Request for Information
The Connecticut Light and Power Company / The United Illuminating Company
Detailed Information Request
Class I Renewable Projects
The Standard Electricity Purchase Agreement (“EPA”) that is included as
Attachment B to this request for information is a Department of Public Utility
Control (“DPUC”) approved standard contract, which is intended to remain
unchanged. As noted at the bottom of Page 1 of the EPA, if a generating entity
believes that its “different circumstances” require an amendment to the EPA, the
generating entity must demonstrate such circumstances, propose an amendment,
and substantiate the need for the proposed amendment to the satisfaction of the
Utilities and the Clean Energy Fund. Any amendment satisfactory to the Utilities
and the Clean Energy Fund will be proposed to the DPUC for approval. If an
amendment is not satisfactory to the Utilities, a generating entity may seek a
DPUC ruling that the amendment is necessary and appropriate, but the Utilities
will not consider the project further until the DPUC has ruled on the amendment,
which may result in the project being considered in the next following solicitation.
The EPA allows for two scenarios: Scenario A and Scenario B, as described
below. In the request for information that follows, scenario-specific information is
noted in bold italics. Please indicate which of the two Scenarios applies to your
project by marking X on the appropriate line below.
_____ Scenario A – Project not yet built at time of contract execution
_____ Scenario B – Project built and in-service after July 1, 2003, but prior to
Where applicable, the section in the EPA that uses the requested information is noted in
1) Project description including location:
a) Legal Name of Company requesting contract (Preamble) ____________________
b) Name of Project/Facility: ________________________________________________
c) Address of Facility: (First Whereas clause)__________________________________
d) Notice Contact Information: (§6.1) _________________________________________
e) [A] Original Scheduled Operation Date (§3.2)______________________________
[B] Scheduled Initial Purchase Date under the EPA (§3.2)____________________
[B] Earliest Initial Purchase Date (§A-1.25) ________________________________
f) Evidence of CT Class I eligibility – Please clearly label and attach.
The Class I Renewable Procurement Process Document provides that the
EDCs’ evaluation of projects include evidence of CT Class I eligibility. In
order to provide evidence of CT Class I eligibility, the process in support of
Regulations of Connecticut State Agencies §16-245a-2 provides that
potentially eligible projects that are not yet operational must petition the
DPUC for a declaratory ruling certifying that the project qualifies as a
Connecticut Class I renewable energy resource. Please provide evidence of
the intention to obtain a satisfactory declaratory ruling as a CT Class I
renewable energy resource from the DPUC.
If your project includes a Combined Cycle / secondary component, please
provide evidence that the Combined Cycle / secondary component of your
project will be able to obtain a satisfactory declaratory ruling as a CT Class I
renewable energy resource from the DPUC.
g) Contract Rate Products: ___________% of Products to be delivered to Utility, up to
______kWh per hour of Delivered Products (§3.5)
A fixed percentage of Energy, net of station use, along with any and all other
Products associated with such Energy will be sold to the contracting Utility.
The EPA does NOT allow a fixed amount of Products (e.g., the first ___
MWh of energy in any given hour) to be sold to the contracting Utility. The
EPA does provide for the Utility to pay Seller for any Additional Products at
the same rate that Utility is paid for the Energy component of such Additional
Products by ISO-NE.
Appendix A of the EPA, Section A-1 Definitions states that “Delivered
Products” shall mean Energy, net of station use, of the Facility along with
any and all other Products associated with such Energy delivered to
Utility by the Seller, determined by a percentage of Facility’s capability as
specified in Section 3.5 of the EPA.
Also, ISO-NE Market Rule 1, Manual M-28, Section 220.127.116.11 (e) states
that the registration letter for generating assets shall include a statement
identifying all the Generator Asset Owners by percentage as of the
Desired Implementation Date.
The kWh per hour of Delivered Products will determine the “size” of a project
being considered under the 100 MW Class I Renewable Procurement
h) Evidence of pre-certification by the CCEF as a Fuel Cell Principally Manufactured in
CT (if applicable) – Please provide as Exhibit B1 to Appendix B of Attachment B)
i) If Facility is a Fuel Cell Principally Manufactured in CT: ______% of RECs attributable
to Facility to be delivered to Utility. (§3.5)
j) Description of Facility including maps, site description and detailed description of
generating plant and equipment. Please submit in the form of Appendix B to
Attachment B. Please clearly label and attach.
Appendix B to Attachment B, Description of Facility requests information on
“Seller Required Approvals.” At a minimum, please include an indication of
whether you intend to submit either A or B:
A. FERC market-based rate authorization for Seller to sell Products in
accordance with the EPA
B. Specific FERC approval of the EPA
Appendix B to Attachment B, Description of Facility also requests Criteria for
Declaring that the In-Service Date has occurred.
o Please provide such criteria.
2) Interconnection and delivery information
a) Name of Interconnecting Utility (§2.2) ________________________________
b) Point of Interconnection ___________________________________________
c) Voltage level of Interconnection _____________________________________
d) Evidence of executed Interconnection Agreement or evidence of significant progress
toward execution of Interconnection Agreement. Please clearly label and attach.
e) Delivery Point (If delivery is to ISO-NE PTF, please specify node): _______________
Attachment B, Section A-1.11 defines the “Delivery Point” as the point where
Products transmitted by the Seller will be delivered to the Utility. The
Delivery Point shall be a specific point on the ISO-NE PTF where Seller shall
transmit its Products to the Utility, except for small Connecticut projects with
a capacity value such that they are recognized by ISO-NE rules, as currently
in effect and as amended from time to time, as a “load reducer.” The
Delivery Point for these small Connecticut projects shall be the point of
interconnection to the purchasing Utility’s distribution system.
f) If the project has a capacity rating between 1 MW and 5 MWs, please indicate your
preference of treatment by ISO-NE as a “load reducer” or as a settlement only generator.
ISO-NE Operating Procedure 14 states that “A unit must be considered a
less than one (1) MW unit if either its summer or winter capability is less
than one (1) MW, or its rating in any month (for a daily cycle hydro or wind
unit) is less than one (1) MW.” Please note that there is a 1 MW minimum
aggregated project threshold pursuant to conditions established by the
g) Describe how Products will move from Point of Interconnection to Delivery Point –
Please note that Seller is responsible for all applicable FERC-approved charges
associated with transmission and distribution interconnection, service and
delivery charges, including all related ISO-NE administrative fees, EXCEPT FOR
small Connecticut projects that have a capacity value and that satisfy any and all
other applicable criteria such that they are recognized by ISO-NE rules, as
currently in effect and as amended from time to time, as a load reducer. These
load reducer projects are not delivering power to the PTF and shall pay energy
delivery costs only to their Delivery Point.
3) Capacity and energy deliveries
a) Estimated annual capacity (MW) and energy (MWh) deliveries
Please provide this information in the form of Exhibit A-1 to this Attachment A.
b) Please indicate if you submitted a Show of Interest to ISO-NE for a Forward Capacity
Auction (“FCA”). If you did submit a Show of Interest, please indicate the associated
Capacity Commitment Period(s). If you did not submit a Show of Interest for a FCA, (a)
please indicate your intention to submit a Show of Interest for the next FCA, and (b)
please indicate your intention to participate in reconfiguration auctions for FCA capacity
4) Fuel source and supplier information (if applicable)
a) Primary fuel source (§3.1)____________________________________________
b) Fuel supplier information (if applicable)____________________________________
5) Requested price for power generated by the project
a) “Specified pricing option” selected from Appendix C of Attachment
(PLEASE NOTE: Bidders may choose Pricing Option 6a as filed with the CDPUC by
CCEF on February 29, 2008. This Pricing Option 6a was approved subsequent to the
approved EPA included in Attachment B. Per the CDPUC’s letter of March 3, 2008,
“Any projects selecting Pricing Option 6a should also select an alternate Pricing Option
for use in the unanticipated event that the Department determines through further
evidence taken in the Round 3 docket that Pricing Option 6a is not in the public
b) All information for the selected pricing option in the form of Appendix C of Attachment B.
Please clearly label and attach.
Terms of Specified Pricing Options are as stated on the pricing option
template. No modifications or adjustments to stated terms are allowed in
Pricing Options 1 – 6a. For Alternative Pricing Option, see 5) c) of
If you have chosen Pricing Option 2, please specify the applicable price
index, initial component values (i.e., Initial Wholesale Electricity Price and
Initial Value of Price Index), and the fixed renewable adder.
If you have chosen Pricing Option 3, please specify the applicable fuel price
index, weighting factors, initial component values, and the fixed renewable
If you have proposed Pricing Option 5, please specify the tariff rate
components, the specific pipeline and Local Gas Distribution Company, and
the specific tariff(s) to be used. Please note that if Seller does not incur, or it
receives rebates of, LDC charges, the pricing component for such LDC
charge(s) in Seller’s electricity contract will be zero.
If you have chosen Pricing Option 6 or 6a, please specify the Local Gas
Distribution Company and its specific tariff to be used. Please note that if
Seller does not incur, or it receives rebates of, LDC charges, the pricing
component for such LDC charge(s) in Seller’s electricity contract will be
The Wholesale Market Electricity Cost must be based on the LMP at the
Delivery Point. For projects that are not designated as load reducers, the
node indicated in the Pricing Option should be consistent with the ISO-NE
PTF node (i.e., Delivery Point) indicated in Section 2) e) of Attachment A.
For projects designated as load reducer projects, the Wholesale Market
Electricity Cost should be consistent with the applicable ISO-NE zonal
If you have chosen Pricing Option 5, 6, or 6a, please note that the projected heat
rate specified in your proposal may be either an average projected heat rate for the
contract term or a table of annual projected heat rates, and should include the effect
of all generation that will be produced at the contract rate. These projected heat
rate values will be fixed for the life of the contract, not subject to change, and
utilized for calculation of the Contract Payment Rate as well as for the
Companies’ evaluation of your project. Please note that heat rate values should
be stated in MMBtu/kWh. Please provide this information in the form of Exhibit A-1.
If you have chosen Pricing Option 5, 6, or 6a, please note that the Contract Payment
Rate will be based on a conversion rate of 1 Mcf = 1.025 MMBtu.
Pricing Options 5, 6, and 6a are only available to Facilities with Natural Gas
as the Primary Fuel Source. If you choose one of these Pricing Options,
please specify if your gas supply arrangement will allow your project to be
available to operate during times of electric system peak demand.
c) If in item 5a you have selected one of the first four specified pricing options from
Appendix C of Attachment B and wish to propose an alternative option in addition to
the specified pricing option, please provide a draft attachment to the contract that
clearly describes how the alternative option will work and a written justification
explaining why the alternative option is preferable for utility customers. Please clearly
label and attach. Please note that the pricing provided for the specified option will be
used for bid evaluation.
6) Requested term of the contract (§5.1)_____________________________
7) Security –
Please note that in its July 25, 2005 Letter accepting compliance filings in Docket
No. 03-07-17, the Department of Public Utility Control (the “Department” or
“DPUC”) stated that the standard contracts are required to provide as follows:
The contract must provide that the supplier maintain, at all times during the
operation of the contract, a surety bond, or other acceptable similar security in
the amount of 2.5% of the project cost. The proceeds of said security shall be
applied toward paying any compensatory damages owed to the Companies
resulting from a breach of the contract. The bond is not intended to be in lieu of
any contractual compensatory damages. Rather, the Companies will be entitled
to seek any remaining compensatory damages above any amount recovered
through security provided by the supplier. In addition to providing for
performance assurance security, the standard contacts must provide for the non-
rescindable forward transfer of renewable energy and capacity credits.
Please see Appendix D to Attachment B for additional information regarding the required
security. Please provide specific information, including draft attachments to the contract
(e.g., draft form of surety bond and draft commitment letter from an acceptable,
creditworthy surety), that details how you plan to satisfy these requirements. The
Companies will review the surety bond and surety as part of the overall project review.
8) Information needed for financial analysis –
The following information is required for an accounting review of your project. Please
provide as much of this information as possible. For any information not supplied
regarding your project, the Companies will formulate assumptions and prepare estimates
in order to complete the analysis required by accounting standards. However, these
estimates and assumptions may be different than data that you would have developed
and could have an unfavorable effect on the accounting opinions concerning your
Legal structure of the entity:
organization chart showing relationship between associated parties
description of parties involved: e.g., equity holders, debt holders, construction
contractors, suppliers, guarantors and any party that earns management fees
description of party with decision-making authority (for approval of day to day
operating decisions, annual budget approvals, veto rights, financing, etc.)
legal order of priority of distributions and claims in the event that cash flows are
insufficient to cover obligations: owner, lender, utility company, and other parties
explanation of overlaps or influential relationships among parties (including any
requirement to obtain approval to transfer or encumber interest in the entity)
Detailed list of project costs and sources of funds including proposed capitalization
structure: terms, dollar amounts and holders of owner equity (by class), other owner
financing, third party senior debt, and third party subordinated debt.
Projected opening GAAP balance sheet for the entity after construction and
Base case project projections (line item budget of revenues and expenses) for as
many years as the term of the contract on a cash basis (i.e., cash flow statements for
the term of the contract):
provide all significant revenue assumptions and calculations, including contract
pricing and quantities to be delivered and % to be sold to utilities vs. other
parties. Include market prices by component (where applicable, energy prices
and quantities, REC prices and quantities, and capacity). Discuss how prices
and/or quantities were derived, components of the pricing buildup such as gas or
O&M indexers, technological risk of not operating at target capacity, and
seasonality. Please explain any unusual variances from year to year. Explain
nature and amount of property tax abatements or IRS tax credits, if eligible.
provide all significant cost assumptions: prices of fuel, cost escalators, annual
capital expenditures, changes in assumptions over the years, fees, breakout of
fixed and variable costs
in addition to the base case project projections, provide alternative assumptions
and projections for project capacity and expected % likelihood of each totaling
100%. Check: the base case should represent the weighted average outcome,
and the weighted average of all outcomes at discounted present value should
also equal the cost or fair value of the plant (please provide the fair value)
Please provide the expected economic life of the plant and plans
(operating/sale/retirement) for the facility after the contract expires, net asset
retirement cost obligations and expected terminal value.
Provide copies or proposed terms of all significant agreements/documents: loan agreements
(draft or detailed listing of expected financing terms including interest rates), management fee
contracts (term, cancellation provisions, fee structure, decision-making rights conveyed),
commitments and guarantees on debt or construction contracts etc., CCEF or other expected
financial support expected, any non-standard terms expected in interconnection agreement,
supply contracts, business plans, marketing documents and applications for grants or loans.
EXHIBIT A-1 TO ATTACHMENT A
Your input to this schedule is essential in order to establish the estimated total MWs of
Capacity and MWhs of Energy to be delivered to the Companies at the Delivery Point.
The estimated MWhs of Energy should be the total estimated annual MWhs expected to
be paid at the Contract Payment Rate.
Specified Pricing Options 5, 6, and 6a are formula-driven and include a proxy fuel cost
derived from a specified tariff; they are not intended to pay your project’s actual fuel
invoices. In addition, these Specified Options are not intended to track the actual
experienced heat rate of your facility. Please provide projected heat rate values in the
spaces provided on this Exhibit A-1 to Attachment A. These values may be either an
average projected heat rate for the contract term or a table of annual projected heat
rates, and should include the effect of all generation that will be produced at the contract
rate. These values will be fixed for the life of the contract, not subject to change,
and utilized for calculation of the Contract Payment Rate as well as for the
Companies’ evaluation of your project.
Please note that the Contract Payment Rate will be based on a conversion rate of 1
Mcf = 1.025 MMBtu.
Exhibit A-1 to Attachment A
Project Name: ______________________________________
This schedule must include the estimated total MWs of Capacity and MWhs of Energy to be
delivered to the Companies at the Delivery Point. The estimated MWhs of Energy should be
the total estimated annual MWhs expected to be paid at the Contract Payment Rate.
Estimated Estimated Net Summer
Total Estimated Capacity Estimated Net Total Estimated
Project Station Delivered to Capacity Annual Energy Projected
From Capacity Service Utility Delivered to Utility Deliveries Heat Rate
(Note 1) To (Note 2) Load (Oct - May) (Jun - Sep) (Note 3) (Notes 4 & 5)
(MMM / YY) (MMM / YY) (MW) (MW) (MW) (MW) (MWhs)
Jul-09 Jun-10 10 1 9 9 67,802 7,600
Note 1: The information provided should begin with the first month of the In-Service Date.
Note 2: "Estimated Total Project Capacity" may change over time due to stack degrades and restacking.
Note 3: "Total Estimated Annual Energy Deliveries" should be a realistic estimate of total annual net
energy to be delivered to the Companies (with consideration given to maintenance outages or load
reductions, such as those caused by ambient temperature or other operating conditions).
Note 4: This column is only necessary for Projects selecting Specified Pricing Options 5, 6, or 6a.
Note 5: "Projected Heat Rate" should include the effect of all generation that will be produced at the
contract rate and will be used for Contract Payment Rate calculation.