The mitigation proposal includes more than $52 million in funding for Jamestown Island, Hog Island and the Captain John Smith Historic Trail District. The money would fund projects such as seawall rehabilitation and replacement at Historic Jamestowne to help combat the impacts of sea-level rise and erosion, according to the draft mitigation plan obtained by the Virginia Gazette.

The mitigation plan proposal includes $15.5 million in funding for water quality improvement including erosion and sediment control in the James River. Battlefield and landscape conservation projects would get $12 million, including government and private lands associated with the Battle of Yorktown, according to the proposal. More than $4 million would go to protecting emergent marsh at the Hog Island Wildlife Management Area.

Electricity on the PJM grid normally flows from west to east. The major centers for electricity demand are the big metropolises along the Eastern Seaboard, at the eastern edge of the PJM system. There aren’t any power plants located in the Atlantic Ocean, therefore power that isn’t generated locally has to come from the west. As it happens, PJM’s western states have abundant, low-cost wind power — at night-time, wind power is so plentiful compared to demand that the price essentially falls to zero. The main factor limiting East Coast access to that cheap wind is the limited capacity of the transmission grid to carry it.

In the United States, 53% of the nation’s population lives in coastal areas, where energy costs and demands are high and land-based renewable energy resources are often limited. Abundant offshore wind resources have the potential to supply immense quantities of renewable energy to major U.S. coastal cities, such as New York City and Boston.  

Offshore winds tend to blow harder and more uniformly than on land.

GBX is asking for a back-up plan for its field of dreams approach to recovering costs, by coming back to the Commission to comply with the financing condition proposed in the Final Order.

As the Farm Bureau previously argued before this Commission, the denial of GBX’s Application by the MPSC, along with the recent Circuit Court of Caldwell County Order which held that GBX has no authority to construct the proposed line through Caldwell County, Missouri, there will be no construction in Illinois by GBX due to the denials in Missouri. This Commission should consider additional evidence on this issue which occurred after the close of the evidentiary hearings, as described in Exhibit A, the Affidavit of Paul A. Agathen, a Missouri attorney who represents the Missouri Landowners Alliance (“MLA”). The Final Order erred on this issue. Thus, the Commission should rehear this issue.

The record in this docket is devoid of any evidence that the Project would promote the convenience or necessity of anyone other than GBX and certain West Kansas wind developers who said they would use the Project if it ever gets built.

Boiled down, GBX merely asserts that a beneficial project like the Project is needed. Why is it needed? Because it is so beneficial. GBX’s argument that a need for the project exists based on a set of alleged benefits amounts to question-begging on a grand scale. GBX assumes what the Commission should require it to prove. Rather than focus on whether there is any need for the project, GBX jumps right into a show-and-tell on how beneficial the Project will be. The Commission concludes from this that a project with this many benefits must be needed.

Stated another way, the Commission fails to distinguish a benefit from a need. It merely accepts GBX’s catalog of purported benefits as proof of need. Under the Commission’s look-only-at-the-benefits logic, it could just as easily conclude that residents of Point Barrow, Alaska need Frigidaires.

...the Illinois RPS may be satisfied by buying RECs generated in GBX’s targeted west Kansas resource area, and those west Kansas-generated RECs can be purchased without having to build a $2,750,000,000 transmission line across four states.

...the GBX Project is “[l]ike that old 1970s song about Oz and the Tin Man, [because GBX] will give nothing to PJM that it doesn’t already have.”

While the Commission makes soothing noises that it takes seriously the landowners’ concerns about GBX’s ability to use the power of eminent domain against them, it immediately and blatantly contradicts itself by dismissing their concerns as unwarranted because GBX has not specifically requested eminent domain authority in this docket.  Less than a moment’s thought suffices to show the absurdity of the Commission’s position on this issue. If GBX is granted a CPCN it could ultimately use the power of eminent domain against landowners under Section 8-509.
Instead of coming to grips with the power of eminent domain as an integral component of public utility easement acquisitions, the Commission adopts the Pollyanna Principle and accepts at face value GBX’s well-oiled talking points about its voluntary “code of conduct” when dealing with landowners, its promises of respectful treatment, its commitment to negotiate reasonably, and so forth. For the Commission to completely discount the potential impact of eminent domain on landowners simply because GBX did not ask for it in this docket is arbitrary and capricious, and an utter abdication of the Commission’s duty to Illinois citizens.

The Commission’s attitude toward GBX is one of serene and nearly limitless benevolence: whatever GBX can’t do now, it can certainly do later. The Commission will grant GBX its CPCN here and now even though it can’t satisfy most of the requirements of Section 8-406.1 until some unknown point in the future.

But when the landowners raise the issue of GBX’s potential future use of the power of eminent domain against them, which the Commission knows full well inheres in every easement negotiation between GBX and a landowner, the Commission summarily dismisses their concerns as premature because GBX hasn’t asked for eminent domain power here and now, in this docket. In this the Commission subjects the landowners to an egregious double standard, and indulges itself in arbitrariness and caprice of the grossest sort.

GBX’s least cost argument thus rests entirely on its claim that it has no alternative but to be least cost because its entire corporate existence will be some kind of Darwinian
market struggle where only the fittest survive.

The unmistakable irony here is that GBX destroys its own claim to be least cost by asserting that it can exempt itself from those same inexorable free market forces if the going gets tough: GBX reserves to itself the right to seek cost allocation to ratepayers, and in so doing proves itself just another corporate dissembler trying to evade committing itself irrevocably to the ups and downs of the market. And if there are too many downs, the ratepayers can bail GBX out.

But in this docket GBX tells the Commission that it is a “merchant transmission owner” not because it has assumed the full market risk of the Project, but because it plans to earn revenues through discrete transmission services contracts with shippers. This definition of “merchant” transmission owner” appears nowhere in FERC’s orders. That’s because it is a definition concocted entirely by GBX itself, and it differs fundamentally from FERC’s.

Understanding the term “assumption of all market risk” does not require a degree in economics: an assumption of all market risk means exactly that, all market risk, come Hell or high water.

This Commission has no jurisdiction to determine whether or how much of an interstate transmission operator’s costs may be recovered from anyone. The rates, terms and conditions of service for interstate transmission are exclusively matters of federal jurisdiction.

...GBX has no power to confer on this Commission subject matter jurisdiction over the rates, terms and conditions of service on interstate transmission facilities.

If GBX were really a “merchant” transmission owner as defined by FERC, then there would be no questions concerning cost allocation,
and this entire discussion would be unnecessary. GBX simply wants to have it both ways, eating its free market cake while having its cost allocation too.

The purchase power agreement (PPA) [with Public Utilities Commission of Ohio] was the last missing piece: balance sheet shored up; equity overhang removed — we see no more surprises for investors.

"FirstEnergy’s proposal will put safeguards in place to protect our customers from increased price volatility that’s expected to occur in the years ahead," said Doug Colafella, a company spokesman.

... other utilities will want profit guarantees in Ohio and in neighboring states. This, in turn, will undermine a competitive market in which many companies do not have the resources to secure government help the way that FirstEnergy does.

Independent power companies competing against FirstEnergy for customers in Ohio and throughout the 13-state region where high-voltage transmission lines are controlled by PJM Interconnection are not asking for special deals like FirstEnergy is, said Glen Thomas, president of PJM Power Providers Group.

"Our members are competing to provide the most efficient and economic power to consumers in Ohio as possible. We oppose this deal.  We see it as destroying all the benefits Ohio has gained from competitive markets.

"By going down a road where you subsidize plants that are not able to compete economically with other plants, you crowd out these economic advantages as well as send a terrible signal to the market that the best way ... is not to operate at most efficient levels but to seek a bail out from the PUCO."

In March 2009, PJM followed the narrower approach, proposing to pay MLSA to all trades with paid transmission (physical or virtual). In response to that filing, no party suggested that UTC trading would be susceptible to the kind of perverse incentives that the Commission understood could apply to most virtual trades.

No party filed any comments rebutting this contention as to the narrow distribution method, and the Commission accepted it in September 2009. Black Oak Energy, LLC, et al. v. PJM Interconnection, L.L.C., 128 FERC ¶ 61,262 (2009).

On a last quarterly call, we had just announced Project Compass, a proposed 725 mile transmission line through the shale gas regions of Pennsylvania and into New York and New Jersey and Maryland.

We’ve been meeting with officials at the state PUCs and governor's offices in the states where customers will benefit, Pennsylvania, New Jersey, New York and Maryland. Those meetings have gone well overall and we plan to have continuing dialogues on the project benefits. We're also meeting with other key agencies and other transmission operators in the region. We will continue to update you as we reach project milestones.

“This transmission line provides a significant opportunity to improve reliability and grid security and also provides benefits to customers,” Paul Wirth, spokesman for PPL Electric, said this morning. “When you add another path for power to flow, then that increases reliability because you are not relying as much on a single substation or power line.”

Another goal is to provide an estimated savings of at least $200 million per year for New York consumers by reducing transmission congestion.

Who will pay for the first segment of Project Compass?

According to the FERC guidelines for cost allocation, those who benefit from a new power line should pay its costs. The first segment would be paid for by electric customers in New York who will get the benefit of lower power prices. The costs would be paid over a period of many years on customers’ electric bills.

Shah Pourreza - Guggenheim Securities LLC
I appreciate the new disclosures around the Compass Project. So how should we think about the remaining miles? Are you looking to potentially segment the rest? And then, is there an opportunity to potentially JV with some of the neighboring utilities to smooth out the process?

William H. Spence - Chairman, President & Chief Executive Officer
Sure. I think in both cases the answer would be yes. So there's an ability to continue to segment the line as well as partnering with adjacent or utilities that the project goes through their service territory. So I think in both cases we would look to do that.

Daniel Eggers - Credit Suisse Securities (USA) LLC (Broker)
Okay. Very good. I got that. And then just on Compass real quick. I know it's ways off, but does this get caught up in this Order 1000 workout because it's an economic line instead of a reliability line? Do you get more competition, and people prospectively bid away the cost of capital? Or how do you think you're going to be able to reserve some sort of competitive advantage in this line?

William H. Spence - Chairman, President & Chief Executive Officer
I'll let Greg take that question.

Gregory N. Dudkin - President, PPL Electric Utilities, PPL Corp.
Yes. So the way this is set up currently under New York law, this would not be considered a FERC 1000 Project, so we are going and making interconnection requests and will be filing our Article VII now. So if the approval path goes down that path there may be an opportunity for competition, but the probability is little bit lower. If the PSC opens up economic window next year then there could be competition, so we'll see how it plays out.

William H. Spence - Chairman, President & Chief Executive Officer
I think relative to the competitive nature of this, obviously just having completed a very major line essentially in the same region, I think our capability to be very competitive should we get to that point should be strong.

However, what I would say is the compass project, which is not included in our CapEx program, would be a program or a project if you will that would take advantage of some of the opportunities in the Marcellus shale to basically instead of bringing the gas pipelines across, we'd be bringing electric lines across to the potentially new power stations that could be built. So that would be our opportunity, if you will, that's shale gas-related.

What approvals will be required for the first segment?

The first segment will require approval from various regulatory and regional planning entities including the public utility commissions of Pennsylvania and New York, New York Independent System Operator, PJM Interconnection, and FERC. Siting and construction of the line will require permits from appropriate environmental and resource agencies.

Where does the name “Compass” come from?

This project charts a new course in the way we think about and plan the electrical grid of the future.

Dominion contends that the technology doesn't exist to run a reliable line of the caliber and kind needed under 4 miles of riverbed - at least not without a price tag in the billions.

Curtis said the Skiffes over-the-river plan, at $60 million, is indeed on the lower cost end of the dozens of routes and options the company considered. Whatever the expense, though, customers will reimburse Dominion. Rate hikes are automatically allowed for utilities that build infrastructure to strengthen the grid.

"So these are rate-payer dollars, not Dominion dollars," Curtis said. "But the opposition is still committed to the conspiracy theory."

"What's frustrating is that people think we're being disingenuous," Curtis said. "They don't believe we've looked at all the alternatives, or they think we're only concerned about making the most money for our shareholders."

Several lines already feed outside power to the Peninsula, but it won't be enough without the Yorktown plant, which Dominion says is too costly to upgrade in the face of new federal clean-air standards.

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.