ISO New England releases 10-year plan

HOLYOKE, MASSACHUSETTS - The 2009 Regional System Plan released by ISO New England Inc. forecasts that the region is likely to have sufficient capacity to meet electricity demand through 2018 and shows that, while more needs to be done, transmission upgrades and resource additions in recent years have bolstered the power systemÂ’s ability to deliver a reliable supply of electricity to New EnglandÂ’s residents and businesses.

The Board of Directors of ISO New England, the operator of the regionÂ’s bulk power system and wholesale electricity markets, approved the 2009 Regional System Plan (RSP09). The 171-page planning document reports on the status of the regionÂ’s power system, defines areas where improvements are needed, and outlines regional challenges and opportunities through 2018. The plan also describes initiatives underway to address the power gridÂ’s future needs.

"RSP09, which was developed in collaboration with our stakeholders, builds on the foundation of earlier system plans. These plans are guiding development of a regional power system that is not only more reliable, but also more capable of efficient production and delivery of competitively priced power," said Gordon van Welie, President and CEO of ISO New England.

The region is expected to have the resources needed to meet consumer demand and maintain bulk power system reliability through 2018 with the 37,283 megawatts (MW) secured in the second Forward Capacity Auction.

Consumer demand for electricity is expected to grow slowly over the next decade, reflecting the impacts of the economic downturn as well as the implementation of energy-efficiency standards for appliances.

Energy consumption is projected to grow an average 0.9 percent annually over the next 10 years, while summer peak demand is expected to grow by 1.2 percent per year.

Transmission upgrades will continue to be needed in all six New England states to meet reliability requirements and improve the economic performance of the system by reducing or eliminating the need to run more expensive generation in areas with transmission constraints. Major transmission projects needed for reliability include the Greater Springfield (MA) Reliability Project; the Maine Power Reliability Program; and the Vermont Southern Loop Project. Other projects in planning, siting, or construction stages include Southeastern Massachusetts transmission upgrades and the Greater Rhode Island Reliability Project.

The region has made numerous improvements required for power system reliability, including the completion of seven major 345 kilovolt (kV) transmission upgrades since 2002.

In total, over 300 transmission upgrades — representing an investment of $4 billion — have been put in service in all six states between 2002 and 2009; all support the reliable operation of the power system and robust, competitive wholesale power markets.

Competitive wholesale markets have encouraged the construction of nearly 12,500 MW of new generation in the region.

Competitive markets, particularly the Forward Capacity Market, have prompted rapid expansion of demand-side resources, such as energy efficiency, that can help lessen or delay the need for new infrastructure. Over 2,900 MW of demand resources — almost 10 percent of total system capacity — will be available in 2011 to lower electricity consumption.

New EnglandÂ’s markets continue to work efficiently, reflecting real-time conditions and production costs. Lower consumer demand, decreased fuel costs, and increased energy efficiency have resulted in lower wholesale prices so far this year.

To prepare for the grid of the future, the ISO is conducting two major studies addressing the challenges of integrating large amounts of wind and demand resources into system operations and markets. The ISO also has ongoing projects to incorporate smart grid technologies.

Economic analyses conducted in 2008 of several hypothetical system expansion scenarios as well as this yearÂ’s New England 2030 Power System Study, done at the request of New EnglandÂ’s six governors, show that large amounts of wind energy development within New England and expanded trade with Canada would require transmission improvements or expansion to move the electricity to load centers.

Gas, which fueled 41 percent of the regionÂ’s electric generation last year, is likely to remain the dominant fuel for the foreseeable future. That said, regional and interregional coordination between the gas and electric power industries, conversions of natural gas plants to dual-fuel capability, and expanded natural gas infrastructure are lessening risks of supply disruptions.

Climate change legislation, the Regional Greenhouse Gas Initiative, and the statesÂ’ Renewable Portfolio Standards are encouraging the development of renewable resources and investment in energy efficiency. Current state targets call for 30 percent of the regionÂ’s electricity use in 2020 to be met by renewable resources and energy efficiency. Renewable resource projects currently proposed in New England, as well as projects not yet proposed, renewable energy from neighboring areas, small on-site renewable energy systems, and the use of state-set Alternative Compliance Payments are among the possible solutions for meeting or exceeding the regionÂ’s goals.

ISO New England continues to work with grid managers and stakeholders in neighboring power systems in Canada and New York, as well as the rest of the nationÂ’s eastern power grid, to coordinate planning for future system needs.

The annual Regional System Plan is developed to help industry and government stakeholders make informed business and policy decisions. In 2000, the Federal Energy Regulatory Commission assigned ISO New England the responsibility for coordinating regional system planning. Each year, the ISO prepares a comprehensive, 10-year plan that includes forecasts of future demand for electricity and addresses how this demand may be satisfied by adding supply resources, demand resources, and new or upgraded transmission facilities. Each RSP is a snapshot in time, and the results are revisited as needed based on the latest available information. Each plan is developed in a year-long, collaborative process that includes state regulators and other government entities, transmission owners, end-users, market participants, and other stakeholders.