For the unrecovered the companies may account, undepreciated investment.  
Balances in the 2012 deactivated power plants (albright, rivesville, and willow.  
Island) in any manner the companies deem appropriate, with gaap in accordance.  
And regulatory accounting.  Not, the parties agree that such accounting does.  
To recover these costs or amortization expenses in future rate establish a right.  
Proceedings, and this joint stipulation shall prevent the parties from nothing in.  
To recovery of these taking whatever position they deem appropriate in relation.  
Amounts in future proceedings.  Herh herh herh.

The proposed increase to the customer charge for residential and small commercial
customers shall remain at $5.00 per month.

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.

The Courier & Press began investigating this issue after receiving a call from a local business owner on Friday concerned that her bill had tripled without warning.

Vectren initially said that more bills than usual were estimated over the summer because the company switched meter reading contractors, and it was changing the readers’ routes.

“Without getting into specifics, there are challenges that happen with any contractor transitions,” Hedde said Tuesday morning. She added that the anonymous caller’s high bill was likely atypical.

“I don’t want to give the impression that that is normal,” Hedde said. “She is experiencing something hopefully that is an anomaly.”

But response to a Courier & Press’ Facebook post showed the issue was widespread. Hundreds of people replied to the post with stories of bills that were several times what they expected.

But mistake or no, customers whose bills were underestimated must pay up, said the Indiana Utility Regulatory Commission.

“They are responsible for it,” said Natalie Derrickson, a spokeswoman for the Indiana Utility Regulatory Commission. “At this point, if a customer feels like their bill was estimated and they have larger bills than they were expecting, their first step should be to contact Vectren. If the customer feels like the issue is not resolved, they should contact us.”

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The best onshore renewable wind 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. The best offshore renewable wind resources, however, are often located close to load centers, as is the case with New England.

All of Clean Line’s projects originate in a Type 1 Conditional Constraint Area, identified by DOE in the 2009 National Electric Transmission Congestion Study (“2009 Congestion Study”) and illustrated in Figure 2. The 2009 Congestion Study defined a Type I Conditional Constraint Area as, “an area where large quantities of renewable resources could be developed economically using existing technology with known cost and performance characteristics – if transmission were available to serve them.” The 2009 Congestion Study also noted, “Construction of major new transmission projects would enable development of thousands of MW of new renewable generation” within these areas.

Clean Line has engaged with thousands of local stakeholders in eleven states, where its five projects are actively under development.

These are real projects, many of which have land leased for wind turbines from
farmers seeking new sources of income, as drought has made traditional farming livelihoods uncertain. Wind power represents new hope for drought-resistant income and economic development in regions of the country otherwise struggling with diminishing populations.

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.