With New England long on ideals and limited in resources, Connecticut’s electricity suppliers will have a difficult — if not impossible — challenge meeting the state’s requirements calling for a percentage of the energy supply to come from sources such as solar, wind and landfill gas in the years ahead.
Because renewable energy projects take a long time to build and the standards become increasingly stringent with each passing year, officials at a Nov. 5 conference in Boston urged the industry to embrace and link into the current slate of renewable projects mostly utilizing wind in the region and Canada. The Canadian officials also urged New England to reverse its thinking about high-wattage hydropower as a possible renewable power resource.
As the state and region struggle to meet these standards in the coming years, the end result will be higher electricity prices and more money going to state-sponsored programs designed to boost renewable generation.
“It will be very challenging to meet those goals,” said James Robb, Northeast Utilities senior vice president for enterprise planning and development. “There are projects to be built, but they are not very economical.”
To help Connecticut come closer to meeting its renewable goal, the state’s utilities must figure out a way to more reliably transmit renewable power from areas where the resources are strong, such as Maine and New Hampshire, to load centers of Hartford and southwest Connecticut.
Each of the six New England states has a renewable portfolio standard, which says a certain percentage of the power supply must come from designated renewable resources. The amounts vary by state, but the cumulative effect is that 25 percent of New England’s power supply in 2025 must come from Class I renewables, the strictest level of resource such as solar, wind and landfill gas.
This year, New England has 32,000 megawatts of generating capacity with 1,100 megawatts — 3.4 percent — coming from renewables. To meet state standards, energy suppliers must import renewable power into the region.
Connecticut’s standard for 2010 calls for 14 percent of electricity to be generated by renewables, including 7 percent from Class I. Over the next 10 years, the standard increases to 27 percent, including 20 percent from Class I.
All 77 of Connecticut’s active energy supplies met or exceeded the 14 and 7 percent renewable power goals this year. That doesn’t necessarily mean that 14 percent of Connecticut’s energy supply in 2010 came from renewable sources because the state allows electricity suppliers to buy renewable energy credits to offset any shortages in reaching their goals.
“It’s kind of one hand washing the other to encourage the development and use of renewable resources,” said Phil Dukes, spokesman for the Department of Public Utility Control.
The real problems will arise in 10-15 years as the collective New England standard calls for a high volume of Class I renewables. Right now, New England has 2,960 megawatts of Class I renewable projects underway — 99 percent of which is wind — and that isn’t enough to meet 25 percent of today’s energy demands, much less the expected 8-10 percent growth in demand over the next decade.
Connecticut has almost no in-state sources of Class I renewables; the largest approved Class I generator in the state is the 450-megawatt landfill methane gas facility in Bridgeport. The majority of the others are fuel cells of less than 1 megawatt, meaning state energy suppliers will have to get the bulk of their renewable needs outside Connecticut.
If Connecticut’s standard were modified to be in line with the proposed national standard, then the state would have a much easier time meeting the goals. Under the American Power Act proposed by Sen. Joe Lieberman, D-CT, and Sen. John Kerry, D-MA, energy suppliers would have been given credit for nuclear and hydroelectric power, since they are zero-carbon-emission sources of generation. Hydro and nuclear weren’t considered renewables under the legislation that ultimately failed to pass into law, but suppliers didn’t have to meet the percentages for the portion of their energy portfolio coming from those two sources.
Nuclear is Connecticut’s largest source of generation with the two reactors at the Millstone Nuclear Power Station in Waterford generating more than 2,100 megawatts daily. While nuclear generates no carbon pollution, the reactors produce spent nuclear waste. That nuclear waste can be recycled; but the current national nuclear waste disposal plan calls for it to be temporarily stored onsite while a new national plan is developed — a decision that has been delayed since 1998.
Because of the spent waste issue, Connecticut’s legislators have never proposed or even considered giving renewable credit to nuclear power, Dukes said.
In some instances, Connecticut allows for hydro power to be classified as a renewable, even Class I, but it must be less than 5 megawatts, not significantly alter the course of a river and meet a variety of other conditions. That rules out the majority of New England’s 1,700 megawatts of hydropower and the new hydroelectric system Northeast Utilities and NStar are spending $1.1 billion to tap into in Quebec.
Hydro-Quebec has 42,000 megawatts of generating capacity from its dams in Canada and is adding 5,000 more megawatts in the next few years. Half of the power that is exported from Quebec goes to New England, an amount that will only increase when the $1.1 billion Northern Pass transmission line is complete.
“It is probably the single biggest project that will help cut CO2 emissions,” Robb said.
At the Nov. 5 energy conference in Boston, officials from Canada urged the United States to accept hydro as a renewable power. A main concern regarding hydro is that the flooding resulting from dams causes leaves and other foliage to decompose, emitting methane, one of the worst greenhouse gases. The Canadian officials argued that the water in their provinces is so cold that the leaves don’t decompose.
“I’m struggling here in New England with how New England is going to meet its renewable requirements. Without Quebec and Newfoundland & Labrador, you will struggle to hit that,” said Ed Martin, president and CEO of Nalcor Energy, which is based in the hydro- and wind-rich Newfoundland & Labrador. “Hydro is part of the mix that has to happen if you are going to meet the goals in New England.”
Unlike other renewables, hydro is sold at market price, so the region doesn’t get the electricity prices that will inevitably come as more of the supply has to come from Class I generation, Robb said.
To get more Class I renewable projects off the ground, Northeast Utilities, NStar and other utilities such as United Illuminating and National Grid are considering teaming on a large transmission project in northern Maine and New Hampshire, areas which have the resources for large-scale wind projects, Robb said.
A reason renewable projects have such a hard time getting started is the developers need a way to move their power into the high-demand centers of Hartford, southwest Connecticut and Boston. By building a transmission line, those large-scale wind projects in Maine and New Hampshire would be more economical to build, Robb said.
If the energy suppliers fail to meet the renewable portfolio standard in the coming years, they must make alternative compliance payments to make up the difference. In this state, those payments will go to the Connecticut Clean Energy Fund, which has programs to bolster the use of renewable, but the state legislature could redirect those funds anywhere.
Connecticut has more than 300 Class I, II and III projects either approved or awaiting approval from the DPUC. Many of the unfinished ones have been delayed for regulatory or economic reasons, but a decrease in overall electricity demand due to the recession has helped the state stay ahead of the curve in meeting its renewable portfolio standard.
“We expected to be a lot further behind, and we’re not,” Dukes said.
(NEXT WEEK: Major investments in transmission lines promise improvements in reliability and access to renewable sources.)
