In addition to airing her jurisdictional and standing concerns, the judge said permitting retail ratepayers to file such complaints "is at odds with promoting efficiency" because FERC could be faced with handling "potentially millions of individual complainants."

The groups, however, insisted that Cintron's position is "contrary to the plain language of the FPA," which states that "any person" has standing to file a complaint with FERC, as well as long-standing commission precedent holding that retail ratepayers have standing to challenge wholesale rates.

Citing a proceeding involving the abandoned Potomac Appalachian Transmission Highline project in which FERC found that "[a] complaint regarding a transmission rate can … be filed by any person, including an end-use customer that will pay some portion of that rate when flowed through its retail bill," the groups called Cintron's attempts to distinguish that situation from AEP's "unavailing." The judge relied on differences in the two companies' formula rate protocols to make her case, but the groups argued that "standing is a statutory right under the FPA, and whatever is said in the AEP protocol cannot overturn the statute."

As for Cintron's concerns about the regulatory burden that would be placed on FERC if retail ratepayers are allowed to challenge wholesale rates, the groups insisted that "administrative convenience is not a basis to eviscerate a statutory right." They said that "[i]n any event, this is a chimera — in the nearly 20 years since the commission issued Order 888, there has been a stream but not a deluge of … rate challenges."

Finally, among other things, the groups said the "novel viewpoint" expressed by Cintron "would reopen the … regulatory gap between federal and state jurisdiction that the FPA was designed to close."

"For consumers impacted by commission-jurisdictional transmission rates, there is no other effective remedy," the groups said.

As a general proposition, the cases that are discussed above suggest that when utilities are seeking selection or CPCN approvals from governmental entities, the utilities should rely on the established governmental approval processes to persuade the officials and not indulge in collateral efforts such as public education, outreach, and advertising activities.  If a utility should rely on  these collateral activities while pursuing selection or CPCN processes, then it will risk the chance that these costs may not be recovered from ratepayers.  If the selection or CPCN application has merit, the governmental selection process provides a sufficient vehicle for the utilities to present their engineering, marketing and economic studies and thereby hope to merit the vote of approval from these officials.  In this regard the PATH Companies spent over $8 million on attorney fees to prosecute the CPCNs before the respective governmental bodies, which begs the need for these collateral expenses.

SWEPCO received a notification letter from SPP stating that updated electric load  forecasts showing lower future electric demand in North Arkansas than prior forecasts for the area critical to the Facilities, and the  recent cancellation of several large, long-term transmission service reservations, establish that the Facilities are no longer needed to meet the reliability needs in the region.

Despite identification of areas in which transmission capacity is limited, a “not in my backyard” (or anyone else’s, in some cases) attitude toward new transmission line siting has resulted in cancellation or delay of some new transmission lines.

For example, in 2011, PJM cancelled the proposed Potomac Appalachian Transmission Highline (PATH) project, a 275-mile transmission line that would have run through West Virginia, Virginia, and Maryland to deliver electricity into Northern Virginia. Although the line was designed to improve reliability in eastern PJM, changing forecasts of electricity demand growth and intense opposition to siting the line led to the project’s cancellation.

Beginning in the late 1920s, electric utilities began to integrate their operations to improve reliability and reduce costs. Previously, utilities had operated as “islands,” meeting the demand for electricity solely from their own generating plants. To ensure reliable service, this meant building extra generating capacity to keep in reserve, in case unexpected problems caused their plants to shut down.[2] By integrating their operations, utilities could provide more reliable service without building as much backup generating capacity. In essence, if a generating plant at Utility A suffered a forced outage, one of Utility B’s generators would be available to ensure the lights stayed on. The concept is similar to diversifying a financial portfolio. Instead of investing everything into just one company’s stock, buying multiple stocks, bonds, and other investments reduces the risk of a sudden financial loss.

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.

Among those who had expressed concern over Bay’s limited energy policy experience was Manchin, who helped sink the bid of Obama’s previous nominee, former Colorado regulator Ron Binz.

That sparked a flurry of negotiations over the last several days among the White House, Murkowski and Energy committee Chair Mary Landrieu (D-La.), which resulted in the president’s concession not to appoint Bay chairman immediately.