But what must be the most difficult pill to swallow is the legislators’ statements that House Bill 2005, which reforms eminent domain law for future transmission projects, represents one of the success stories of the 2020 session.

Lawmakers should be willing to call it what it is. Perhaps not a sellout, but a difficult compromise that comes at the expense of those landowners who are most affected and led this fight.

You could point to several benefits of Grain Belt, the 780-mile transmission project bringing wind power from Kansas to populations further east.

The customers on the receiving end get plenty of benefits. But who, exactly? Unlike something more tangible like gasoline, it’s hard to see where electricity is directed on the grid, but the fact that Grain Belt will end near Indiana suggests that many of its beneficiaries are there and not here.

Invenergy, the for-profit company building Grain Belt, could benefit nicely when it starts to sell the power.

This spring, the legislature passed a bill that clamps down on the use of eminent domain for transmission lines. The legislation, now headed to the governor’s desk, requires a company or an investor-owned utility to pay 150% of market value for an easement on agricultural property. It also requires a project to deliver a proportional amount of power to Missouri so that it doesn’t just use rural counties as an energy superhighway on the way to bigger cities.
But House Bill 2005 contained the following words: “These provisions will not apply to applications filed prior to Aug. 28, 2022.”
That means Grain Belt, granted regulatory approval in 2019, is grandfathered in.
“We thank our many supporters for their tireless efforts in ensuring that this legislation recognized the legal rights of Grain Belt Express as a previously approved project that will continue forward toward full construction,” said Nicole Luckey, senior vice president of regulatory affairs for Invenergy, in a statement. “Missouri lawmakers brought stakeholders together around this important legislative compromise, which will benefit Missouri families, farmers, workers and businesses for decades to come.”


That’s not how Rogers sees it.
“I have a hard time with the Legislature right now,” he said.

The growing threat of power outages fueled by extreme weather calls for new approaches to grid oversight, the head of the Federal Energy Regulatory Commission said yesterday, adding that utilities and grid operators should “think differently.”
In the face of droughts and heat waves worsened by climate change, the commission must advance new policies to modernize power markets, build more transmission lines and safeguard energy infrastructure, said FERC Chair Richard Glick. Regulators, energy providers and others also need to adjust to the “new normal” as extreme weather events become more common, according to Glick.
“The old way doesn’t work anymore. We need to figure out a new approach, a much more reliable approach, and that’s what we’re trying to do here at FERC,” he said.

While Glick, a Democrat, said the FERC report underscored the need for more transmission lines and changes in U.S. power markets, Republican commissioners highlighted how retiring fossil fuel power plants may be exacerbating reliability challenges.

The Midwestern grid region, for example, is at a “high risk” of power shortfalls due to a decline in generation capacity this year relative to last year. Power shortfalls could occur during extreme temperatures, during periods of low wind power or in the event of generation outages in the coming months, FERC staff said in a presentation on the findings.

The staff analysis showcased the need for more natural gas infrastructure to support generators, and for regulators to address state energy policies that are “reliability-impairing,” said Republican Commissioner James Danly. He also questioned whether more investments in the electric transmission system would solve the reliability challenges.

“There is, in the minds of some, an idea that as long as we get the transmission issue correct, everything else will eventually solve itself. I am simply a skeptic,” Danly said.

“There is clear, objective, conclusive data indicating that the pace of our grid transformation is out of sync with the underlying realities and physics of our system,” Christie said.

Based on my experience as a state regulator with IRPs and computer models purporting to predict the future two or more decades down the road, I regard 20-year projections of this sort as, at best, occasionally interesting, but they certainly provide no basis whatsoever for saddling consumers with the costs of a billion-dollar transmission line.

AFUDC is booked during the pre-service phases, but cannot be recovered from customers until the project is completed and actually serving customers, i.e., “used and useful.”  The NOPR proposal is simply in keeping with traditional good utility ratemaking principles.  Booking these costs as AFUDC also recognizes the reality that just because an LTRT project is selected for a regional plan, it still has to obtain all state siting, certificate of public convenience and necessity  and other, including environmental, approvals, and survive what may be the subsequent litigation, before it is actually built.

The Infrastructure Investment and Jobs Act (IIJA or the Act) directs the Secretary of Energy (Secretary) to establish a program, to be known as the “Transmission Facilitation Program” or “TFP,” under which the Secretary shall facilitate the construction of electric power transmission lines and related facilities. The U.S. Department of Energy (DOE or Department) Grid Deployment Office is issuing this NOI to notify interested parties of its intent to implement the TFP and to describe the proposed approach for participation by eligible entities in the TFP. The Department also seeks input from all stakeholders through this RFI regarding the application process, criteria for qualification, and selection of eligible projects to participate in the TFP.

(19) The IIJA calls on DOE to seek to enter into capacity contracts that will encourage other entities to enter into contracts for the transmission capacity of the eligible projects. On what basis should DOE assess whether a capacity contract with an applicant will encourage other entities to enter contracts for transmission capacity?

12) Recognizing that transmission projects are located based on the availability of generation, and ultimately customers to buy that generation, and have limited long term direct employment impacts:

• What equity, energy and environmental justice concerns or priorities are most relevant for the TFP? How can these concerns or priorities be addressed in TFP implementation?
  

DOE participation is to help provide certainty to developers, operators, and marketers that customer revenue will be sufficient to justify the construction of a transmission line that meets current and future needs. Applications for capacity contracts are not required to account for National Environmental Policy Act (NEPA) environmental impact review, because DOE's entry into a capacity contract does not independently trigger NEPA review.

Because we conclude that the Commission’s decision denying the Siting Applications and rescinding Transource’s provisional CPC was in accordance with Pennsylvania law, including Sections 1501 and 2805(a) of the Code, and Section 57.76(a) of the Regulations, and is supported by substantial, credited evidence
of record, we affirm.

As for Transource’s arguments that PJM’s determination of need would be binding due to this matter involving issues of interstate regional transmission subject to FERC oversight,the ALJ held that the Commission was obligated to make an independent determination based on Pennsylvania law. (Id.at 82, 86, 99-102.)The ALJ further observed that while FERC has exclusive jurisdiction over the interstate transmission of electric energy and wholesale electric process, that jurisdiction was limited to matters that are not subject to state regulation. (Id.at 85 (citing Section 824(a) of the Federal Power Act, 16 U.S.C. § 824(a)).) According to the ALJ, FERC recognized this limitation by stating that there is “longstanding state authority over certain matters that are relevant to transmission planning and expansion, such as matters relevant to siting, permitting, and construction” and that the FERC was in noway invoking “an exercise of authority over those specific substantive matters traditionally reserved to the states . . . .”(Id.(quoting Transmission Planning and Cost Allocation by Transmission Owning & Operating Pub.Utils., 76 Fed. Reg. ¶¶49,842, 49,861 (Aug. 11, 2011) (FERC Order No. 1000)).) This means, according to the ALJ, that FERC Order No. 1000 was “not intended to dictate substantive outcomes” or to allow FERC to “determine what needs to be built, where it needs to be built, and who needs to build it.” (Id.at 85 n.13 (quoting S.C. Pub. Serv. Auth. v. Fed. Energy Reg. Comm’n, 762 F.3d 41, 57-58 (D.C. Cir. 2014) (internal quotation marks and citation omitted)).)

As for the resolution of congestion in the APSRI, it does not appear that we have ever held that congestion, which is an economic consideration, is sufficient on its own to support need or necessity under Pennsylvania law.

It was not just OCA’s witness who criticized PJM’s cost-benefit analysis, but PJM’s own Independent Market Monitor who suggested that its market efficiency process, which includes the cost-benefit analysis, be reevaluated and that the actual costs and benefits of a project should be considered and not ignored in determining whether a market efficiency project is needed.

But building transmission, she said, “takes patient money” and “a deep engagement with many, many regulatory bodies” and stakeholders.
“The very big reality is, whether we’re doing a 100-mile [transmission] line or a 500-mile [transmission] line, pretty much anyone can stop it. You can have local jurisdiction, county jurisdiction, state jurisdiction. And you don’t typically have condemnation rights.”
Overcoming landowner opposition “takes a lot of engagement. It takes a lot of humility. You’ve got to talk to people from where they’re at. You can’t come in political. You can’t come in with preconceived ideas. You can’t come in even with the implicit idea that this is essential for the greater good. You have to come in, when you’re talking with landowners, profoundly respectful, that you may be dealing with heritage ranches that have been in families for over a century. And you need to be willing to sit down, listen, have hard conversations [and] follow up again.
“And then you have to work with their concerns. … They can say, ‘You know, I am protective of this particular view. Can you work on the routing around this precious part of the land for me?’ And so I think that that’s really the key to engagement.”
Webster said Pattern takes a broad view of its “host community.”
“You’re a host community if you’re hosting an actual facility with turbines or panels. You’re a host community if you’re hosting a substation, or a major piece of transmission infrastructure. But to us, you’re also a host community if you’re supporting the public good by allowing your transmission line to pass through your county or your property. And so we created standardized community benefits packages based on just mileage that [is] consistent across our entire footprint.”

The RTO said all summer months will require emergency resources to meet peak load conditions. Using a probable peak load forecast, MISO said it has 116 GW of firm resources to cover a 116-GW peak in June, an insufficient 119 GW to tackle a 124-GW peak in July and another 119 GW that will be no match for August’s 121-GW peak forecast.

The RTO said it could be in even worse shape if it encounters higher-than-normal temperatures coupled with a high level of generation outages. The grid operator said it’s possible it will find itself depleting all emergency resources and still coming up a few gigawatts short over all three months. In a worst-case scenario, MISO could have a little less than 114 GW in firm capacity and a daunting 131-GW demand during the July peak. In that case, it would be about 5 GW short after all firm and emergency resources are factored in.

MISO last week warned that even a normal amount of demand and generation outages will likely send it into emergency procedures this summer.
The RTO also didn’t rule out summertime load shedding during combinations of high demand and high generation outages.

The grid operator said it will probably rely on a combination of emergency resources and non-firm energy imports from neighbors to maintain system reliability in June, July and August.