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.

For the 39 municipalities in Missouri signed up to buy power off the line, it’s an estimated $12.8 million in annual savings.

As stated in the rebuttal testimony of Duncan Kincheloe, MJMEUC’s president and general manager, our current arrangement with Illinois Power Marketing Company (“IPM”) for 100 MWs of energy and capacity will expire in 2021, and that contract currently serves the needs of the Missouri Public Energy Pool (MoPEP). We have been actively considering sources to replace this energy and capacity.

In 2021, a contract for 100 MWs of energy and capacity with Illinois Power Marketing Company (IPM) (former Ameren coal plants in Illinois, now owned by Dynegy) will expire. That energy and capacity will need to be replaced. That contract currently serves MoPEP, a group of 35 Missouri cities for which MJMEUC provides full requirements for wholesale energy, capacity and ancillary services. The TSA with Grain Belt and the power purchase agreement with Infinity Wind would allow the MoPEP to replace the current 100 MWs of purchased power in MISO with more affordable energy. John Grotzinger will explain in his rebuttal testimony that while the TSA and corresponding contract with Infinity Wind will not by themselves replace the IPM contract, these contracts will form the cornerstone of the resource mix to replace the IPM contract.

The United States desperately needs new power lines.

Our transmission standstill has a number of consequences. First of all, it raises consumer prices. As this post at CanaryMedia makes clear, bad transmission hasn’t raised utility bills despite generation being cheaper than ever.

A 2018 report by the nonprofit Americans for a Clean Energy Grid identified 22 shovel-ready projects that had been in existence for a decade or more. To get such projects off the ground, the report’s authors suggested streamlining project siting and permitting, passing a tax credit for transmission projects, and direct investment by the federal government. 

Despite recent noise from the Biden administration about speeding up the sitting process, the same problems are still knocking off and slowing down transition projects. 

The most recent and notable example is that of the Grain Belt Express. The transmission line, which would span nearly 800 miles across four midwest states, from Kansas to Indiana, connecting into the PJM Interconnection LLC grid, is at risk of being thwarted by House Bill 2005. The bill, brainchild of big ag groups across the region, would give any county in the line’s path the right to block construction. 

The project represents a special economic opportunity for the region’s rural communities which have struggled in recent times. The cheap wind power would provide significant savings to the small municipalities. What’s more, emissions would be brought down as well. 

Cumbersome regulations and NIMBYISM are mostly to blame for the nation’s stagnant transmission system.

The same article includes quotes from advocates of bill 2005: ‘“Grain Belt is currently working towards condemning our land,” Henke said in written testimony. “They have told us they will not negotiate with us and the price they tell us is what we get. This line will take out our shade trees in our pastures and cut through several fences. They are not willing to move the line at all to avoid some of these things that will greatly impact our farm.”’

I don’t want to completely disregard people like Henke’s misgivings, but no decision comes without a cost. At some point, we’re going to have to accept some of the costs associated with big transmission projects to reap the important benefits: Cheaper, cleaner electricity.

Coordinating with utilities to deploy buried HVDC transmission in the highway ROW offers several benefits, including increased resilience and significant carbon emissions reductions without changing the viewscape. Expanded transmission will be vital for electrifying transportation in the most cost-effective manner.
The traditional thorny issue of building linear infrastructure on private property can be mitigated with undergrounding the transmission along existing highway and rail corridors. Burying HVDC transmission can be done at a similar cost to conventional overhead AC transmission while providing critical reliability and resilience benefits. Furthermore, the potential for accelerated permitting timelines for buried transmission projects would be worth billions of dollars in avoided carbon emissions.
The findings from this study demonstrate that buried HVDC transmission is cost-effective and can be feasibly sited in interstate and highway ROW after making appropriate consideration of existing and future transportation system needs. While the study identified challenges, none appear to pose insurmountable barriers.

The development of transmission and fiber lines often requires the ability to acquire or lease significant lengths of ROW – this is especially true for interregional transmission. Utilities often prefer to use a ROW they have developed and own. However, obtaining new ROW is challenging and the optimal route is not always possible. (Footnote:  A number of overhead interregional transmission projects have been successfully blocked by public opposition in recent years.)  Access to a portion of existing ROW in interstate or highway could offer significant benefits in the development of new transmission and fiber lines. Existing ROW along interstate highways would be especially valuable for the interregional transmission lines needed to cost-effectively decarbonize the grid while improving its reliability and resilience.
If interstate and highway ROW were made available for transmission development, a typical transmission project would likely use a portion of the highway ROW while also using existing utility and rail ROWs. The transmission line would not be fully sited within the highway ROW alone. In these circumstances, siting of the transmission line within the ROW would be done in close collaboration with the existing ROW owner (e.g., the DOT) and would take into account current and future transportation needs.
While not all highway ROW is suitable or available for electric transmission (siting within urban corridors can be particularly challenging), ROW in rural areas can be suitable (see figure 7). In rural areas, the ROW is often 300 feet wide, and other utilities and land uses are not as competitive.

By building a buried HVDC transmission system alongside our interstate network of roads and rail lines, the country can overhaul and expand the transmission network more quickly, cost-efficiently, and easily than developing a new ROW through private land. Benefits of this approach accrue to landowners, electric customers, and the grid itself.
Siting, permitting, and building a traditional overhead HVAC transmission line typically takes at least 10 years and often much longer because of challenges related to cost, environmental permitting, and siting on private land. Using highway and rail ROW means working with fewer property owners – potentially just a handful instead of many hundreds. It also largely removes the threat of eminent domain to take land from private owners.

Thus, the five-year reduction in the transmission development timeline that the NextGen Highways Team believes is possible (for a typical interregional transmission project) would translate into $1 billion of societal value.
It is worth noting that a 2GW, 300 miles-long, buried HVDC transmission line would cost roughly $2.5 billion. As such, $1 billion of societal value would equate to 40 percent of the transmission line’s cost.
Scaling the societal benefits from a single interregional transmission line to meet estimated interregional transmission needs yields about $150 billion of societal benefits from coupling buried HVDC transmission with our existing transportation ROW.

Buried HVDC transmission costs have declined and become competitive with traditional overhead AC transmission. The technology for buried HVDC transmission has matured, and the industry has gained experience designing and building projects across the world. Figure 8 compares transmission coston a capacity-normalized basis (dollars per gigawatt-mile of transmission capacity) for a few representative transmission projects in the United States. The figure shows that buried HVDC projects are cost-competitive with overhead AC transmission projects. 

Historically, utilities have discounted the use of underground transmission because buried AC line costs were often 7 to 10 times more costly than overhead lines. Today, some utilities will still cite those cost comparison numbers without considering the technological advances of HVDC cables and converter stations over the past decade.

Buried HVDC transmission is cost-competitive with traditional overhead AC transmission projects.

Buried HVDC transmission is roughly 2-4 times the cost of overhead HVDC transmission. (Footnote:  This assumes that the overhead HVDC transmission can be permitted and built. Over the last decade, a number of overhead HVDC transmission projects across the US were unable to be successfully built, including Northern Pass, New England Energy Connect (still active), Plains and Eastern, Grain Belt Express (still active).

Given the positive findings from this Feasibility Study, the NextGen Highways Team is planning to launch a NextGen Highways Coalition to support the co-location of buried fiber and transmission in highway and interstate ROW.