While not yet ready to begin construction, Hurtado said the next big milestone isn't far off, and Clean Line has turned its focus to finding key customers.

"We've been at it for a while, and we're very close to the finish line," he said.

Clean Line has yet to announce any firm agreements with Southeast utilities for transmission. Meanwhile, the clock is ticking.

"We think that there's a time-sensitive opportunity," Hurtado said. "I'm not comfortable waiting too much longer. The sooner we can get this done, the better. There are always risks, and you want to manage that really prudently. We're already in pre-construction. The sooner we get into full-fledged construction, the better."

"Obviously, the trick is to make sure that you have capacity at the right price to the people that are actually winning the contracts in the Southeast," Hurtado said. "There's direct commercial discussions that are going on that are confidential. There are RFPs [requests for proposals], and that's still moving forward. It's part of our overall commercial discussions that we've got that are sort of focused, but they're all sort of in the works."

One potential customer, the Tennessee Valley Authority, so far hasn't shown an interest in taking transmission service from the Plains and Eastern.

TVA signed a memorandum of understanding with Clean Line in 2011, but the utility currently has no need for more energy on its system as its long-range plans show no demand growth for the next decade, said spokesman Scott Brooks.

And any older power plants being shut down by TVA are generally being replaced with natural-gas-fired generation, Brooks said.

Plains and Eastern is open to PSO or other utilities customers owning all or a portion of the transmission line, commensurate with their transmission needs. In addition, Plains and Eastern is open to PSO or other utilities managing part or all of the Plains & Eastern Project's construction.

If there is a demand for Oklahoma Panhandle wind in eastern Oklahoma, the Project's first phase could be built solely in Oklahoma. Subsequent phases could be built at a later date if market demands warranted such action.

While Plains and Eastern's efforts have been focused on HVDC transmission, other technical
solutions could be constructed in the Project's right-of-way, such as 345kV AC or 765kV AC. Plains and Eastern is open to modifying the
Project to a different technology or voltage level if it offers the best value to customers.

The Project begins near Wind Catcher's generation position in the Panhandle and the route runs within 50 miles of PSO's Tulsa North substation, the proposed interconnection point for the Wind Catcher line.  In eastern Oklahoma, there are also other potential interconnection points in PSO's service territory that are even closer to the Plains & Eastern Project's route than the Tulsa North substation and could be utilized to serve PSO load and other loads.

Furthermore, the Plains and Eastern team has received many questions from landowners and other stakeholders in Oklahoma about the Wind Catcher project. The team has been asked if Plains and Eastern can be involved or assist in the Wind Catcher project given that Plains and Eastern has a construction-ready, long-haul transmission project that runs from the Oklahoma Panhandle to the east and has acquired easements on more than 750 parcels in Oklahoma.

After being approached by representatives of PSO, Oklahoma landowners have asked the Plains and Eastern team if they should work with PSO even though they have already signed an easement with Plains and Eastern.

The power markets have evolved substantially since Plains and Eastern received its order from this Commission in the past eight years and eastern Oklahoma is now a strong delivery point for the Plains & Eastern Project. The Project could be utilized to accommodate high-voltage either direct current ("HVDC") and alternating current ("AC") transmission solutions to accomplish this interconnection in eastern Oklahoma and Plains and Eastern is willing to engage to consider either option. Mr. Hurtado stated that he would explain that Plains and Eastern is open to building a first
phase of the Project that is located solely in Oklahoma.

SPP has no plans to build new transmission
lines in the next decade, making independent transmission necessary to enable large amounts of new wind farms to be built in the Oklahoma Panhandle.

Plains and Eastern has also secured all key regulatory approvals necessary for construction on that route.

The DOE independently analyzed the proposed route and several alternative routes in its
EIS and ultimately approved a preferred route through its Record of Decision.

Plains and Eastern's careful and open approach to landowner interaction and easement acquisition established the company as a solid partner and good neighbor in Oklahoma

Many landowner conversations are on-going, and Plains and Eastern is highly confident that all right-of-way necessary to start construction could be completed in time to allow for construction to start in 2018 and an on-line date in 2020.

The current market design in ERCOT primarily places the responsibility for system costs on ERCOT customers. This docket has revealed that the Southern Cross DC tie will result in additional costs to ERCOT, which include extraordinary costs that arise specifically from the Southern Cross DC tie, the Garland line, and the Garland or Oncor substations. Because the customers of exported power are not ERCOT customers, under the current market design and rules, they will not bear any responsibility for the extraordinary costs specific to the Southern Cross DC tie, Garland line, and Garland or Oncor substations that they impose on the ERCOT system. Southern Cross believes that those customers—and therefore Southern Cross—should get a free ride as to these extraordinary costs. The Commission disagrees and determines that the public interest demands that ERCOT ratepayers should not bear any of the costs associated with the Garland line, the Oncor substation, the Garland substation, or the Southern Cross DC tie that are properly borne by others.
The costs that a user of the ERCOT system causes cannot be determined simply by focusing on the costs of the facilities on the last forty miles of a multi-thousand-mile network. There is little doubt that additional facilities will be required in ERCOT because of the electricity flowing over the Southern Cross DC tie. Southern Cross believes that the costs of those facilities should be borne by customers in ERCOT, not the out-of-ERCOT customers that cause those costs.  And Southern Cross opposed even an investigation into whether revisions to the current ERCOT cost-allocation method were needed. Southern Cross attempts to justify this free-ride position based on theoretical benefits that this project will provide to ERCOT.

The Commission agrees, however, that no party met the burden of proof to prove what benefits, if any, Texas ratepayers will enjoy as a result of the Garland line and the Southern Cross DC tie and concurs with the ALJs that any benefits are questionable.  This is one of the issues that will be evaluated by ERCOT and if subsequent investigations show any benefits, then any such benefits could be reflected in the new market-design rules. The record in this case does not justify a free ride for these questionable benefits.  Texans are in the process of paying billions of dollars for the newly constructed CREZ transmission lines, and for substantial other facilities, that are integral to transmitting electricity to the Garland line and the Southern Cross DC tie. As proposed by Southern Cross Transmission, the Garland line would simply interconnect with these CREZ lines and reap benefits without paying its fair share of costs.

Further, Southern Cross argues that the DC tie will not cause a substantial increase in ancillary services needed in ERCOT, and that no change in the current manner that ancillary costs are assigned is necessary.  Southern Cross argues that the DC tie should get a free ride on these extraordinary costs also. The Commission agrees that this is a highly technical question and has requested ERCOT to evaluate this matter. The Commission also agrees, however, with ERCOT and other parties that additional ancillary services will likely be required to support the operation of the DC tie, and at certain levels, that requirement may be significant.  And, as with the other extraordinary costs discussed in this Order, it is appropriate that the cost causer be responsible for the costs, not for ERCOT customers to bear the costs of others. The Commission does note that Southern Cross softened its position some by agreeing that it could and would provide reactive-power service through the DC tie.

One benefit offered by Southern Cross is the lowering of the price of electricity in ERCOT during high-load periods.  However, Southern Cross Transmission's analysis does not appropriately account for the effect on the ERCOT energy market, which sends market signals through scarcity pricing when electricity resources are becoming scarce. Distortions to ERCOT's market signals could prevent the energy-only market from appropriately responding to shortages, leading to inadequate resources in this market. This risk to ERCOT's market structure and the grid's reliability must be assessed and addressed through recommended changes.

“Anytime you have legal clouds pending, you’re not going to spend a lot of time with that uncertainty,” said Lawlor. “We’ll see how the decisions play out before we put a lot of people to work building the project.”

The ruling, Clean Line director of development Mark Lawlor said last week, would discourage renewable energy development in Illinois.
“It is clearly a setback, and a signal not only to our investors, but to other developers, on the tremendous amount of legal barriers in Illinois,” said Lawlor. “It goes beyond Rock Island. It goes beyond Grain Belt.”

The already-strong demand for imports of low-cost wind energy into the mid-South and Southeast would likely increase if and when states in the region are subject to regulations limiting greenhouse gas emissions from power plants. EPA’s Clean Power Plan, published in October 2015 and scheduled to mandate compliance beginning in 2022, aims to “continue progress already underway in the U.S. to reduce CO2 emissions from the utility power sector” and is part of a suite of air quality improvements sought by other national environmental regulations. These improvements could be accomplished through retrofitting of older generation plants, plant retirements, and an increasing reliance on local or imported low-carbon generation including renewables. The Department’s Energy Information Administration (EIA) estimates that the Clean Power Plan would result in strong growth in renewable generation, particularly in regions currently lacking robust renewable portfolio standards such as the Southeast. Implementation of the Clean Power Plan would also shift the regional fuel mix away from baseload capacity with on-site fuel supplies (such as coal, nuclear, hydroelectricity, and oil) towards capacity that tends to utilize real-time fuel delivery (wind, solar, and natural gas).  Overall, wind generation is projected to play a major role and become increasingly economically competitive. Although the EIA’s analysis did not look at the degree to which such a fuel mix would be imported to the Southeast or conduct a detailed model of the transmission system, it did find that “[c]ompliance with the proposed rule could necessitate significant investment in electric transmission system infrastructure to integrate renewables from remote areas.”

To be sure, wind power delivered by the Project will compete with other sources of renewable energy in markets in the mid-South and Southeast. But such competition is healthy, and ultimately benefits consumers and the renewable energy sector as a whole. Indeed, new transmission links such as the Project create value through their ability to foster healthy competition among generators. As the Commission has observed: “New interconnections and transmission service generally meet the public interest by increasing power supply options and improving competition.” The Commission has also explained that “as a general matter, the availability of transmission service enhances competition in power markets by increasing power supply options of buyers and sales options of sellers, [resulting in] lower costs to consumers.”

The proposed Chokecherry Sierra Madre wind energy project could face challenges selling power in the desert southwest, officials told lawmakers in Casper last week.

The energy generated from the proposed 1,000-turbine site will be carried along a high power transmission line to California and the desert southwest.

California, however, is being difficult.

“We have a huge issue in California in that Californians would like to keep all of the development and buy all of their power from within their borders,” she said.

“We call it the missing buyer syndrome. The need is still there … we believe the market is there, but we are right now caught in a limbo.”

Clean Line Energy Partners, a Houston-based company that proposes to bring wind-generated power from Oklahoma and Texas to the Southeast along a $2.5 billion transmission line, says it could deliver power to TVA at less than 2 cents per kilowatt-hour.

But the utility has yet to commit to buying any of the 3,500 megawatts of wind-generated power Clean Line Energy will bring to the western edge of TVA's territory along its 720-mile transmission line from near Diamond, Okla. TVA said it doesn't need more power generation because of the stagnant demand for electricity in its seven-state region, and Johnson said TVA still would have to maintain or build other generation capacity to make up for the Clean Line energy when the wind doesn't blow.

"The price [from Clean Line Power], in and of itself, is a good price for wind," Johnson said. "But it actually costs us a lot more to import it and to make sure we have gas plants running or capable of running in case the wind doesn't show up."

Johnson estimates having the additional capacity to make up for when the wind doesn't blow or the sun doesn't shine typically adds at least 2 cents per kilowatt-hour to the quoted price of such renewable energy.

"At the moment, we have yet to conclude that [buying power from Clean Line Energy] is the right fit for what we are doing," he said.

"But I am mostly pro consumer, so we want what is the best price, the most reliable and the cleanest power for the consumer," he said. "Given our demand projections, we actually don't need any additional generating capacity at this time."

The Trump administration could help by pushing for an infrastructure package that would see the government “buying down a portion of the capacity” on big transmission projects so they can enter construction more quickly, or perhaps through an investment tax credit, Skelly suggests.

“All the ideas come down to a temporary underwriting of the project so you can get these things over the top, or some sort of tax mechanism.”

Dozens of developers are competing to offer Massachusetts the best price for long-term contracts to supply clean energy to hundreds of thousands of homes. But many of the projects face a challenge: convincing residents of northern New England that it's in their interest to host the Bay State's extension cord.

Offshore wind is still a relatively costly technology, but here's one advantage: You can build ocean-based windmills pretty close to the demand centers, and avoid all those long transmission lines.

"Because the system was designed with large, central-station generation as the primary source of electricity, significant amounts of new transmission may be needed to support renewable resources located far from load centers.216"

The studies (see Appendix B) that look into the distant future are exploratory only and represent initial investigations into how to implement high levels of VRE. They do not look into all the operational aspects of reliability due to the needed complex and computationally challenging modeling. Typical assumptions (sometimes implicit) include successful siting of (at times long multistate) transmission lines and new generation, sufficient new and existing economically viable conventional generation and other resources to support the VRE, institutional and market changes, and relevant grid modernization-type spending at both the transmission and distribution level. One study, for the ease of modeling, even assumes the nation’s 66 balancing authorities, including their governing boards and member states, would agree to one national joint dispatch). Some of these assumptions are non-trivial. These studies recognize that given enough time and money, power system engineers can make any resource and configuration reliable, as long as the laws of physics are not violated; whether the changes needed are indeed affordable, doable, and desirable may be a different question. Also, affordability was typically not in the scope of these studies.

Most of the contiguous United States’ wind power plants are installed in the center of the Nation, which has the best wind resources.

Technical and economic factors may drive power plant operators to run generators even when power supply outstrips demand. For example:
For technical and cost recovery reasons, nuclear plant operators try to continuously operate at full power.
Eligible generators can take a 2.2¢/kWh or $22/MWh[yyy] production tax credit (PTC) on electricity sold. This means that some generators may be willing to sell their output for as low as -$22/MWh to continue producing power. Typically, wind generators are the largest such group in any region.
There are maintenance and fuel-cost penalties when operators shut down and start up large steam turbine (usually fossil-fueled) plants as demand varies over a day or a week. These costs may be avoided if the generator sells at a loss to attract a buyer when demand is low.

As EIA notes, the PTC can create an incentive for wind generators to bid at negative prices. If other generators located at nodes in the areas affected by negative prices are unable or unwilling to reduce output, they will have to pay the negative price for their output. That scenario has unfolded on some buses in PJM, as outlined in comments to DOE from PJM staff:
Tax and subsidy policies have had an impact on the economics of certain types of generation. The Renewable Energy Production Tax Credit and renewable energy mandates have had the most significant impact on nuclear generation. Specifically, the nuclear and wind generation are competing to clear in the market during off-peak hours when wind resources are the strongest and load is reduced. In those off-peak hours, the production tax credit has created an incentive for renewable resources to bid negative prices as they must run in order to receive their payment from the federal treasury. Since 2014, PJM has seen prices go negative at nuclear unit buses in approximately 2,176 hours—representing 14 percent of off-peak hours.

RPS compliance costs were found to total $2.6 billion in 2014, averaging $12/MWh for VRE and equating to 1.3 percent of average retail electricity bills.ffff 451 The actual effects of zero-marginal cost electricity on consumers’ bills is situational, and growth in VRE can drive additional costs, including transmission and integration costs.452 453 Because many utility-scale VRE plants are built in locations distant from load centers, they sometimes require major transmission additions to connect the remote generation to the rest of the grid and to load centers. Over the past five years, a portion of the 24,000 miles of new transmission built (about twice the number of miles added from 2006–2010) and $102 billion invested to strengthen the grid and interconnect new generation has been made to interconnect VRE.454 455 Transmission investments (regulated or merchant) can increase bulk power costs and therefore increase customers’ retail bills to the extent that they are not offset by savings attributable to access to lower-cost generation or reduced congestion costs.

Studies on RPS compliance costs do not fully capture the “all-in” costs that the ratepayer (and taxpayers) ultimately bear. These other costs are harder to measure, but may not be insignificant. They may be harder to quantify for many reasons, such as having multiple drivers behind those investments and various distribution-level grid modernization investments (e.g., smart meters and others that are touted to aid VRE integration). New transmission (other than the direct transmission interconnection charged to the renewable generation project and thus reflected in their PPA), as well as effects of VRE variability on the dispatchable fleet, are other examples of costs often not included in grid integration cost studies. Costs of various tax and other subsidies are also not counted.

Numerous technical studies on electricity systems in most regions of the Nation have concluded that significantly higher levels of VRE can be successfully integrated without compromising resource adequacy.hhhh Demonstrating resource adequacy is essential, but achieving the modeled levels of VRE penetration requires a full consideration of “all-in” costs, land use, siting, and other environmental impacts; sustainable economics for non-wind and solar resources; for some studies, required changes at the distribution level; wholesale market design and organizational changes; spending on relevant transmission and distribution grid modernization activities; and ensuring all aspects of operational reliability.iiii These caveats are non-trivial, as they would be for any substantial major changes in the electric power system. However, these studies (particularly those examining high VRE levels) may often assume (or ignore) modeled conditions that could be difficult and/or costly to achieve in practice, such as a large transmission buildout that may face siting or other obstacles, ability of non-wind and solar plants to remain financially viable and thus available, institutional changes, or, for one study, synchronization of all three interconnections.

The challenge for building transmission continues to revolve around the three traditional steps involved, each of which can be time-consuming, involved, and complex: (1) demonstrating a need for the transmission project, also known as transmission planning, (2) determining who pays for the transmission project, also called cost allocation, and (3) state and Federal agency siting and permitting. FERC has taken steps to help with the first two, with reforms such as Order No. 1000, which remains a work in progress.258 259 260 261 262 Transmission planning entities, as well as regional state-based groups, are also contributing to improving these three necessary process steps. The current and past administrations, aided by various new Federal laws, have issued various Executive Orders and other initiatives to improve the processes involved in siting and permitting of transmission when Federal lands or waters are involved.
All three transmission building steps can be time-intensive and complex; in particular, siting and permitting for large networks or long multi-state lines is challenging. 263 264 265 The second necessary step of cost-allocation can be time-consuming as well. For example, large overlay networks now being built in MISO (“Multi-Value Projects”)266 and SPP (“Highway/Byway Plan”)267 required several years of sensitive negotiations among states brokered by the respective Organization of MISO States and SPP Regional State Committee to determine the cost allocation of each large transmission buildout.268 269

Fuel neutrality is essential for both monopoly-utility resource planning and competitive markets to manage risk and achieve reliability efficiently. Interventions to promote specific fuel types—such as bailouts for coal and nuclear or mandates and subsidies for renewables—skew investment risk and can undermine incentives for reliability-enhancing behavior (e.g., a public intervention to finance pipeline expansion removes incentives for the private sector to invest in fuel security). Fuel-specific subsidies and mandates replace individual choice with collective choice. This one-size-fits-all approach to risk mitigation ignores variances in individuals’ risk tolerances, results in high-cost risk mitigation, and creates perverse incentives for market participants by transferring risk and costs from the private to the public sector.

New technologies with very low marginal costs, i.e. VRE, reduce wholesale prices, independent of— and in addition to—the effects of low natural gas prices. To the extent that additional development of such resources is driven by subsidies and mandates, their price suppressive effect might place undue economic pressure on revenues for traditional baseload (as well as non-baseload) resources and could require changes in market design.

On modeling capacity factors for renewables: Each ISO and RTO calculates the on-peak contribution of renewable resources as a function of historic resource performance. Land-based wind plants are assumed to deliver four to 14 percent of nameplate capacity during peak summer afternoon periods, and solar resources are assumed to deliver between 10 percent and 80 percent of nameplate capacity. Note, however, that as the level of PV penetration increases, the cumulative amount of PV generation on summer afternoons is moving net load peak hour later.

Market designs may be inadequate given potential future challenges. VRE—with near-zero marginal costs and if at high penetrations—will lower wholesale energy prices independent of effects of the current low natural gas prices. This would put additional economic pressure on revenues for traditional baseload (as well as non-baseload) resources, requiring careful consideration of continued market evolutions.

Natural gas-fired generation has grown nearly continuously since the late 1980s (see Figure 3.19) for several key reasons. These plants have low capital costs and are, in general, relatively less expensive than some competing technologies.108 They are also much less land-intensive than many other types of generation, and thus often can be more easily sited in urban areas near electric demand.109 Similarly, natural gas pipelines can be built more quickly than electric transmission lines (in most states) because they have a comparatively streamlined permitting process, which often has made it easier for a plant developer to build a new gas-fired plant near a large electric load than to build a power plant farther away and transmit its electricity to large load centers by wire.dd

Interstate natural gas pipelines can often be built more quickly than transmission lines because the pipeline owners, once granted a FERC-issued certificate of public convenience and necessity, have eminent domain power under section 7(h) of the Natural Gas Act and the procedures set forth under the Federal Rules of Civil Procedure (Rule 71A). By contrast, electric transmission developers are dependent on states to grant eminent domain authorization.

Former FERC Commissioner Tony Clark summarizes today’s changing demands on centrally-organized markets: “Affordable power was the goal when markets were created. The current markets are still procuring affordable power, but many state public policy makers no longer see that as the only goal [...] other public policy goals [include...] incenting in-state jobs, promoting ‘green’ energy or other politically favored resources, preserving carbon-free resources, and retaining substantial tax revenues to state and local government.” Clark goes on to say, “[Markets] were never designed for job creation, tax preservation, politically popular generation, or anything other than reliable, affordable electricity.”

“We will review the order in detail to determine next steps for the project,” adds Skelly. “We are currently assessing all existing authorities available to move the Grain Belt Express project forward, including but not limited to legal appeals.”

Clean Line executives said Wednesday that they were weighing their options for the Grain Belt Express power line, though they acknowledged that the “legal and regulatory conundrum” could add many months or years to the project if they decide to keep trying.

"So, the Grain Belt Project will deliver enough power for over a million homes, and will do so at costs that are extremely competitive with wind energy that is clean and renewable.”

“We absolutely want to do the project,” said Mark Lawlor, development director for Grain Belt Express. But he added: “Unfortunately, the message that we’re getting from Missouri is that investments of these kind might be better spent in other places.”

Lawlor said the four commissioners’ belief that the project was worthwhile but not approvable under state law “makes for an interesting argument” if Clean Line decides to instead seek federal permission to proceed.

Clean Line director of development Mark Lawlor said another hearing would be sought, but that the company also was exploring legal options.

He added that Clean Line would push ahead with the project, despite the setback in Missouri.

“This is a Missouri problem, it’s not just a Grain Belt problem. This says any transmission line looking to build in Missouri cannot set foot on the commission’s doorstep until there’s permission from counties for a road permit,” said Lawlor.

“It’s too important to our country, and to our energy future, to just walk away,” said Lawlor. “This project is just as valuable today as when we started and probably more so.”

The project’s developers and other supporters harshly criticized Wednesday’s PSC ruling.

“It’s going to apply to future infrastructure projects — not just ours, but anyone who wants to come to Missouri and build transmission lines or pipelines, they’re gonna pay attention to this,” said Mark Lawlor, vice president at Clean Line. “It sends a bad signal to the marketplace.”

He argued that Grain Belt Express and projects of statewide significance should be decided by the PSC.

“It’s certainly not what the legislature intended,” Lawlor said. “It’s certainly not how the commission has worked in its 113-year history, but that’s somehow where we found ourselves today.”

Lawlor said Clean Line would need time to determine its next course of action.

A lawyer representing clean-energy interests said that another appeal is a near-certainty. Mark Lawlor, Clean Line’s vice president for development, wasn’t quite as definite.

“I think it’s sort of placed the burden on Clean Line to go ask the courts to sort this out,” he said. “Because of this legal quagmire, the project can’t move forward. It’s a broken system. It’s a problem for Missouri.”

Lawlor said there are a few options that he and his staff are evaluating. One is to essentially take the case back to the state appeals court – the same body that took the position that in part has led to this “quagmire,” as Lawlor called it.

There is actually a chance that the same court that ruled against Clean Line’s interests could see things differently, according to Renew Missouri’s James Owen.

“There are aspects of this that haven’t been presented before,” he said. “We can point out things that haven’t been thought about.”

The legislature is another avenue, according to Lawlor. He suggested they might want to study the pertinent law and ask themselves, “Is this what we meant to do here? Is this what we want, to have county commissions decide which infrastructure moves forward in the state?

“It would be in legislature’s interests to sort this out.”

There is also a federal avenue through which Lawlor said private developers can partner with the Department of Energy to develop infrastructure.

But Lawlor claims that the issue goes beyond Clean Line’s desire to build a high-voltage transmission line across Missouri. The new administration of Gov. Eric Greitens “has made a point of saying, ‘Missouri is open for business, we want investment in our state.’

“This decision runs counter to that.” As it now stands, he predicted that, “Other investors are going to look at Missouri and this will enter into their decision as to whether this is a good place to invest money.”

“It’s impossible if you’re building a multi-state transmission line to get agreements from all 30 counties that you might cross,” said Michael Skelly, the president of Houston-based Clean Line, which is planning about $9 billion of power lines across the Great Plains, Midwest and the Southwest. 

Clean Line has at least three options it is considering, according to Skelly. It can appeal the decision, seek a change of state law or bypass the state by asking the U.S. Energy Department to approve it.

“If none of those three work, we’re toast,” Skelly said in an interview Wednesday.

Clean Line’s other options, said spokesperson Sarah Bray, include asking the PSC for a rehearing, working with the state’s legislature to revise pertinent laws or seeking U.S. Energy Department approval under Section 1222 of the 2005 Energy Policy Act. The latter would authorize the department to take part in “designing, developing, constructing, operating, maintaining or owning” new transmission.

“The project is certainly not dead,” Bray said.

Bray told RTO Insider that Clean Line was “encouraged by the PSC’s determination that the project is in the public interest and will benefit the State of Missouri.”