ISO New England on Nov. 8 released the 2013 Regional System Plan (RSP13), a report that outlines transmission upgrades and market responses, such as generation or demand response, that can address identified power grid reliability needs.
The annual plan was approved by the ISO New England board of directors on Nov. 7. The RSP culminates a year-long process with industry representatives and other stakeholders to analyze power system needs and solutions over a 10-year planning horizon.
“New England’s regional planning process has resulted in extensive transmission upgrades needed to ensure grid reliability. These improvements allow power to flow more easily across the system, enable the construction and interconnection of new generators, and foster competitive wholesale electricity markets,” said Gordon van Welie, president and CEO of ISO New England. “At the same time, many factors are converging that will change the way the grid is operated and planned for in the future—and the RSP will continue to serve as a valuable reference document for all stakeholders to use as we move forward to solve these challenges.”
The report said by category:
Transmission—From 2002 through June 2013, 475 transmission projects to address reliability needs were put into service in all six New England states. These projects represent a $5.5bn investment in new infrastructure.
System resources—Since 1997, nearly 14,900 MW of new generation have been constructed in New England, while about 3,360 MW of less efficient, primarily older resources, have retired. Currently, about 1,850 MW of demand resources (both demand-response and energy-efficiency measures) are part of New England’s resource mix.
The outlook is:
- Transmission and power system planning—Additional transmission upgrades to meet reliability requirements are under construction, have been approved, or are being designed. Some of the larger ongoing projects include: the New England East-West Solution, which is major transmission upgrades in Massachusetts, Connecticut, and Rhode Island; the Maine Power Reliability Program; and transmission system upgrades in southeastern Massachusetts and the Greater Boston area.
- Capacity—The seventh Forward Capacity Market auction (FCA #7) procured adequate resources to meet demand through 2016/2017.
- Long-term load forecast—Energy consumption, unadjusted for energy-efficiency (EE) programs, is projected to grow an average of 1.1% annually through 2022, while summer peak demand is expected to grow by 1.4% per year. When the energy-saving effects of EE are included, the forecast shows essentially no long-run growth in electric energy use and 0.9% annual growth in annual summer peak demand, the ISO said.
ISO New England readies wind forecast mechanism
In 2012, 52% of the electricity generated in the region was produced by natural gas-fired plants, while oil units produced less than 1%, and coal plants generated about 3%. Brayton Point, the largest coal plant in the region, is now due to shut in 2017. Nuclear produced about 31%; hydro and pumped storage produced 7%; and renewable energy resources produced 7% of the electricity generated in the region.
As the amount of wind power in New England continues to grow, the ISO is on track to implement a wind power forecast for use in daily system operations in late 2013. Progress continues on other recommendations from the New England Wind Integration Study, including modifying operating procedures and data requirements for wind resources and, over the longer term, integrating wind resources into ISO scheduling and dispatch services. The ISO said it is also considering changes to its generator interconnection study process, including analyzing a wider range of operating conditions than are currently required, as well as identifying elective upgrades to the transmission system in the remote areas where most wind farms are built.
Distributed generation (DG) resources—primarily solar photovoltaic (PV) facilities, but also cogeneration and small-scale biomass and wind turbines—are rapidly expanding. State policies are encouraging the development of these resources, most of which are connected to the distribution system and therefore are not visible to ISO system operators. It is anticipated that more than 2,000 MW of DG, mostly PV resources, will be installed regionwide by the end of 2021, up from about 250 MW of PV at the end of 2012. To address the potential effects of high levels of DG on grid reliability, the ISO recently convened a working group. It will gather information about DG resources in New England and eventually develop a forecast of future DG growth to be incorporated into the long-term planning process.
ISO New England addresses increased reliance on natural gas
Said the report about the recent issue of the region’s increased reliance on often-volatile natural gas supplies: “The region’s heavy dependence on natural-gas-fired generation to meet its electricity needs has resulted in recent operating problems similar to those experienced during past events. Adverse interactions between electric power generators and the natural gas system have occurred, and could occur any time of the year, because the natural gas system has been subject to interruptions that reduce the flow of natural gas to generating units requiring fuel.” The reported added: “In addition, the scheduling requirements of the natural gas system for providing fuel to generators can be in conflict with the electric power sector’s need for flexible operation. Adding to this issue is that the regional dependence on natural-gas-fired generation to provide both electric energy and capacity is expected to grow with the likely retirement of older coal and oil units and their replacement, in whole or in part, with generators in the queue that burn natural gas. Upgrades to the natural gas system infrastructure, some of which have been proposed, would provide some improvements to the deliverability of natural gas. However, additional solutions are required to address fuel-adequacy issues.”
The ISO said it is pursuing market and operational changes, as follows, to address the risks associated with unit performance and gas dependency:
- Coordinating with the gas industry to obtain timely information to fill information gaps and better manage the power system;
- Enhancing market mechanics to better enable resource performance;
- Improving market incentives for resources to perform; and
- Procuring sufficient resources to meet the requirements for capacity and electric energy.
The RSP13 forecast of summer peak demand is higher than the RSP12 forecast by 75 MW for 2013 and lower than the RSP12 forecast by 50 MW for 2021 for the 50/50 “reference” case. For RSP13, the 50/50 summer peak forecast is 27,840 MW for 2013, which grows to 31,520 MW for 2022. The 90/10 summer peak forecast, which represents summer heat waves, is 30,135 MW for 2013 and grows to 34,105 MW in 2021.
The ISO forecasts the 10-year growth rate to be 1.4% per year for the summer peak demand, 0.6% per year for the winter peak demand, and 1.1% per year for the annual use of electric energy. The annual load factor (i.e., the ratio of the average hourly load during a year to peak hourly load) continues to decline from 56.2% in 2013 to 54.6% in 2022.