Large-scale wind farms paired with new transmission lines -- not distributed solar generation -- is the cheapest way for the US to decarbonise its electricity system, claims an executive at Clean Line Energy Partners.

Jayshree Desai, executive vice president at Clean Line Energy Partners, also believes that over the next few years the cost curve for wind will bend downward more rapidly than for PV, after solar’s spectacular price decline in recent years. Large-scale wind farms paired with new transmission lines -- not distributed solar generation -- is the cheapest way for the US to decarbonise its electricity system, claims an executive at Clean Line Energy Partners.

“I’m a supporter – I have nothing against [distributed generation]”, she said, speaking this week at the AWEA Finance conference in New York. “But the math is just not right.”

Desai argues that the true cost of integrating distributed solar into the grid is not being accounted for – a line increasingly employed by electrical utilities keen to curb the growth of rooftop solar.

“It’s heavily subsidised, not only at the federal level, but at the transmission and distribution [level too],” she says. Given those subsidies, “of course DG looks so good”.

Kris Zadlo – a multi-decade veteran of the transmission sector, and currently vice president at Invenergy – believes distributed generation will “take a big bite” out of the electricity transmission sector in the years ahead.

Zadlo says that being able to cut the transmission portion out of the picture entirely is a big advantage for distributed generation. “And it’s not only about cost, but also about control,” he says.

“We can’t underestimate that what DG allows people is their own peace of mind, control of their own destiny. What sort of premium is that worth to the customer?”

The DOE will conduct a thorough review that includes making all required statutory findings as well as consideration of the proposed project’s environmental impacts, the project’s technical and economic feasibility, and whether the project is in the public interest.

DOE will decide whether to participate in the proposed project, a decision which would include route selection, once all environmental reviews and other due diligence have been completed. The earliest a decision could be made is at least 30 days after issuing the Final EIS, which is not expected before 2015.

Issues Not Addressed in the EIS: Before DOE conducts its review of all of the factors discussed above, the applicant will be required to submit further information and update its original application. Once DOE receives the updated information, and deems the application complete, it will provide notice that the application is available for public review through a notice in the Federal Register and an announcement on the OE website. Publication of this notice in the Federal Register will begin a 45-day public comment period. The notice will describe how to comment on the application for the proposed project. All comments submitted during the comment period will be considered in the DOE’s ultimate decision as to whether to participate in the proposed project under the Section 1222 program.

The chief planning official for PJM Interconnection Inc., the grid operator, said in a letter to New Jersey Sierra Club director Jeff Tittel that continued operations of the B.L. England power station in Cape May County would not create reliability problems, but that the plant's shutdown would.

"Recent media statements attributed to you about reliability and cost impacts associated with the B.L. England generating units' remaining in service are based on a misunderstanding of PJM Interconnection's planning process," Steven R. Herling, PJM's vice president of planning, wrote Thursday to Tittel.

"Our transmission-planning process is very complex, dynamic, and - as a consequence - can be misunderstood," Herling said in his letter to Tittel. "I would have been very happy to explain the process and underlying facts to help you avoid confusion, and would be willing to clarify PJM's study results at any time."

“I have no doubt, in the long run, we need power and we need power transmission lines, and they’re going to go somewhere,” said Don McKay, general manager of Tyrol Basin Ski and Snowboard Area.

“Nothing here is very negotiable,” said McKay, who also is a Vermont town supervisor.

Robert and Danuta Pyzalski said it was too preliminary to get answers about their town of Middleton home, in the study area.

“My concern is how close the lines would be to residential areas,” Robert Pyzalski said. “To say there would be no danger would be naive.”

Members of a new resident-led work group created to grapple with Dominion Virginia Power’s plans to run a transmission line through Alexandria did not mince words following the utility’s first presentation on the project.

“I’m just looking at statements here with nothing to back them up.”

Both officials and work group members are growing more suspicious as Dominion’s application date creeps closer.

“There’s some healthy skepticism,” Smedberg said. “While Dominion says they don’t know what a final route would be, many people in the community find that a little hard to believe. They know exactly what they want to do and have known for a while.”

With permits to build an underwater and underground power line from the Canadian border to New York City all but fully in hand, the developer is turning its attention to a similar proposal for a 1,000-megawatt power line that would run down Lake Champlain and then across Vermont to feed the New England electric grid.

Once out of the water all the cable will be laid in public rights of way and the company TDI New England has been working with the state of Vermont and local communities along the route on the minutiae: Everything from how to be sure the under-road conduits don’t worsen spring frost heaves to how the cables cross beneath bridges or how to ensure that once the cables are buried they aren’t disturbed.

Benson Selectboard member Sue Janssen said TDI New England has worked hard to meet the concerns of her community of just over 1,000. They are even paying a lawyer of the town’s choosing to represent the community in the detailed discussions that are coming.

“I have the impression if we’d said we wanted our dirt roads painted pink they’d have done it,” she said.

So far there has been no significant opposition to TDI New England’s major electrical infrastructure project such as has faced plans to build ridge-top industrial wind projects, extend a natural gas power line from the Burlington area to Rutland or build a 180-mile above-ground power line between the Canadian border and northern New Hampshire.

“I think that one of the key differentiators of other proposed projects is that we are all buried,” said TDI New England CEO Donald Jessome.

Matt Valle’s solution to energy shortages in Eastern Massachusetts eschews the usual approach of running miles of new transmission lines on unsightly towers. Instead, Valle proposes to bury 50 miles of high-power cable in the ocean floor, using an underwater robot that resembles a lunar rover.

The robot would dig a trench 4 to 6 feet deep in an arc from Salisbury to Lynn for a power line that would bring 520 megawatts of electricity from the Seabrook generating station into Greater Boston.

If approved, the so-called SeaLink line would be the first underwater transmission line in Massachusetts, and Valle argued that it would be more reliable than high-voltage lines that are exposed to New England weather.

“It’s a buried system. It is protected against extreme weather — high winds, flooding, icing,” said Valle, president of New Hampshire Transmission, a subsidiary of NextEra Energy, one of the country’s largest power companies.

But there is one major drawback: With a price tag of more than $1 billion, SeaLink looks on paper to cost about $350 million more than a competing project, which includes a new 25-mile transmission line running from Londonderry, N.H., to Tewksbury, as well as upgrades to the existing high-voltage power network.

“Ours is the most cost-effective solution. That’s a fact,” said Rudy Wynter, president of the transmission business at National Grid, which is partnering with Northeast Utilities on the project. It would feature a combination of high-voltage 115 kV lines and extra-high-voltage 345 kV lines constructed on rights of way that are already held by the two companies.

"Generic statements that transmission reinforcement is desirable do not amount to establishment of need."

Construction of major new transmission facilities, in particular, raises unique issues because transmission facilities have long lives – typically 40 years or more. Evaluating the merits of a proposed new facility is  challenging, because common practices take into account only those expected costs and benefits from a project that can be quantified with a high degree of perceived certainty. This has two effects:
First, it leads to a focus on the subset of cost and benefits that can be readily quantified. Not taking into account the costs and benefits that are hard to quantify has the effect of setting their value to zero in a comparison of costs and benefits.
Second, it leads to projections of costs and benefits that are generally on extrapolations drawn from recent experiences. Projections based only on recent experiences will not value the costs and benefits a transmission project will have under very different assumptions or scenarios regarding the future because they ignore or discount the likelihood of these possibilities. Such a narrow view of the range of costs and benefits that could occur provides a false sense of precision.

As will be discussed later in this chapter, many states adopted Renewable Portfolio Standards with requirements or goals to use more  renewable‐sourced electricity.
Because much of the best utility‐scale renewable resource potential is relatively remote from the load centers, the states then had to authorize new transmission construction to enable the desired renewable‐based electricity to reach the grid.

Many points of transmission congestion today result from the need to deliver electricity from
changing sources of generation. For example, generation sources are changing because of
state‐mandated RPSs. The best renewable resources (i.e., those with the highest potential capacity factors) tend to be located far from load and sometimes in areas with less transmission than desired for effective resource development. Existing transmission constraints may deter development of these resources. While this is not a challenge in all parts of the Eastern Interconnect, it is a principal cause of evolving congestion concerns in the Midwest.

Designation of an area as a National Corridor is one of several preconditions required for
possible exercise by the Federal Energy Regulatory Commission (FERC) of “backstop” authority to approve the siting of transmission facilities in that area.