Governors’ Infrastructure Initiative Update
NEPOOL Transmission Committee
June 20, 2014

Overview

• Introduction
• Transmission Infrastructure Tariff Charges
• Gas Pipeline for Electric Power System Reliability Infrastructure Tariff Charges
• Timeline

Introduction

• The states will seek NEPOOL support for two new schedules to support the Governors’ Infrastructure Initiative – one related to transmission, one to gas pipeline constraints causing power system challenges
• Primary purpose of these schedules is for the ISO-NE Tariff to be the vehicle for billing and collection in support of transmission and gas pipeline infrastructure to advance power system reliability
  • Regional electric power system solutions funded by regional electric power system customers
• The schedules will not include all details or processes related to the initiative
• Schedules are intended to be for this one-time initiative only
  • not generic or for future use
• This is a preliminary proposal. States are working out the details; no agreement has been finalized.

Transmission

Transmission Costs

• States intend to select a project or projects through an RFP process for no and/or low carbon resources administered by states and EDCs as appropriate
• The RFP process will not be in the ISO-NE tariff and is not part of today’s discussion
  • When the states are ready to release the RFP instrument, more information will become available to those interested in bidding
• The RFP process will not be concluded before this schedule is filed with FERC
  • Winners will be selected through the RFP process
  • Costs will be identified concurrent with project selection
• Transmission costs will be shared regionally through a new tariff schedule
• Energy costs will be borne directly by the EDCs purchasing the power.

ISO-NE Tariff Changes

• New Tariff schedule for Strategic Clean Energy Transmission (SCET) which will create a framework for cost recovery
• Schedule will be filed by the PTOs (or jointly by PTOs/ISO)
• As necessary, entity(ies) collecting funds will enter into a new operating agreement with ISO-NE or become a party to the TOA if not already

What will be recovered?

• Transmission costs associated with purchase of non-carbon resources
• Depends on the selected project/projects
• RFP design/details still under state discussion, will not be included in tariff
  • States anticipate creative responses
  • Tariff recovery could possibly include fixed cost, incremental revenue needed to make a proposed project happen, or other methodologies that could ensure a certain level of cost predictability
  • States, and/or EDCs as appropriate, will select most cost-effective method of supplying no and/or low carbon emitting resources to New England

Cost Allocation for SCET

• Recovery will begin when the project or projects go into service
• The annual costs for SCET will be divided by 12 and collected on a monthly basis
• The monthly amount will be allocated to load in each state using a Base Cost Allocation Percentage (BCAP). This percentage will be fixed for each year
• The initial BCAPs for each state will be fixed through 2018 and will be included in the tariff

BCAP Calculation

• At the end of each year, beginning at the end of 2018, total energy consumed in each state will be calculated. The % of each state’s energy consumed over the total New England energy is its Energy Ratio Share (ERS)
• For each state: New BCAP = ERS * state specific multiplier.
• All BCAPs will be totaled and ratioed up or down as necessary to total 100%
• Multipliers will be fixed and will be reflected in the tariff

Cost Allocation within a state

• After BCAP is used to determine the cost break down by state, costs will be allocated to load within each state based on monthly peak network load – the same allocator that is used for RNS.
• Each Network Load customer will be allocated its load ratio share of SCET related charges allocate to its state
• Individual states may wish to adjust any allocation to load within its state

Example

• Total monthly charge is $1000
• BCAP for state A is 50%
• Total state A allocation is $500
• Three LDCs in the state A have loads of 5 MW, 15 MW and 30 MW at the time of the monthly system peak
• LDC A pays 5/(5+15+30) * $500 = $50
• LDC B pays 15/(5+15+30) * $500 = $150
• LDC C pays 30/(5+15+30) * $500 = $300

Gas

Gas Infrastructure

• The process to select a gas pipeline project(s) to improve regional electric system reliability will not be in the ISO-NE tariff and is not part of today’s discussion
  • More information on intended process will be communicated at a later date
• The final project(s) and costs will not be known before ISO-NE files this schedule with FERC. The schedule is limited to billing and collection.

IGER Framework

• States asked NEPOOL and the Gas-Electric Focus Group for feedback on the Incremental Gas for Electric Reliability (IGER), EDC and other concepts
  • Many stakeholders provided thoughtful commentssummarized in June 11th follow-up request
• Based on comments, on June 11th states issued Request for Information on Capacity Management and Expressions of Interest from those interested in acting as a counter-party.
  • Responses sought by July 3rd
• States expect to finalize the approach in July

Gas Schedule

• New Service will be called Regional Gas- Electric Reliability Service (RGERS)
• Schedule will be filed with FERC by ISO-NE
• ISO-NE will enter into a Gas Infrastructure Billing and Collection Agreement (GIBCA) with the entity or entities that act as counterparties with the pipeline, separate from, but in support of this schedule, assuming the final structure states advance includes a counterparty

What will be charged?

• Charges will be pipeline and administrative costs less revenues received from capacity release
• Net charges will be paid to the pipeline counter party
• Since capacity release revenues will vary with market conditions, this RGERS charge will change over time

Cost Allocation

• The States are proposing to allocate cost associated with RGERS in the same manner as the SCET though costs will vary per month
  • BCAP based on Energy Ratio Share and state specific multipliers
  • Allocation within a state using network load at the time of the monthly peak
  • BCAP adjustment annually

Why allocate RGERS using network load?

• States’ intent is to allocate costs to regional electric customers in New England in a manner generally reflecting the broad, diverse regional electric power system benefits associated with relieving natural gas constraints that have placed the power system at risk
• This intent could be frustrated if RTLO is used
  • Charge will vary over time; marketers could add risk premiums to project revenue from capacity release
  • Marketers would spread the costs across state boundaries so that the states intent for cost allocation would be frustrated
• Consistency with RNL allocator: incremental pipeline is an investment in power system reliability-based infrastructure

Expected Time Line

• Initial presentation of both Transmission and Gas Tariff language in July
• TC vote on Aug 29
• PC vote on Sept 12
• FERC filing in September