulatory Assumptions

• Standard Offer ends (CTC rolls-off) one year early December 31, 2005 instead of legislative date of December 31, 2006

• Bundled Tariffs remain frozen through end of transition December 31, 2005

• Fuel Cost factors embedded in “frozen” rate and thus insulated from fuel market volatility

• CTC is assumed to be greater than zero

• Delivery Service rates are assumed to be flat until January 1, 2006, where downward pressure of “lower-risk” wires business receives lower rate of returns from Commission


Forecast & Regulatory Risks

• Late CTC roll-off risk is estimated to be $6 million - nominal(greater of 9mills/kWh or 12% of UDC Fixed rate applied to current positions)

• Hypothetical Delivery Service rate increase of 5% increases exposure by $2.5 million - present value (T&D rates*0.05 applied to current T&D MWh positions)

• Risk of negative CTC can move customers back to bundled or pay higher rates on PPO and increase Enron’s cost to serve (impact not estimated)

• Meter Service Provider (MSP) unbundling needs to result in a equal offsetting credit (impact not estimated)

• ISO/RTO formations are in the works and delivery rates of ComEd may be redefined upward (impact similar to DS rate increase sensitivity)


Regulatory Strategy

• Ensure CTC Roll-off occurs by December 31, 2005

• Prevent ComEd from raising Delivery Service Rates

• Monitor Market Value calculations and risk of CTC dropping to zero

• Ensure Decommissioning costs stay at the currently allowed $80 million/year (or that they fall)

• Following the workings of the for-profit Alliance RTO membership and it’s impact on DS

• Ensure the MSP rate do not increase DS or other rates and if they do they are offset by CTC decreases


Financial Hedging Strategy

• MV’s may rise and eventually push CTC to zero and cause the PPO to exceed the BBR rates, a call option on generation should offset losses from high MV due to this occurrence, the key is to find the MV that creates a zero value for CTC

• MV’s may fall so low that CTC’s would rise above current values which may be offset by a put option on generation. If this happens, then the PPO (Enron’s costs) will be significantly lower because MV is low and CTC increases are offset by the “in the money” put option

• Embed the option premiums into the product prices (increases product price) and take out risk premiums for regulatory risks (decrease product price) should lead to similar profit at lower risks


Illinois MarketAppendix

Marc L. UlrichFebruary 26th, 2001


Logic for Early CTC Roll-off

• Why CTC might not roll-off early...– By law, ComEd is entitled to collect CTC until December 31, 2006. – ICC (or Legislation) would have to be influenced to terminate CTC

early or ComEd could voluntarily eliminate CTC collection

• Why CTC may be influenced to roll-off early...– No collection target for CTC payments (no stranded cost estimate) – ComEd may have to eliminate PPO/CTC to get increased T&D rates– ComEd may eventually be exposed to buying in a volatile

wholesale market and selling to end-users at fixed retail rates (California problem)

• A meeting has been previously held between Government Affairs and Rates & Tariffs on this subject. Section 16-130(a)(1) requires utilities to provide information concerning the extent to which eligible retail customers switch suppliers, and the amount of transition charges paid to the incumbent utilities by those customers.


PPO Calculation

Rate Class 800 to 1,000 kW

$46.00

$48.00

$50.00

$52.00

$54.00

$56.00

$58.00

$60.00

$62.00

$64.00

50% 55% 60% 65% 70% 75% 80% 85% 90%

Load Factor

$/M

Wh

Bundled

PPOC

lass A

vera

ge L

F =

65

%


Illinois MarketSupplement

Marc L. Ulrich


Batch Pricing - Below threshold scalar

REQUIRED -- Input for Identification, CTC Calc, and Illustrations.

Utility Commonwealth EdisonRate 6>400

FALSE False = Fixed CTCIf residual CTC, answer the following:

FALSE False = Customer Specific ProfileCTC Start Date 10/01/99 Date (Example: 01/01/99)CTC End Date 12/31/05 Date (Example: 01/01/99)Shopping Credit Adder $/MWh

FALSE False = No Shopping Credit Cap

For Graphs (No Calc) Stan. Offer Direct AccessTypical kWh Dollars 3,000$ 750$ Typical kW Dollars 1,500$ 600$

OPTIONAL --- Use to Quick Fill the Monthly Grid

Standard Offer Direct Access Offer from Bid fromkWh $ kW $ kWh $ kW $ Mid Mid

1999 1.000 1.000 1.000 1.000 1.003 0.998 2000 1.000 1.000 0.934 1.000 1.003 0.996 2001 1.000 1.000 0.859 1.000 1.006 0.993 2002 1.000 1.000 1.059 1.000 1.006 0.994 2003 1.000 1.000 0.969 1.000 1.006 0.994 2004 1.000 1.000 1.047 1.000 1.006 0.994 2005 1.000 1.000 1.001 1.000 1.007 0.992 2006 1.000 1.000 - 1.000 1.060 0.936 2007 1.000 1.000 - 1.000 1.000 1.000 2008 1.000 1.000 - 1.000 1.000 1.000 2009 1.000 1.000 - 1.000 1.000 1.000 2010 1.000 1.000 - 1.000 1.000 1.000 2011 1.000 1.000 - 1.000 1.000 1.000 2012 1.000 1.000 - 1.000 1.000 1.000 2013 1.000 1.000 - 1.000 1.000 1.000 2014 1.000 1.000 - 1.000 1.000 1.000

OPTIONAL - Direct Access Starting Rate Over-Ride

$/MWh $/MWJan 20.34 6355.27Feb 20.34 6355.27Mar 20.34 6355.27Apr 20.34 6355.27May 20.34 6355.27Jun 20.34 6355.27Jul 20.34 6355.27Aug 20.34 6355.27Sep 20.34 6355.27Oct 20.34 6355.27Nov 20.34 6355.27Dec 20.34 6355.27

Residual CTC?

Class Average Profile?

Cap Credit @ Bundled?

Direct Access

-

100

200

300

400

500

600

700

800

1 9 17

25

33

41

49

57

65

73

81

89

97

10

5

113

12

1

12

9

13

7

14

5

15

3

16

1

16

9

17

7

18

5

MonthsD

oll

ars

kWh kW

Standard Offer

-

500

1,000

1,500

2,000

2,500

3,000

3,500

1 9 17

25

33

41

49

57

65

73

81

89

97

10

5

113

12

1

12

9

13

7

14

5

15

3

16

1

16

9

17

7

18

5

Months

Do

lla

rs

kWh kW

Cust Chg/KW + Dist rate + Trans Rate

CTC

Applied to DA rates

Applied to UDC fixed


Batch Pricing - Above threshold scalar

Cust Chg/KW + Dist rateTrans (no

CTC)

Applied to DA rates

Applied to UDC fixed= HR-MF

REQUIRED -- Input for Identification, CTC Calc, and Illustrations.

Utility Commonwealth EdisonRate 6L>3000







1999 1.000 1.000 1.000 1.000 1.003 0.998 2000 0.972 0.972 1.000 1.000 1.003 0.996 2001 0.942 0.942 1.000 1.000 1.006 0.993 2002 1.000 1.000 1.000 1.000 1.006 0.994 2003 0.978 0.978 1.000 1.000 1.006 0.994 2004 1.000 1.000 1.000 1.000 1.006 0.994 2005 0.989 0.989 1.000 1.000 1.007 0.992 2006 1.000 1.000 1.000 1.000 1.060 0.936 2007 1.000 1.000 1.000 1.000 1.000 1.000 2008 1.000 1.000 1.000 1.000 1.000 1.000 2009 1.000 1.000 1.000 1.000 1.000 1.000 2010 1.000 1.000 1.000 1.000 1.000 1.000 2011 1.000 1.000 1.000 1.000 1.000 1.000 2012 1.000 1.000 1.000 1.000 1.000 1.000 2013 1.000 1.000 1.000 1.000 1.000 1.000 2014 1.000 1.000 1.000 1.000 1.000 1.000



Residual CTC?



Direct Access

-

100

200

300

400

500

600

700

800

1 9 17 25 33 41 49 57 65 73 81 89 97 105

113

121

129

137

145

153

161

169

177

185

Months

Dol

lars

kWh kW

Standard Offer

-

500

1,000

1,500

2,000

2,500

3,000

3,500

1 9 17 25 33 41 49 57 65 73 81 89 97 105

113

121

129

137

145

153

161

169

177

185

Months

Dol

lars

kWh kW


Batch Modeling

• For Large Customers (> 3,000 kW) CTC NOT EXPLICITLY MODELED– UDC Fixed (Models BBR):

• 10/1/1999 to 12/31/2014– UDC Mid (Models Standard Offer PPO = BBR - MF):

• 10/1/1999 to 12/31/2005 – Enron Mid (Models Enron Generation Delivery + DS):

• 1/1/2006 to 12/31/2014

• For Small Customers (<= 3,000 kW)CTC EXPLICITLY MODELED ON 4/15/99 COMMODITY CURVE– UDC Fixed (Models BBR):

• 10/1/1999 to 12/31/2014– UDC Mid:

• Same as UDC Fixed 10/1/1999 to 12/31/2005– Enron Mid (Models Standard Offer PPO = CTC + DS + MV):

10/1/1999 to 12/31/2014


Batch Pricing - Cash Flows

Below Threshold Cash Flows• UDC fixed = bundled rate.

• UDC mid = bundled rate (because scalars are 1). MF accounted for through CTC calculation.

• Enron mid = cash flows start at 10/1/99 and serve as a substitute to the PPO till 12/31/05 and assume physical delivery by Enron from 1/1/06.

• Cust mid = lower of above 2, resulting in choice between bundled and PPO/Enron.

• Discount can be given as a % off UDC fixed i.e. Bundled Rate .

Above Threshold Cash Flows• UDC fixed = Bundled rate.

• UDC mid = Bundled rate - MF step downs.

• Enron mid = cash flows 0 till 12/31/05, begin 1/1/06 and assume physical delivery by Enron.

• Model selects UDC mid up to 12/31/05 (i.e. PPO) and Enron thereafter.

• Discount can be given as a % off UDC fixed i.e. Bundled Rate.


Is Site above Load (KW) threshold?

Create Customer Specific Scalar

Use Class Average Based

Scalar

Illinois Power Purchase Option Structure

Threshold Levels

ComEd = 3,000 kw

Illinois Power = 100 kw

Ameren CIPS and Ameren UE (IL) = 1,000 kw

• DA (Enron) Start date = 01/01/06

• SO (UDC) End date = 12/31/05

• PPO = HR - MF; SO scalars generate UDC mid.

• Enron cash flows begin 01/01/06

• DA override rates contain T&D rate (CTC finished)

• Physical Delivery planned for 01/01/06

• DA (Enron) Start date = 10/01/99

• SO (UDC) End date = 12/31/05

• SO all set = 1, so that UDC mid = UDC fixed

• Enron cash flows begin 10/01/99

• DA override rates contain CTC and T&D rates.

• CTC scaled through DA scalars

• Physical Delivery planned for 01/01/06

Yes

No


Batch Modeling for Large CustomersREQUIRED -- Input for Identification, CTC Calc, and Illustrations.

Utility Commonwealth EdisonRate 6>3000


FALSE False = Customer Specific ProfileCTC Start Date 01/01/06 Date (Example: 01/01/99) **CTC End Date 12/31/05 Date (Example: 01/01/99)Shopping Credit Adder $/MWh



** Date of Enron Physical Delivery



1999 1.000 1.000 1.000 1.000 1.003 0.998 2000 1.000 1.000 1.000 1.000 1.003 0.996 2001 0.917 0.917 1.000 1.000 1.006 0.993 2002 1.000 1.000 1.000 1.000 1.006 0.994 2003 0.982 0.982 1.000 1.000 1.006 0.994 2004 1.000 1.000 1.000 1.000 1.006 0.994 2005 0.989 0.989 1.000 1.000 1.007 0.992 2006 1.000 1.000 0.918 0.975 1.060 0.936 2007 1.000 1.000 1.000 1.000 1.000 1.000 2008 1.000 1.000 1.000 1.000 1.000 1.000 2009 1.000 1.000 0.966 0.996 1.000 1.000 2010 1.000 1.000 1.000 1.000 1.000 1.000 2011 1.000 1.000 1.000 1.000 1.000 1.000 2012 1.000 1.000 0.972 1.002 1.000 1.000 2013 1.000 1.000 1.000 1.000 1.000 1.000 2014 1.000 1.000 1.000 1.000 1.000 1.000


$/MWh $/MWJan 3.69 3,866.10 Feb 3.69 3,866.10 Mar 3.69 3,866.10 Apr 3.69 3,866.10 May 3.69 3,866.10 Jun 3.69 3,866.10 Jul 3.69 3,866.10 Aug 3.69 3,866.10 Sep 3.69 3,866.10 Oct 3.69 3,866.10 Nov 3.69 3,866.10 Dec 3.69 3,866.10

Residual CTC?



Direct Access

-

100

200

300

400

500

600

700

800

1 9 17 25 33 41 49 57 65 73 81 89 97 105 113 121 129 137 145 153 161 169 177 185

kWh kW

Standard Offer

-

500

1,000

1,500

2,000

2,500

3,000

3,500

1 9 17 25 33 41 49 57 65 73 81 89 97 105 113 121 129 137 145 153 161 169 177 185

kWh kW

Trans

Distribution & Cust Charge

PPO=BBR-MF

Enron Deli

very A

dded


Batch Modeling for Small CustomersREQUIRED -- Input for Identification, CTC Calc, and Illustrations.

Utility Commonwealth EdisonRate >1000-3000kw_SpaceHeat







1999 1.000 1.000 1.000 1.000 1.003 0.998 2000 1.000 1.000 1.000 1.000 1.003 0.996 2001 1.000 1.000 1.098 1.000 1.006 0.993 2002 1.000 1.000 1.064 1.000 1.006 0.994 2003 1.000 1.000 0.970 1.000 1.006 0.994 2004 1.000 1.000 1.051 1.000 1.006 0.994 2005 1.000 1.000 1.003 1.000 1.007 0.992 2006 1.000 1.000 - 0.960 1.060 0.936 2007 1.000 1.000 - 1.000 1.000 1.000 2008 1.000 1.000 - 1.000 1.000 1.000 2009 1.000 1.000 - 0.990 1.000 1.000 2010 1.000 1.000 - 1.000 1.000 1.000 2011 1.000 1.000 - 1.000 1.000 1.000 2012 1.000 1.000 - 0.996 1.000 1.000 2013 1.000 1.000 - 1.000 1.000 1.000 2014 1.000 1.000 - 1.000 1.000 1.000



Residual CTC?



Direct Access

-

100

200

300

400

500

600

700

800

900

1,000

1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190

kWh kW

Standard Offer

-

500

1,000

1,500

2,000

2,500

3,000

3,500

1 10 19 28 37 46 55 64 73 82 91 100

109

118

127

136

145

154

163

172

181

190

Months

Dol

lars

kWh kW

CTC

T&D and Cust. Charge

BBR

PPO (on 4/15/1999)


IL Pricing Problems

1. Current method shows false position in book2. Current method doesn’t model BBR, PPO, and Enron

Delivery Simultaneously3. Transition dates are being used to start/stop cash flows

and do not match reality4. Pricing doesn’t determine when to serve5. Large customer pricing doesn’t have CTC estimates

and thus cannot have Enron delivery before CTC roll off6. CTC calculated off 4/15/99 curve for small customers7. Energy charges ($/kWh) are converted to demand

($/kW) charge by assumption (class LF) to combine T&D for small customers and scaled by same kW scalar

8. Individual scalars for each large customer deal9. 2 lines/site in batch10. Different methods for large and small customers11. Pricing is still in Batch99


Commodity Desk Issue

• For sites below 3,000 kW in ComEd, because PPO is modeled in the Enron cash flows it appears that we are physically delivering before 1/1/2006

• For sites above 3,000 kW in ComEd, there is no Enron Mid line before 1/1/2006

Current Method

$0

$20

$40

$60

$80

$/M

Wh

UDC Fixed UDC Mid Enron Mid

UDC Fixed $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60

UDC Mid

Enron Mid $75 $64 $60 $58 $57 $58 $58 $59 $59 $60 $61 $61 $62 $62

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014


Commodity Desk Issue

• It may be possible to change VB code in Batch to move Enron cash flows before DA to UDC Mid for small customers

Proposed Method

$0

$20

$40

$60

$80

$/M

Wh

UDC Fixed UDC Mid Enron Mid

UDC Fixed $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60 $60

UDC Mid $75 $64 $60 $58 $57

Enron Mid $58 $58 $59 $59 $60 $61 $61 $62 $62

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014


Illinois Option Pricing• All non-residential customers have direct access. These

customers can choose one of three options…

– Benchmark Bundled Rate (BBR) - bundled tariff

– Power Purchase Option (PPO) - unbundled, discounted

– Alternative Retail Electric Supplier (ARES)

• PPO is calculated as…PPO = DS + CTC + MV

• Transition Charges are calculated as…CTC = BBR - DS - MV - MF

CTC = Customer Transition ChargeBBR = Bundled Base Rate (UDC Fixed)DS = Delivery Service (T&D) (From Tariff Scalar Files)MV = Market Value of Generation (From Cash Flow's tab

Swap Mid)MF = Mitigation Factor (Mandatory Discount)


Illinois Option Pricing

BBR = UDC Fixed

PPO = UDC Mid Enron Mid

Time2005

$



BBR = UDC Fixed

PPO = UDC Mid Enron Mid

Time2005

$

Enron Revenue ( = BBR – X%)

X%



$/MWh

Enron Cost to Server

BBR

PPO

BBR–DS–MF


$/MWh

MVBBR–DS

Enron Costs ( Without Hedge)

Recall: PPO = DS + CTC + MVCTC = BBR - DS - MV - MF



$/MWh

Enron Cost to Server

BBR

PPO

BBR–DS–MF


$/MWh

MVBBR–DS

Enron Costs ( Without Hedge)

Buy Call Option here

Sell Call Option here

Enron Costs ( With Hedge)


Pricing and Curve Selection

4/20/01 EES INTERNAL 3

Price Curves

Transition & Choice ChoiceRegulated

CustomerMid = Min (UDC, ENE)

UDCMid (T, D, CTC, Gen)

ENEMid (T, D, CTC, Gen)

$.06/ Kwh

1 2 3 4 5 6 70

Example Financial Product Derivation:NPV-UDCFixed = $60 / MWhNPV-Customeroffer = $55 / MWhNotional Offer to Customer is 9% discount from tariff (baseline)

UDCFixed

(baseline)

Scaler =.95

Direct Access = T+D+CTC+Spot

Standard Offer = T+D+CTC+G*

* Fuel, Shopping Credit, Spot


Illinois MarketMarc L. UlrichGuy Sharfman

Jay Lewis


ComEd Proposals

• ComEd sent a letter to the Illinois Commerce Commission (ICC) proposing…

– Large Users (400+ kW)• Phase out existing PPO and BBR after 2004• Pass-through day-ahead real-time beginning 2005 as

only ComEd power rate• Restrict PPO to CTC>0

– Mass Market (400– kW)• Avoid California-style rate shock• Provide specific fixed price service between 2005-2008 • Perhaps specific fixed price will have annual price

escalation


ComEd Existing Book

Regulated Generation (without JCP&SAKs)UtilityName 2001 2002 2003 2004 2005 TotalAmeren CIPS (128,764) (179,926) (170,753) (161,695) (97,081) (738,218)Ameren Union Electric (IL) (5,989) (12,762) (12,012) (11,417) (8,003) (50,183)CILCO (2,726) (3,737) (3,431) (3,250) (3,053) (16,198)ComEd (625,498) (822,307) (761,533) (620,266) (411,291) (3,240,895)Illinois Power (IL) (167,328) (240,056) (227,899) (215,898) (144,832) (996,014)MidAmerican (IL) (1,147) (1,440) (1,317) (1,248) (1,172) (6,323)Grand Total (931,453) (1,260,228) (1,176,944) (1,013,774) (665,432) (5,047,832)

Book Impact of Eliminating ComEd PPO…Assume $3 difference 2001 2002 2003 2004 2005between Enron Delivery & PPO ($1,876,494.67) ($2,466,919.78) ($2,284,599.02) ($1,860,797.44) ($1,233,873.02)


Possible Responses to ComEd Proposal

• We encourage discussions of improving the wholesale market and services with an eye toward avoiding CA like events.

• Solutions need to be ones that market participants can manage risk. Solutions that allow us to hedge risk.

1. Establishment of RTO/ISO with liquid wholesale services2. Zero CTCs or flat CTCs at some rate3. Real-Time-Pricing (RTP) based on a liquid trading hub4. PPO determined on Cinergy prices updated more frequently

(weekly, daily)

• We also support the ability of buying this services through wholesale agreements with ComEd



• An example of a wholesale agreement is the Full Requirements Profile Service (FRP) contract

• FRP would allow Enron to buy all energy at PPO rates through a wholesale transaction

• The points we need to ensure are…– We want an FRP contract until the end of PPO (12/2004)– We want eligibility of customer load that have zero value

CTCs– We want to add or subtract any amount of customers and

their corresponding load at any time (or once a year) to the contract

– Transmission and Ancillary are charged in bulk– All in commodity price (load shaping)– We want a negotiation clause if an RTO/PPO is created but not an

out clause if one exists



• We would be happy to provide default service at the right price, however, the right price is probably not one that will be amenable to the ICC

• We also prefer not to open legislation HB 362

• We probably prefer to avoid ICC hearings also

• For all this we would and should support ComEd’s proposal

Internal and Confidential to EESMay 16, 20011 Illinois Market Marc L. Ulrich.

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Transcript of Internal and Confidential to EESMay 16, 20011 Illinois Market Marc L. Ulrich.