September 8, 2004
Confirmation Agreement – Unit Contingent Energy and Unit Identified (RA) Products
When fully executed, this confirmation agreement (“Confirmation Agreement”) shall document the negotiated transaction (the “Transaction”) between ______(“Seller”) and Pacific Gas & Electric Company (PG&E or “Buyer”), together the “Parties”, in which the Seller agrees to provide to PG&E the right to call on energy, capacity and/or ancillary services specified herein. This Transaction is governed by the [Western Systems Power Pool (“WSPP”) Agreement or Edison Electric Institute (“EEI”) Master Purchase & Sale Agreement], and any amendments entered into between the Parties effective ______(“Master Agreement”). The definitions and provisions contained in the Master Agreement shall apply to this Confirmation Agreement; provided that, to the extent that this Confirmation Agreement is inconsistent with any provision of the Master Agreement, this Confirmation Agreement shall govern the rights and obligations of the Parties hereunder.
1. Seller: ______
2. Spark Spread product:
Unit(s): Specify ______
A Unit(s) spark spread is defined as an energy call option from a specific generating unit(s) or a MW subset of a portfolio of units. All products are energy unless resource adequacy designation is selected.
3. Contract Quantity: ______MW
4. Delivery Term: The start date for the Delivery Term can be as early as July 1, 2005, but no later than January 1, 2006. The end date can be no earlier than December 31, 2007, but no later than December 31, 2008.
Start date: ______; End date: ______.
5. Operating Flexibility – Subject to operating constraints contained herein (check one):
[ ] (A) Day-ahead, in either 8, 16 or 24 hour blocks; same size for all hours called on in a day. Buyer can elect 0, 8, 16 or 24-hour dispatch for any given day, subject to the definitions below. “8 hours” is defined as Hour Ending (“HE”) 13-20; “16 hours” is defined as HE7-22. The 8-hour product can be called for delivery on Monday –Friday, excluding NERC holidays. The 16 and 24-hour products can be called for any day including NERC holidays.
[ ] (A2) Day-ahead, in either 8, 16 or 24 hour blocks; same size for all hours called upon in a day . Buyer can elect any 0, 8, 16 or 24 consecutive hour dispatch on any given day.
[ ] (B) Day-ahead, and Buyer is able to select any combination of hours and hourly rates of delivery.
[ ] (C) Day-ahead, except that for any given day, Buyer’s call on energy must be for continuous hours and at a constant rate of delivery each hour,
[ ] (D) Hour-ahead, and Buyer is able to select any combination of hours and hourly rate of delivery.
[ ] (E) Hour-ahead and Buyer’s call on energy must be for continuous hours and at constant rate of delivery each hour. Adjustments to the initial hour-ahead calls are allowed so long as continuous hour and constant rate of delivery criteria continue to be satisfied.
[ ] (F) Day-ahead, except that for any given day, Buyer’s call on energy must be for continuous hours and at a constant rate of delivery each hour, plus for 3 calendar days per month, Hour-ahead call on energy for continuous hours and at constant rate of delivery each hour. Adjustments to the initial hour-ahead calls are allowed so long as continuous hour and constant rate of delivery criteria continue to be satisfied.
6. Energy Price: The price paid for the energy produced (“Energy Price”) must be in the form of a heat rate multiplied by a gas price index. The heat rate can be a single value, as specified below, or, alternatively, can be specified as a heat rate curve. (Seller to provide heat rate curve, with average MMBTu/MWh provided for minimum and maximum output levels and ten distinct operational levels between minimum and maximum.)
______MMBtu/MWh (“Heat Rate”) x Platt’s Gas Daily Index. For the purposes of thisConfirmation Agreement, the Platt’s Gas Daily Index” shall mean that price, expressed in $/MMBtu as published by Platt’s Gas Daily (in the internet publication currently accessed through www.platts.com) in the table entitled “Daily price survey” under the heading “Midpoint” for: “PG&E city-gate” for the date of delivery.
A variable charge in $/MWh (“Variable Charge”) can also be added to the product of the Heat Rate multiplied by the gas price index to determine the full price Seller will pay Buyer for energy. The Variable Charge is:
2005: ______$/MWh
2006: ______$/MWh
2007: ______$/MWh
2008: ______$/MWh
7. Fixed Payment:
2005: ______$/KW-yr
2006: ______$/KW-yr
2007: ______$/KW-yr
2008: ______$/KW-yr
All Fixed Payments are allocated monthly per the schedule in Attachment 1. If the term of the Confirmation Agreement includes partial years, all the Fixed Payments above shall reflect the annual cost for such partial year. Evaluation for such partial years shall be determined based on the relative value of the monthly allocation factors applicable to such partial year to the total year.
8. Delivery Point.
8.1 The delivery point shall be NP-15 or within NP-15 as indicated below (“Delivery Point”). As an alternative, Seller can specify a particular substation within the current NP-15 zone. In the future, this may result in different prices if the California Independent System Operator (“CAISO”) or its successor creates alternate zones, nodes or trading hubs per Section 8.2.
Please indicate whether Delivery Point is:
[ ] NP-15; or
[ ] point of interconnection (specific substation) within the current NP-15 zone and within the CAISO controlled grid: name of substation ______.
8.2 If the current NP-15 zone (or other zonal delivery point(s)) are replaced with an alternate zone(s), node(s) or trading hub(s), as established by the CAISO or successor organization, then, Buyer and Seller shall seek to agree on a new Delivery Point which maintains the balance of benefits and burdens under this Confirmation Agreement for delivery within the current NP-15 zone.
8.3 If the current NP-15 zone (or other zonal delivery point(s)) is replaced with an alternate zone(s), node(s) or trading hub(s), as established by the CAISO or successor organization, and if Buyer and Seller do not agree on a new, more specifically described Delivery Point at or among such successor zones, nodes or trading hubs, the Delivery Point shall be the new NP-15 trading hub (if any). Alternatively, if the CAISO (or successor organization) replaces the single NP-15 zonal delivery point with multiple nodal delivery points, then, each time such a change is made by the CAISO during the remaining term of the Confirmation Agreement, the Delivery Point for settlement purposes shall be a delivery point that best approximates the location and characteristics of the current NP-15 zonal delivery points. This will be specifically the average of all the CAISO load nodal points that are located within the current NP-15 zone, weighted by load, such that each megawatt-hour delivered by the Unit(s) shall be deemed delivered, pro rata, to every such CAISO load nodal point that is located within the current NP-15 zone.
9. Ancillary Services (“A/S”): Seller may offer the following A/S products as defined by the CAISO: spinning reserves (“Spin”) and non-spinning reserves (Non-spin”). All offered A/S must be within the CAISO control area. The combined size of energy and A/S products that can be called by PG&E for any hour is based on the Contract Quantity. The service, size and price (if not already included in the fixed or variable components) for each offered A/S is per the following:
Spin / Non-SpinMax Size (MWs) / Price ($/kW-yr) / Max Size (MWs) / Price ($/kW-yr)
2005
2006
2007
2008
2009
Note: A/S products offered by Seller shall be consistent with the scheduling flexibility specified in Section 5. Any energy dispatched by the CAISO with respect to the Spin and Non-spin A/S in this Section shall be settled directly between CAISO and Seller. The $/kw-yr price shown above are allocated monthly per the schedule in Attachment 1. If the term of the Confirmation Agreement includes partial years, the A/S payments set forth above in this Section shall reflect the cost for such partial year, and such payments shall be allocated monthly based on the relative value of the partial year’s monthly allocation factors
10. Resource Adequacy Requirements: Seller shall indicate whether it is willing to identify Unit(s) or a specific combination of Units for the purposes of satisfying Resource Adequacy (“RA”) requirements. The California Public Utilities Commission (“CPUC”) or CAISO may, during the term of this Confirmation Agreement, put into place an RA requirement whereby eligibility to count MW toward the RA requirement may be determined by identifying specific Unit(s) or combination of Unit(s) . This RA requirement does not imply that the energy to serve this Confirmation Agreement must physically come from the same Unit(s) or combination of Units that meet the RA requirements. However, the Unit(s) or combination of Units identified here will provide capacity towards meeting the Buyer’s RA requirements. In addition, it is expected that at some future time the CAISO or successor organization will create the right in itself to dispatch the identified Unit(s) or combination of Units. This may also impose a requirement for Seller to bid the identified Unit(s) or combination of Units into the CAISO Day-Ahead markets and, if the bid were not accepted and the identified Unit(s) or combination of Units not scheduled, the identified Unit(s) or combination of Units would be subject to residual unit commitment (“RUC”).
[ ] Yes, willing to identify Unit(s) or a specific combination of Units, provide any necessary certification and be bound by any CAISO or successor organization imposed obligations on Seller that may follow: (list units with associated MW’s) ______
[ ] No, not willing to identify Unit(s) or a specific combination of Units.
If yes, provide the price below for so identifying Unit(s) or a specific combination of Units, providing any necessary certification and agreeing to be identified Unit(s) or combination of Units (“Certification Price”).
Prior to any CAISO dispatch right requirement being in place, the only RA requirement that may precede it is that these identified Unit(s) or combination of Units are uniquely defined for the Buyer (MW’s from identified units not double counted anywhere for RA purposes) within this Confirmation Agreement The Certification Price is payable by the Buyer only if and when the above described RA requirements and/or Seller obligations are created by the CAISO as described above. If it becomes applicable, the Certification Price shall be allocated monthly per the schedule in Attachment 1. If the term of the Confirmation Agreement includes partial years, the Certification Price will be in proportion to the same monthly allocations set forth in Attachment 1.
2005: ______$/KW-yr
2006: ______$/KW-yr
2007: ______$/KW-yr
2008: ______$/KW-yr
Should the CPUC or CAISO, during the term of this Confirmation Agreement, create an RA requirement utilizing capacity tagging (such as, but not limited to, distinct Installed Capacity (“ICAP”) products), Seller shall provide Buyer with the capacity tags for the term of the Confirmation Agreement, for the MW size specified in Section 3. Seller shall take all actions and execute all documents necessary to affect the use of the capacity tags for the sole benefit of Buyer's RA requirements.
11. Minimum Schedule: When scheduled , the minimum amount that can be called is _____ MW
12. Ramp rate: _____ MW/minute (may be a range of values as set forth in a ramp-rate schedule attached by Seller).
13. Minimum Downtime after each shutdown: ____ hours.
14. Minimum Uptime after each start-up: _____ hours.
15. Start-ups: The cost per start-up is $ ______. The maximum number of start-ups per year is _____. In the event that Buyer exceeds the number of start-ups, the cost for each additional startup is $______. A start is defined as moving the schedule of a designated unit from zero load.
16. Allowance for Planned Maintenance: Maximum number of days per calendar year Seller may schedule for maintenance.
Maximum Planned Maintenance days:
2005: ______
2006: ______
2007: ______
2008: ______
Seller shall provide the Planned Maintenance schedule for the next following calendar year on or before October 1 of the current calendar year. No Planned Maintenance is permitted in January, June-October or December.
17. Forced Outage Allowance: Seller shall notify Buyer of any Forced Outage within 10 minutes of the Unit being offline, and shall provide an estimate of the expected outage duration within 1 hour thereafter. If the Forced Outage duration is greater than 24 hours, the Seller will update the Buyer daily with any revised estimates regarding the Unit’s(s’) return to service. Subject to the non-performance penalties specified in Section 20, a Forced Outage shall excuse Seller’s obligation to deliver energy and A/S.
18. Substitute Energy: So long as it is not a “Prolonged Outage” as defined in Section 19, Seller may deliver to the Delivery Point energy from an alternative source as defined herein (“Substitute Energy”) if the Seller has notified Buyer that: a) a Unit(s) is unavailable, but Seller will deliver Substitute Energy; or b) Substitute Energy will be provided for all hours scheduled by Buyer for that particular day. In a) or b) above, Forced Outage hours shall not be affected. Such notification and energy substitution must be consistent with Western Electricity Coordinating Council (“WECC”) and CAISO scheduling protocols. If the Unit(s) is unavailable, Seller may only provide Substitute Energy for up to 168 consecutive hours per identified outage and no more than 672 hours per 365-day period.