The rule shall--
(1)
promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all facilities for the transmission of electric energy in interstate commerce, regardless of the ownership of the facilities;

(3)
encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities

Section 219(b)(3) directs the Commission to encourage investments in technologies and other measures that increase the capacity and efficiency of existing transmission facilities and improve the operation of those facilities. Such investments could include advanced management software or application of technologies, such as energy storage, in order to improve utilization of existing transmission system assets.

Q 37) How should the Commission incentivize the deployment of technologies and other measures to enhance the capacity, efficiency, and operation of the transmission grid? How can the Commission identify and quantify how a technology or other measure contributes to those goals? Please provide examples.

Q 38) Can the Commission distinguish between incremental improvements that merit an incentive and those maintenance- related expenses that a transmission owner would make in its ordinary course of business?

Q 39) How should a transmission owner seeking this type of incentive demonstrate increases or improvements in the capabilities or operations of existing transmission facilities?

Q 40) Should the Commission provide a stand-alone, transmission technology-related incentive? If the Commission provides a stand- alone transmission technology-related incentive, what criteria should be employed for a technology to be considered as meriting an incentive? Should the Commission periodically revisit the definition of an eligible technology?

Q 41) Certain utility costs, such as those associated with grid management technology, including dynamic line rating technology, are typically recovered through operations and maintenance expenses within cost-of service rates. For such costs, should the Commission, instead, consider inclusion of these expenses in rate base as a regulatory asset? If so, what costs should be eligible for such treatment and over what period should they be amortized?

Q 42) Are there ways the Commission could incentivize RTOs/ISOs to adopt better grid management technologies and/or other technologies to improve the efficiency of individual transmission assets to promote efficient use of the transmission system and improved market performance?

Q 43) Should the Commission interpret section 219(b)(3) to encourage improvements that are not historically considered part of the transmission system, such as, for example, software upgrades, technologies that allow for faster ramping, or other innovative measures that achieve the same goals as new transmission facilities? What types of incentives could increase the adoption of these technologies? Are there forms of performance-based ratemaking with respect to transmission that the Commission should explore? If so, describe such alternative ratemaking structures.

"I am a firm believer in protecting individual freedom and rights of private property owners, especially our farmers and ranchers," Parson said in a written statement to The Associated Press. "We will continue to stay engaged with the legislature to ensure that we are equipped to protect all Missourians from potential threats of government overreach for private gain."

The vote was bipartisan, and approving the measure was the right thing to do. The Missouri Senate should pass the bill, and the governor should sign it.

...we agree with Missouri Republican leadership that allowing a company to condemn property for this purpose is wrong. Clean Line Energy should negotiate fair agreements with property owners for any towers it needs, and pay for the land accordingly.

It should not use the threat of condemnation to browbeat property owners into accepting low-cost deals.

Their efforts should be applauded. Eminent domain must always be the last resort for projects of major public benefit, not the first step in making rich companies richer.

Condition No. 4: Invenergy shall make preliminary easement payments of [redacted percentage, most likely 30%] of the total eventual compensation to all Kansas landowners affected by the line siting within 12 months of a Commission decision to extend the 13-803 sunset provision or gaining approval for a new line siting.

Placing a firm deadline by which preliminary easement payments must be made to all Kansas landowners unnecessarily and improperly restricts the ability of GBE, and by  extension Invenergy, to conduct Project development according to its proven best   practices which have resulted in the successful delivery of over 20,220 MW of generation   projects and 392 miles of transmission lines.

Importantly, this deadline, in a vacuum, does not account for the many other Project development activities that must be carefully sequenced prior to and in parallel with easement acquisition in order to ensure efficient scheduling and deployment of capital to minimize Project costs and facilitate timely delivery, including but not limited to:

Completing the regulatory processes in the various states;

Closing on the Membership Interest Purchase Agreement;

Completing environmental permitting requirements, including extensive consultation with state and federal agencies;

Advancing Project engineering, including detailed design of the route to conform with environmental permitting requirements and landowner considerations;

Conducting an open solicitation for Project capacity;

Negotiating transmission service agreements with customers; and

Obtaining financing for construction of the Project.

There are endless variables that could impact the timing of this process, such that placing a firm deadline on payments to all Kansas landowners restricts the ability of GBE and Invenergy to efficiently manage Project development, and thus severely inhibits the Project’s likelihood of success.

GBE and Invenergy fully understand and respect the uncertainty surrounding landowner impact from the Project, which has been an unfortunate consequence of regulatory uncertainty in other states that has hindered Project progress. It is important to clarify that, despite Invenergy’s concerns with Proposed Condition No. 4, it is in no way discounting the importance of landowner participation in the GBE Project and reaffirms its commitment to working with host communities to foster mutually beneficial relationships; this commitment is reflected in Invenergy’s track record of successfully negotiating over 16,000 lease agreements with landowners, entirely on a voluntary basis, across its project portfolio. GBE and Invenergy are planning, upon approval of the Transaction, to reengage affected landowners to provide Project updates and to be a resource for interested parties. This effort to become a known commodity in host communities and to develop and foster local relationships is an important first step in the land acquisition process that must not be overlooked simply for the sake of quickly obtaining easements.

The best way to obtain certainty regarding the Project is to utilize available capital in an efficient and logical manner. Each of the development activities listed above will add incremental certainty to the Project. Inefficient use of capital will decrease certainty by putting unnecessary financial and logistical strain on the Project. Accordingly, while the intended result of Proposed Condition No. 4 is to increase certainty, it will actually have the opposite effect.

There can be no debate that our energy future will require more diversity in energy resources, particularly renewable resources. We are witnessing a worldwide, long-term and comprehensive movement towards renewable energy in general and wind energy specifically. Wind energy provides great promise as a source for affordable, reliable, safe and environmentally-friendly energy. The Grain Belt Project will facilitate this movement in Missouri, will thereby benefit Missouri citizens, and is, therefore, in the public interest.”

The dominant argument in favor of blocking eminent domain is that the right to private property shouldn’t be infringed upon by a private company.

“This is just another attempt by private companies under a government commission to limit our personal liberties,” bill sponsor Rep. Jim Hansen, R-Frankford, said as he introduced his bill.

There were also concerns about how the power line could negatively affect property value and how it could damage farming land. The lawmakers also questioned why an out-of-state company should have this power.

“We’ve been told that these people will be well-compensated and it’s going to do so much for the economy and so these poor counties — I come from a poor part of the state — and those things matter, but there ends up being more important overarching values,” Rep. Jeff Shawan, R-Poplar Bluff, said.

“For an awful long time, we’ve subsidized oil, and we don’t seem to have a problem with that,” Rep. Deb Lavender, D-Kirkwood, said. “So why do we suddenly have a problem with subsidizing wind?”

James Owen, executive director of Renew Missouri, dismissed the eminent domain legislation as a tactic that will only “add to the litigation that’s been attempting to halt this job-creating project for five years.”

“Ultimately, it won’t stop it for many reasons, but leaders think this frivolous legislation will score points with some noisy constituents,” Owen told The Missouri Times. “So it’s another hurdle to creating jobs and bringing low-cost energy to Missouri. Disappointing, but misguided.”

“We have tremendous outpouring of leadership in the House and the Senate,” Gary Marshall, CEO of the Missouri Corn Growers Association, said. “We just felt it was important to be here to show them how much this legislation means to us.”

The recommendation by the reviewing State Agencies to deny a transmission project is a
rarity and is not made lightly, or without significant analysis and consideration. Yet, this project contradicts Maryland’s well-established statutory planning and preservation priorities. While, the work of PJM is vital to assure the reliability of the electricity grid that serves Maryland, what is most beneficial for the applicant, or PJM and its stakeholders, is not always what is in the public interest of the State and its residents. This discretionary PJM-driven market efficiency project, and the process used to approve it, demonstrates this divergence. As described by the Direct Testimony of the Secretary of Agriculture, Joseph Bartenfelder, and the Executive Director of MALPF, Michelle Cable, Maryland’s agriculture industry is vital to Maryland as its single largest industry after the federal government, which is why Maryland has prioritized preserving farmland and ensuring the integrity of MALPF easements. Projects that diminish the State’s efforts and devalue its investments to preserve this finite resource should not be approved when existing infrastructure is available. PJM and transmission developers should reasonably be expected to incorporate Maryland’s stated policies and statutes into their project development and approval processes.

The MMU recommends the creation of a mechanism to permit a direct comparison, or competition, between transmission and generation alternatives, including which alternative is less costly and who bears the risks associated with each alternative.

Transmission owners are already required to address many facets of reliability through compliance with the North American Electric Reliability Corporation (NERC) reliability standards and various other planning criteria. Nevertheless, the Commission could potentially tailor incentives to promote reliability transmission projects that significantly enhance transmission reliability above and beyond what is required by the NERC reliability standards or other planning criteria.
Q 17) Should the Commission tailor incentives to promote these types of projects based on their expected reliability benefits? If so, how should the Commission differentiate these projects from others required to meet reliability standards?
Q 18) Are there specific reliability benefits or project characteristics that could merit such an approach?
Q 19) If the Commission tailored incentives for reliability benefits, how should the Commission measure the expected enhancement to transmission reliability? Should there be a threshold or bright line
test applied? If so, how?

One way in which additional transmission facilities may further encourage reliability is by expanding access to essential reliability services, which can, among other things, allow delivery of sufficient resources to support and stabilize grid frequency during disturbances and ensure adequate voltage control and reactive power capability.
Q 20) Should the Commission incentivize transmission facilities that expand access to essential reliability services, such as frequency support, ramping capability, and voltage support?
Q 21) If so, how should the Commission assess and measure whether transmission projects expand access to essential reliability services?

Transmission projects can promote economic efficiency by reducing congestion, which allows efficient dispatch of resources, facilitating the interconnection of additional generation, and facilitating the transmission of additional generation to load centers. The Commission could tailor incentives to promote transmission projects that accomplish either of these two outcomes.

Q 22) Should the Commission tailor incentives to promote projects that accomplish the outcomes of reducing congestion or facilitating access to additional generation?
Q 23) Should the Commission establish bright line metrics, such as a specified level of reduction in average production costs, to determine whether a transmission project merits incentives?
Q 24) Should the Commission consider incentivizing transmission projects that are scaled to more efficiently facilitate interconnection of, or transmission to, additional generation? What other measurable economic efficiency benefits should be considered a bright line metric for the purposes of economic efficiency?
Q 25) How should the applicable bright line criteria be established, and, in cases where more than one criterion applies, how should they be evaluated in combination?

Section 219’s objective of promoting the development of transmission facilities that ensure reliability and/or reduce congestion may be particularly important in regions of the country that have experienced chronic, long-term congestion or require operating procedures in place to address long-term reliability issues.

Q 26) Should the Commission utilize an incentives approach that is based on targeting certain geographic areas where transmission projects would enhance reliability and/or have particular economic efficiency benefits? If so, how should the relevant geographic areas be identified and defined? What entity (e.g., the Commission, RTOs/ISOs, state regulators, other stakeholders) should designate such areas?

Q 27) What criteria should be used to define such geographic areas? Procedurally, how should such geographic areas be determined, monitored, and updated?


Q 28) Should the relevant geographic areas be defined on an ex ante basis and/or should the transmission developer have the burden of demonstrating that the relevant transmission project falls within a geographic region that has an acute need for transmission?

Q 29) How can flexibility characteristics improve the operation of the transmission system? Q 30) Should the Commission incentivize flexibility characteristics and, if so, how should it do so?
Q 31) How could the Commission define “flexibility” in this context?

Q 32) Should the Commission incentivize physical and cyber- security enhancements at transmission facilities? If so, what types of security investments should qualify for transmission incentives? What type of incentive(s) would be appropriate?

Q 33) How should the Commission define “security” in the context of determining eligibility for incentive treatment? For example, should the Commission define security based on specific investments or based on performance of delivering increased security of the transmission system?

Q 34) Should transmission projects that enhance resilience be eligible for incentives based upon their reliability-enhancing attributes? Q 35) If so, how could the Commission consider or measure the benefits of an individual project towards grid resilience?

Q 36) If the Commission were to grant incentives for measures that enhance the resilience of the transmission system, what incentive(s) would be appropriate?

“My fear of that is the precedent it would set within the state of Missouri for any future developments,” Klusmeyer said.
Any utility system in the state, whether it’s water, sewer, electric or telecommunications, has the power of eminent domain, Klusmeyer said. The bill could be construed to limit the use of eminent domain for “pretty much any utility in the state,” he said, even though it’s limited to “above-ground merchant lines.”
“That can trickle down into just about any type of utility expansion that’s done, whether it’s through Missouri American, or maybe even Ameren or Associated (Electric Cooperative),” he said. “That’s my fear of what it’s going to do to any type of infrastructure improvement or expansion in the state.”

Private entities shall not have the power of eminent domain under the provisions of this section for the purposes of constructing above-ground merchant lines. For the purposes of this subsection, "merchant line" means a high-voltage direct current electric  transmission line which does not provide for the erection of electric substations at intervals of less than fifty miles, which substations are necessary to accommodate both the purchase and sale to persons located in this state of electricity generated or transmitted by the private entity.

The bill, introduced by Rep. Jim Hansen, R-Frankford, would prohibit taking easements by eminent domain to make way for the Grain Belt Express, a planned $2.3 billion transmission line, which Chicago-based Invenergy bought last year. The line would carry electricity from the Iron Star wind farm in southwestern Kansas, across Missouri and Indiana, and into Illinois. The line would cross eight north Missouri counties, including Monroe and Ralls, which are represented by Hansen.

Targeted at the Grain Belt Express, the bill would also apply to similar projects. It bans all private entities from using eminent domain to acquire easements to build “above-ground merchant lines” if less than 12 percent of the power will be consumed by Missouri customers.

The Federal Energy Regulatory Commission has the power to regulate transmission, not the state legislature, said Mark Petty director of Kirkwood Electric. Every transmission project can be difficult for landowners to grapple with, which is why they are considered by a commission rather than elected officials who haven’t been reviewing all the facts, he said.

“It’s easy for an entity that objects to want to do an end run, even after all the other facts have been presented and laws been interpreted and reviewed,” he said.

Since the electricity is still coming to customers through public utilities, customers will have the same low rates and price stability, Petty said. The wind electricity from the Grain Belt Express is also cheaper than the alternatives, and Kirkwood could save up to a third of what it currently pays for electricity, Petty said.

Cities served by the public energy pool will also see savings, but not as large as Kirkwood. Each city would save about 3-4 percent, said John Grotzinger, vice president of engineering operations and power supply at the Missouri Public Utility Alliance. Those savings would be passed on to ratepayers, he said.

Q 1) Should the Commission retain the risks and challenges framework for evaluating incentive applications?
Q 2) Is providing incentives to address risks and challenges an appropriate proxy for the expected benefits brought by transmission and identified in section 219 (i.e., ensuring reliability or reducing the cost of delivered power by reducing transmission congestion)? If risks and challenges are not a useful proxy for benefits, is it an appropriate approach for other reasons?
Q 3) The Commission currently considers risks both in calculating a public utility’s base ROE and in assessing the availability and level of any ROE adder for risks and challenges. Is this approach still appropriate? If so, which risks are relevant to each inquiry, and, if they differ, how should the Commission distinguish between risks and challenges examined in each inquiry?

Q 4) Would directly examining a transmission project’s expected benefits improve the Commission’s transmission incentives policy, consistent with the goals of section 219? Are there drawbacks to this approach, particularly relative to the current risks and challenges framework? Q 5) If the Commission adopts a benefits approach, should it lay out general principles and/or bright line criteria for evaluating the potential benefits of a proposed transmission project? If so, how should the Commission establish the principles or criteria?
Q 6) How would a direct evaluation of expected benefits, instead of using risks and challenges as a proxy, impact certainty for project developers?
Q 7) Should transmission projects with a demonstrated likelihood of benefits be awarded incentives automatically? How could the Commission administer such an approach?

Q 8) If the Commission grants incentives based on expected benefits, should the level of the incentive vary based on the level of the expected benefits relative to transmission project costs? If so, how should the Commission determine how to vary incentives based on the size of benefits?

Q 9) Should incentives be conditioned upon meeting benefit-to-cost benchmarks, such as a benefit-cost ratio? If so, what benefit- to-cost ratios should be used?

Q 10) Should incentives be based only on benefit-to-cost estimates or should the Commission condition the incentives on evidence that that those benefit-to-cost estimates were realized?

Q 11) If an incentive is conditioned upon a transmission developer meeting benefit-to-cost benchmarks, what types of benefits and costs should a transmission developer include, and the Commission consider to support requests for such incentives? Should there be measurement and verification, and if so, over what time period? If expected benefits do not accrue, should the incentive be revoked?

Q 12) How, if at all, would examining transmission projects’ characteristics in evaluations of transmission incentives applications improve the Commission’s transmission incentives policy and achieve the goals of section 219? Are there drawbacks to this approach, particularly relative to the current risks and challenges framework? Would this approach result in different outcomes, as compared to the current risks and challenges approach for granting incentives?
Q 13) If the Commission adopts an approach based on project characteristics, should it lay out general principles and/or bright line criteria for identifying or evaluating those characteristics?
Q 14) If so, how should applicable criteria be established, and, in cases where more than one criterion applies, how should they be evaluated in combination?
Q 15) How would an approach based on project characteristics impact certainty for project developers, particularly relative to the current risks and challenges framework?
Q 16) Should transmission projects with certain characteristics be awarded incentives automatically? How could the Commission administer such an approach?

Private entities shall not have the power of eminent domain under the provisions of this section for the purposes of constructing above-ground merchant lines. For the purposes of this subsection, "merchant line" means a high-voltage direct current electric  transmission line which does not provide for the erection of electric substations at intervals of less than fifty miles, which substations are necessary to accommodate both the purchase and sale to persons located in this state of electricity generated or transmitted by the private entity.

Marilyn O’Bannon of Monroe County says she will lose farmland and room to till:

“When do you give the right to somebody to take their business across your business. I’m going, as a landowner, to give up a lot of income. I’m not talking a few dollars here, a lot of income to allow something to come across my property that I will get no value from.”

The Public Service Commission ruled that the landowners would have to be compensated for use of the land and caps the amount of agricultural land used for each tower.

But the Public Service Commission on this past March voted unanimously to give Grain Belt Express Clean Line LLC a “certificate of need and necessity.” Former Missouri Gov. Jay Nixon argued on behalf of the company.

The proposed line promises to deliver 3,500 megawatts of renewable energy from western Kansas to southeastern Missouri and into Illinois, and Indiana where it would connect to a grid that supplies energy to heavily populated northeastern states. 

Peggy Whipple, who argued on behalf of Clean Line before the Missouri Supreme Court and the PSC, says the commission decision legally deems the company to be a public utility, answerable to local regulators.
“We have legal control over this company that will develop this line for everything that we could hope to have it for, other than rates only.”  Rates would come from the U.S. Federal Energy Regulatory Commission and must be just and reasonable, she says.”

Small cities and their utilities spoke against the bill, saying they need the new power lines. Carroll County Commissioner Bill Boelsen:
“My previous job before I took on this job was high-voltage electricity. I traveled the entire United States working on substation transformers.  This country’s infrastructure is crap anymore. It’s 70, 80 years old at least.”

Stephen Franke, a businessman from Hannibal says they’ve been promised energy a third cheaper than the open market.
“Two cents a kilowatt-hour an entire third cheaper for a community with 20 percent poverty rate. That’s substantial. In addition, a 25-year contract, we’re locked in which means we can do capital planning, we can do reserve planning. We’re not exposed to the risk of an open and volatile market.”