Incorporating new natural gas plants and large wind farms will require more infrastructure, ISO New England President and CEO Gordon van Welie said on Jan. 26, noting that expanded natural gas infrastructure will be needed to provide fuel to the growing fleet of natural gas power plants, and new high-voltage transmission lines will be needed to move wind energy from remote mountainous areas in the north to markets in the south.
There are multiple proposals to build large, privately-owned transmission lines to bring additional hydro and wind power from Canada and northern New England to the region’s population centers, he said during ISO New England‘s “State of the Grid: 2016″ media briefing.
While those are elective projects proposed by private developers, and not reliability projects needed to address weaknesses on the existing power system, they could help facilitate the integration of renewable resources by improving portions of the grid, van Welie said.
As noted in his presentation, as of Jan. 1, 11 elective transmission projects had been proposed in the ISO interconnection queue, totaling more than 7,000 MW of potential transfer capability.
According to his presentation, developers are proposing to build 13,000 MW of generation, including nearly 8,200 MW of gas-fired generation and more than 4,200 MW of wind. There are 3,641 MW of wind projects proposed in Maine; 464 MW proposed in Massachusetts; 91 MW proposed in New Hampshire; and 47 MW proposed in Vermont, according to his presentation.
“State policies have had a significant impact on the development of solar resources, which have been coming online rapidly in recent years,” van Welie said. “We expect the current level of nameplate capacity of 1,200 MW to double to more than 2,400 MW by 2024.”
Most of the solar being added in New England is at customer sites, on the distribution system, and van Welie added that ISO New England is not connected to those resources and cannot “see” or control their output, so improving daily operational forecasts to understand when they will produce energy, or not, is crucial to reliable power system operations.
The New England states are leading the nation in development of energy efficiency measures and support of clean energy resources, he said, adding that those have primarily been large-scale wind in remote areas of the region, as well as behind-the-meter solar.
“Some state clean energy goals also seek more large-scale hydro from Canada,” he said. “Whether it’s wind in northern New England or hydro from Canada, more high-voltage transmission lines will be needed to bring that energy down to New England’s population centers.”
The transition to greater levels of renewables will require fast and flexible resources that can ramp their output up and down on command to balance the variable output of those weather-dependent resources, he said.
Paradoxically, the current technology that can do that best is in natural gas generators, van Welie said, adding that New England has conventional grid-scale energy storage in the form of two large pumped hydro storage facilities, and the states are launching initiatives in support of emerging storage technologies.
The New England power system continues to be in a precarious position during extended periods of extreme cold, and the region will continue to be in that position until New England’s natural gas infrastructure is expanded to meet the demand for gas, van Welie said.
The region’s competitive wholesale electricity markets have attracted significant investment in new power plants, he said, adding, “Most of this new investment has been in highly efficient, natural gas-fired plants that are relatively easy to site and less expensive to build and run than other types of power plants.”
Booming natural gas production from the Marcellus Shale has made low-priced natural gas available to the region, most of the time, he said.
“When there’s enough pipeline capacity to serve the region’s power generators, New England’s wholesale electricity prices can compete with the prices in regions where electricity is typically less costly,” he said. “In winter, though, the pipelines serving New England are operating at full capacity just to meet heating demand. When that happens, we’ve experienced challenges to power system reliability as well as extreme price spikes.”
During most of the year, the price of natural gas is setting the wholesale price of power, so power plants using more expensive fuels are getting squeezed financially, and as a result, more non-natural gas-fired generators are retiring, he said.
With declining natural gas prices, the use of natural gas to generate electricity has increased, he said, noting that last year, natural gas-fired power plants produced 49 percent of the electricity generated in New England, which is up from 15 percent in 2000, and is more than any other fuel source in the region. Meanwhile, the combined use of coal and oil has fallen from 40 percent to 6 percent over the same period, he said.
The price of wholesale electricity is primarily driven by the cost of fuel used to produce it, he said, adding that natural gas and wholesale power prices are closely linked in New England because the largest share of electricity produced in the region’s six states comes from generators that use natural gas.
“In winter, when the demand for gas is high and natural gas pipelines are constrained, wholesale prices can increase dramatically,” he said. “In summer, when the demand for natural gas is low and the pipelines are not constrained, the fuel’s price drops and wholesale electricity prices drop, too.”
Last summer’s prices were the lowest in 12 years and as a result, New England prices were competitive with prices in other wholesale markets, van Welie said. The Midwest typically has used such cheaper, indigenous fuels as coal and, therefore, typically has had lower prices than New England, he said. However, van Welie said, in winter, the Midwest does not have the natural gas pipeline constraints that New England experiences and because of those constraints, New England consumers cannot reap the year-round benefit of low-cost natural gas.
He also noted that the total value of the New England energy market was $5.9 billion in 2015, and there were two main drivers for the low energy market value: very mild weather most of the year lowered consumer demand for natural gas and electricity, and extremely low natural gas prices during most of the year translated into very low power prices.
Including the capacity and ancillary services markets, the total value of New England’s wholesale electricity markets was $7.2 billion in 2015, he said, noting that those are preliminary numbers.
When wholesale markets are competitive, as they are in New England, resources must compete by offering their electricity at prices that reflect their true operating costs, van Welie said, adding that fuel is the primary operating cost for most resources. Competitive markets have enabled the addition of new, efficient, natural gas-fired generators, and those generators are displacing older power plants that use more costly fuels, such as coal and oil, he said. Renewable resources, which have no fuel costs, will displace natural gas generators, van Welie added.
As noted in his presentation, 13,650 MW, or 44 percent, of the total generating capacity in New England uses natural gas as its primary fuel.
Discussing natural gas pipeline constraints, he noted that forecasters have identified up to 4,200 MW of natural gas generation that could be at risk of not being able to get fuel during the 2015/2016 winter period. To ensure that there is enough fuel to keep the lights on, ISO New England initiated its first winter reliability program two winters ago for 2013/2014, he said, noting that another one ran last winter, and the third program is underway.
New performance incentives in the Forward Capacity Market will go into effect in June 2018, he said.
“With the new rules, resource owners are expected to make investments that will ensure their resources will perform as expected during times of system stress,” he said. “For many of these owners, the most cost-effective investment is to convert to dual-fuel capability.”
Of the Forward Capacity Market, van Welie said that in 2015, more than 1,000 MW of new power plants came forward and cleared in the market. When those new plants come online in two or three years, they will start to address the future capacity shortfalls expected in some areas of the region, he said. In addition to the high level of new generation, last year’s capacity auction demonstrated robust price competition, he said, noting that in that auction, developers of proposed new power plants accepted a capacity clearing price that was lower than the estimated cost to build a new power plant.
For the next capacity auction, in February, 147 new resources totaling 6,700 MW of new generation, demand response and energy efficiency capacity have qualified to compete to supply capacity three years from now, van Welie said.