Energy prices, including the prices of electricity, natural gas, and gasoline, have risen for most US consumers over the last several years due to the impact of growing demand, tighter supply-demand conditions (both in the regional electricity market and in global oil markets), as well as exogenous market events, such as the impact of winter cold snaps (January 2004) and Hurricane Katrina (August 2005). Connecticut ratepayers have experienced the same upward trend in electricity costs. While Connecticut does technically possess sufficient in-state generation capacity to meet usual peak demand conditions in the energy market today and into the future, the state has an immediate need for qualified capacity to meet requirements in the Locational Forward Reserve Market and may have an incremental need for capacity as early as 2011 because of the Forward Capacity Market. In addition, much of the local capacity in the state is relatively old, inefficient, and has higher emissions rates as compared to new technology. Connecticut’s load is also disproportionately located in the southwestern portion of the state, creating a load pocket during peak periods and sometimes even requiring emergency measures by the Independent System Operator of New England (ISO-NE) to ensure that there is sufficient energy to meet local demand.

As a way to encourage required new investment in appropriate locations, ISO-NE and the Federal Energy Regulatory Commission (FERC) have been moving forward on plans to implement locational capacity and locational forward reserve markets. Such markets, under the status quo, would expose Connecticut ratepayers to upward pressure in rates through increased Federally Mandated Congestion Charges (FMCCs). Public Act 05-01, An Act Concerning Energy Independence (the Act or EIA) authorizes the Connecticut Department of Public Utility Control (DPUC) to launch a competitive procurement process geared at motivating new supply-side and demand-side resources in order to reduce the impact of FMCCs on Connecticut ratepayers.

Connecticut is a part of the ISO-NE market that spans six Northeastern states, including Vermont, Massachusetts, Maine, Rhode Island, and New Hampshire. ISO-NE currently operates a nodal power market, where the market-clearing price for electricity (the Locational Marginal Price (LMP)) at any point of the network, represents the aggregate of the price of energy, congestion, and marginal transmission losses. Generally speaking, energy-based congestion costs and locationally-driven reliability supplements, such as costs associated with Reliability Must Run (RMRs) agreements, are the result of the need to utilize higher cost local generation when transmission limitations and system operations preclude lower cost power from being imported from other zones or regions. To the extent that ISO-NE also adopts other locationally-differentiated product markets, like the locational Forward Capacity Market and the FERC-approved Locational Forward Reserve Market, the costs associated with these other markets can also be classified as congestion-related and therefore would constitute a component of FMCCs

Subsection 12(a) of the Act requires the DPUC to identify near-term measures by November 1, 2005 that can be implemented by the electric distribution companies by January 1, 2006. This is referred to as Phase I of the FMCC reduction effort. Subsection 12(c) of the Act further requires the DPUC to develop and issue a request for proposal (RFP) to solicit the development of long-term projects to reduce FMCCs, with the local distribution companies serving as the counterparty to any such contracts. It is this clause that is the focus of the current RFP efforts.

According to Subsection 12(c) of the Act, the RFP should identify “measures that would reduce Federally Mandated Congestion Charges for the period commencing on May 1, 2006, and ending on December 31, 2010” and may include but shall not be limited to “(1) customer-side distributed resources, (2) grid-side distributed resources, (3) new generation facilities, including expanded or repowered generation, and (4) contracts for a term of no more than fifteen years between a person and an electric distribution company for the purchase of electric capacity rights”. Subsection 12(c) of the EIA further specifies that the RFP shall “encourage responses from a variety of resource types and encourage diversity in the fuel mix used in generation.”

In line with its mandate under the EIA, the DPUC has launched a procurement process to facilitate the development of incremental capacity that is expected to result in lower costs of power for Connecticut ratepayers. The DPUC’s primary objective with this RFP is to reduce the impact of FMCCs and other costs on Connecticut ratepayers by facilitating the development of new or incremental capacity, including generation capacity, demand-side response, and conservation projects. In launching this RFP process, the DPUC aims to encourage the development of such capacity sooner than might otherwise occur. A project’s contribution to reducing Connecticut ratepayers’ costs of power will be the main driver in the DPUC’s evaluation methodology, which is discussed in greater detail in the actual RFP.