WASHINGTON, May 25 (TNSrep) -- The Consumer Energy Alliance issued an 11-page white paper in March 2023 entitled "Right of First Refusal for Electric Transmission Projects: Delivering Resiliency and Affordability to Indiana Consumers."
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Rights of First Refusal for Electric Transmission Projects
Transmission reform has become a key policy item at both the federal and state level in recent years, as the national push toward new forms of clean generation increasingly demands a rethinking of how transmission has traditionally been planned and developed. While the policy zeitgeist over the past two decades has been to foster greater "competition" in these processes, recent experience has shown that this may not always be the best approach to serving essential energy policy goals when it comes at the expense of the timely, coordinated, and cost-effective expansion of the grid.
The Federal Energy Regulatory Commission's ("FERC") 2011 elimination of the federal right of first refusal ("ROFR") for incumbent transmission providers has driven this paradoxical outcome. For the last decade-plus, cumbersome processes imposed by this change have hamstrung the development of new regional and inter-regional transmission facilities--transmission critically needed to support the clean energy transition, manage consumer costs, and address concerns about grid resiliency and resource adequacy. Some states, like Indiana, have worked to bridge the gap by enacting their own state ROFRs over the years, and FERC itself is now considering rolling back its federal ROFR policy. These shifts reflect a reality that has become increasingly apparent as the shortcomings of the competitive transmission process have emerged--rather than being backward and anti-competitive, granting incumbent utilities a ROFR to build new transmission can foster better outcomes for customers and the grid.
In the end, ROFRs benefit consumers by ensuring transmission is developed based on realistic cost estimates and eliminating the need for other investments or payments necessary to maintain reliability in the absence of the development of the transmission. At a time when this country needs transmission, revisiting the need for ROFRs at the state level is imperative--a point underscored by FERC itself doing so at the federal level.
Overview and Background
In the transmission context, a right of first refusal, or "ROFR," affords an incumbent transmission provider (i.e., any entity developing a transmission project within its own retail distribution service territory or footprint, including incumbent public utilities) the right to construct new transmission facilities within its service territory before those facilities may be opened to other potential developers. Should the incumbent transmission provider choose not to pursue a needed project that has been identified through a coordinated planning process, the regional planning authority could then solicit bids from non-incumbent transmission developers (i.e., transmission developers that do not have a retail distribution service territory or footprint, or that propose a transmission facility outside of their existing retail distribution service territory or footprint) to develop and build the project.
Historically, the existence of a federal ROFR meant incumbent transmission providers possessed ROFR rights for all new transmission projects built in their service territory. A series of FERC orders beginning in the mid-1990s aimed at removing barriers to competition in the bulk power market gradually led to the issuance of Order No. 1000/1 in 2011, which removed this right for the construction of certain new transmission facilities under FERC's jurisdiction.
FERC laid the groundwork for Order No. 1000 in 2007, when it issued Order No. 890/2 requiring all transmission providers to develop and implement a transmission planning process that would satisfy nine principles: (1) coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; (7) regional participation; (8) economic planning studies; and (9) cost allocation for new projects. FERC intended for the new requirements to remedy perceived opportunities for undue discrimination in the expansion of the transmission system at both the local and regional level./3
In later issuing Order No. 1000, FERC intended to build on Order No. 890 "to improve transmission planning processes and cost allocation mechanisms under the pro forma Open Access Transmission Tariff (OATT) to ensure that rates, terms and conditions of service provided by public utility transmission providers are just and reasonable and not unduly discriminatory or preferential ... in light of changing conditions in the industry."/4 FERC found that the additional reforms were needed beyond those made in Order No. 890 to "address opportunities for undue discrimination by public utility transmission providers."/5
One of Order No. 1000's most significant changes was to open regional and interregional transmission projects to competitive bidding processes, on the general assumption that ensuring non-incumbent transmission developers more of an opportunity to participate would promote more cost-effective, innovative, and timely transmission development./6 To that end, FERC opted to eliminate incumbent transmission owners' federal ROFR to develop and build transmission facilities falling within the scope of the order. FERC explained that ROFRs "create opportunities for undue discrimination and preferential treatment against non-incumbent transmission developers within existing regional transmission planning processes," and that it had "a responsibility to consider anticompetitive practices and to eliminate barriers to competition."/7
FERC also drew a clear line distinguishing between "local" transmission planning processes (performed by public utility transmission providers for their individual retail distribution service territory) and "regional" transmission planning processes (performed to address broader needs across transmission planning regions). Order No. 1000 took care to specify that its regional planning and competitive bidding requirements were "not intended to appropriate, supplant, or impede any local transmission planning processes that public utility transmission providers undertake,"/8 nor were the competitive bidding requirements intended to apply to local transmission facilities./9 Apparently recognizing that such cumbersome requirements would not suit all types of projects, FERC allowed incumbent transmission owners to maintain their existing federal ROFRs for: (1) local projects where the incumbent does not seek to share the costs of those projects through regional allocation; (2) upgrades to the incumbent's existing assets; and (3) projects on existing rights-of-way.10 FERC has since also permitted exemptions for projects addressing immediate reliability needs.
Most importantly, Order No. 1000 deferred to the states' well-established authority to regulate the siting, construction, and operation of transmission facilities located within their borders,11 leaving open the possibility for states to reinstate their own ROFR requirements for facilities that would otherwise by default be subjected to Order No. 1000's competitive bidding requirements. Put another way:
Eliminating a federal right of first refusal in [FERC]-jurisdictional tariffs and agreements does not ... result in the regulation of matters reserved to the states, such as transmission construction, ownership or siting. The reforms are focused solely on public utility transmission provider tariffs and agreements subject to [FERC's] jurisdiction. ... [FERC] acknowledges that there may be restrictions on the construction of transmission facilities by non-incumbent transmission providers under rules or regulations enforced by other jurisdictions. Nothing in this Final Rule is intended to limit, preempt, or otherwise affect state or local laws or regulations with respect to construction of transmission facilities, including but not limited to authority over siting or permitting of transmission facilities./12
In the years since Order No. 1000, a number of states across a swath of the Midwest have chosen to reinstate ROFR requirements to varying degrees, including Arkansas, Iowa, Indiana, Michigan, Minnesota, Montana, Nebraska, North Dakota, Oklahoma, South Dakota, and Texas./13 The existing Indiana statute is a good example of an effective ROFR that achieves the benefits outlined in this paper. Of note, Indiana's ROFR provision is codified in Chapter 38 of the state code, which is entitled "Transmission Reliability." This title is fitting because that is exactly what the law furthers, with the added benefit of reducing costs due to congestion and other factors that ultimately would be borne by customers where transmission does not get built--or is needed and cannot get built because the absence of a ROFR can detract from the ultimate objective of building transmission and providing reliable service. However, more benefits may accrue to Indiana consumers because of House Bill 1420. Ensuring ROFR provisions apply to all transmission projects in Indiana, as well as requiring incumbent transmission providers to competitively bid for contracted services, allows for investments to be made to safeguard the resiliency of Indiana's grid at the most affordable cost to consumers.
Indeed, other states are taking cues from states like Indiana. For example, Mississippi enacted its own ROFR law this year,/14 and Kansas and Missouri are currently in the midst of deciding whether to do so. Others will likely follow as states increasingly begin to see the benefits of safeguarding their ability to regulate the provision of safe, reliable, and cost-effective electric service within their borders.
But states are not the only entities that appear to be realizing the valuable role transmission ROFRs can play--FERC itself has begun to reconsider its own position on ROFRs in recent technical and rulemaking dockets, despite continuing to tout the benefits of increased competition. Indeed, FERC's recent Notice of Proposed Rulemaking ("NOPR") in Docket No. RM21-17 identified long-standing concerns about the processes established under Order Nos. 890 and 1000--including the real-world negative impacts that the removal of the federal ROFR has had on the planning and buildout of critical transmission infrastructure. FERC has proposed new rules that would partially roll back its elimination of the ROFR, allowing incumbent transmission providers a "conditional" ROFR subject to joint ownership requirements./15 While it remains to be seen how these proposed rule changes will play out, the time is clearly right to reevaluate the current ineffective approach to getting transmission developed--and whether ROFRs might play a role in jump-starting that process.
The Benefits of ROFRs
From both a customer and grid perspective, transmission ROFRs can yield significant benefits over full competitive processes. There is no such thing as true free market competition when it comes to the electric transmission industry; even supposedly competitive markets ultimately demonstrate monopoly tendencies. This is where it is important that traditional regulated transmission providers be permitted to perform the role they were designed for. Incumbent utilities and cooperatives that serve retail customers within a designated service territory are very differently situated from independent competitive transmission developers, which often are not based in the same state as the facilities they would be competing to build. Incumbent providers' typically long history of serving a particular area and engaging with local communities to address their specific concerns means that they tend to have a much greater degree of established knowledge that competitive developers simply cannot replicate. The information asymmetry is even stronger in states with fully vertically integrated utilities, which benefit from visibility into all interrelated aspects of the electric generation, transmission, and distribution processes.
Moreover, unlike competitive developers, incumbent utilities are state-regulated entities with a duty to serve in their state-sanctioned service territory subject to oversight by regulators--and in some cases, such as in Minnesota, utilities can even be compelled by regulators to build projects they would not otherwise build if those projects are deemed necessary for the public interest. This is all part of the reciprocal obligations that exist between regulators and utilities under the "regulatory compact." These utilities are accustomed to regularly going before state regulators to justify the costs and benefits of their projects--including actual costs and benefits, not just those forecasted at the project planning stage. Should reliability or other concerns arise, utilities can be called before regulators and held to task where appropriate on the facilities they build and operate. Competitive developers have no such requirement to answer to the retail customers and communities ultimately impacted by the facilities they develop, nor to state regulators for cost overruns or other issues that may arise after the project solicitation is won.
This distinction is also important from a consumer perspective. As discussed in more detail below, illusory "cost caps" have been a hallmark of competitively bid transmission projects--cost caps that are subject to well-utilized exceptions that ultimately result in higher upfront costs to consumers or, because of corner-cutting on the front end, can lead to higher operations and maintenance or additional future capital investment over time. Well-formulated transmission projects deliver benefits to consumers by reducing congestion costs, providing resource adequacy and reliability benefits that may otherwise require generation investments or reliability-must-run ("RMR") contracts,/16 and avoiding the need for costly uplift payments. PJM, a large market operator, defines uplift payments as payments "made to market participants for operating a unit under specific conditions as directed by PJM to ensure that they recover their total offered costs when market revenues are insufficient or when their dispatch instructions diverge from their dispatch schedule," and notes that transmission congestion is a driver of uplift payments: "Transmission congestion impacts the commitment, dispatch and prices on the system and can result in uplift charges."/17 Any transmission project can provide these benefits, the argument goes from ROFR opponents. Industry data shows, as discussed in more detail below, that ROFRs can help result in more accurately priced proposals that provide cost certainty for consumers and deliver these benefits, with the added upside of the continued oversight of incumbent utilities by state regulators with a finger on the pulse of all activities undertaken by these entities.
All of this means that incumbent utilities are uniquely positioned to further state policy goals as compared to unregulated transmission developers that do not have a local presence in the state or its communities. Minimal local accountability makes competitive developers a much riskier prospect when it comes to delegating the development, construction, and overall management of high-cost, critical transmission facilities. Unfortunately, as discussed below, this dynamic can also artificially play to the incumbent utility's disadvantage when pitted against developers in a competitive solicitation process. Competitive developers may indeed have certain industry knowledge or tools that could help innovate the grid and respond to today's changing system needs, but positioning them as potential replacements for incumbent transmission providers by eliminating ROFR protections is an unwise trade-off. A better way to capitalize on that potential is to foster greater partnership and collaboration between developers and the regulated utilities already integrated into the state, not impose a veneer of competition where it is ill-suited to serve the public interest.
Finally, it is worth noting that the existence of ROFRs can help ease the transition to greater transmission cooperation and coordination at the regional level, by mitigating incumbent transmission providers' reasonable concerns about giving up control over their systems to a third-party entity. By allowing utility transmission providers to become willing partners in the regionalization process rather than forcing them onto the defensive, the reliability of the entire grid can benefit.
Competition operating within a functioning framework is good. But when it comes to natural monopolies like the electric transmission industry, competition for the sake of competition is not always the approach that leads to the desired end results--whether the goal is improved reliability, greater integration of clean energy, more coordinated transmission development, or any of the other efficiencies that expanded competition was meant to achieve. The biggest lesson from Order No. 1000 and its failure is that the natural monopoly characteristics of transmission make "competition" an impediment to building transmission--rather than creating incentives to build it. In the end, working with the industry's unique characteristics using ROFRs and other effective regulatory constructs is more likely to encourage the kind of transparency, openness, and regional cooperation that competition advocates seek.
Debunking Common Myths About ROFRs
ROFR opponents frequently point to one 2019 report by the Brattle Group/18 in support of claims that ROFRs increase costs to customers, contribute to project delays, and stymy innovation in the transmission industry. Brattle's study estimated the potential cost savings from expanding competitive processes at 20-30 percent,/19 and cited the limited number of competitively bid projects since the adoption of Order No. 1000 (only three percent of nationwide transmission investments between 2013 and 2017)20 as evidence of a lack of competition in electric transmission and the need for FERC to expand the types of projects subject to competitive processes deeper into the grid. Brattle chalked this up to FERC's "restrictive regional planning criteria,"/21 and claimed that expanded transmission competition could result in billions of dollars of savings over five years/22 while promoting more innovative transmission solutions and benefitting from developers' cost containment mechanisms to protect customers./23 The report also argued that competitively-developed transmission projects had been proposed at an average 40 percent lower cost than incumbent transmission owners' lowest-cost proposals, and alleged that completed costs for projects developed by incumbent transmission owners across the country had exceeded initial project cost estimates by an average of 34 percent./24 The problem is that the Brattle's calculations and assertions rely on both unsound methodology and questionable assumptions, as detailed in a report released later that year by Concentric Energy Advisors;/25 this includes relying on cherry-picked data points and early-stage cost estimates for comparison purposes./26 Concentric's calculations, by contrast, tell a very different story./27 As Concentric's report points out, bidders at the competitive solicitation stage do not yet have solid, reliable information on which to base their cost estimates. The information asymmetry between incumbent utilities and competitive developers, as discussed above, can lead to competitive developers offering unrealistically low-priced bids aimed largely at winning the solicitation,/28 whereas utilities may have more reason to submit a more realistic proposal that will hold up over time for cost recovery purposes--meaning bid prices may differ widely from the actual final costs to construct a project, and potentially more qualified competing proposals may be passed over. Underpriced bids may sound good in theory, but they can lead to the inability to finance or complete projects--a phenomenon seen in multiple facets of the industry--and leave customers and state policymakers without the benefit of the projects they were depending on.
Competitive developers' bids may also offer cost caps as a purported cost containment measure; however, these caps frequently provide for risk-shifting exclusions that allow for final project costs to exceed those cost caps, and often for known high-risk cost categories./29 Even if these cost caps were firm and enforceable, developers may be incentivized to focus on cutting construction costs to meet overly ambitious cost caps, at the possible expense of the long-term reliability and cost-effectiveness of the facility. In that case, long-term maintenance and repair costs could outstrip any upfront savings realized due to the cost cap. The offer with the lowest upfront cost may not prove to be the best deal for customers in the long run, compared to if the utility had been allowed to build the project under more realistic cost projections./30 Again, it is worth noting that unlike regulated utilities, competitive developers are not answerable to state regulators for their management of a project once they are selected to build it, so they have little incentive to present more realistic proposals from the outset. Complex, capital-intensive transmission projects require contractual complexity and adaptivity that simplistic competitive models are insufficient to contain. Cost caps and competitive solicitations sound good in the abstract, yet once the complexities of a real-world project emerge the problems of opportunistic behavior and information insufficiency arise.
Most important, Concentric observed that the Order No. 1000 competitive process itself has not necessarily been conducive to effective development of transmission projects. Competitive solicitations for new transmission projects are heavily time- and resource-intensive, with the delay between identification of a transmission need through the regional planning process and selection of a winning project bid through the solicitation process over the 2013-2019 period ranging from several months at the low end to over four years at the high end, with an average delay of over 500 days.31 These delays increase administrative, planning, and potentially litigation costs, and delay projects' ability to deliver critical grid benefits addressing the identified transmission need.
In addition, while little data was available at the time of Brattle's 2019 report regarding actual outcomes for completed projects that had been subjected to competitive bidding,/32 a more recent Concentric report released in 2022/33 had even more unfavorable observations about the Order No. 1000 process with the benefit of final project data. Studying several completed or near-completed competitive projects and their final costs, Concentric found a pattern of cost overruns--67 percent over the initial cost cap for the Empire State Line in New York; 11 percent over the median bid for the Duff-Coleman Line in Indiana and Kentucky; and 61 percent over the cost cap for the Ten West Link project in California, among other issues./34 Many of these cost overruns were due to factors that may have been foreseen by incumbent transmission developers familiar with the area, such as regulatory delays, routing issues, and environmental challenges./35 For the projects examined, Concentric also noted delays of between 287 and 950 days from identification of need to bid selection, with in-service dates delayed in some cases years beyond the required dates identified through the regional planning process./36
Put simply, Brattle's 2019 report identified a problem--that Order No. 1000 has not meaningfully expanded the use of competitive processes for transmission development in the ensuing years--but failed to identify one of the major causes of that problem. The burdensome, time-consuming, and often unpredictable processes to which competitively bid projects are currently subjected have been the real barrier to driving more regional transmission projects, not "anti-competitive" ROFRs. As Concentric ultimately found, further broadening the scope of FERC's competitive solicitation requirements will not yield the improved results proponents think it will; the evidence to date points only to further delays and cost overruns for critically needed transmission projects, to the detriment of both grid reliability and customers. The wider the Order No. 1000 net is cast across lower-voltage parts of the grid, the more likely it is to start ensnaring true reliability projects that cannot afford to absorb the long delays of the solicitation process. FERC deliberately left a path open for utilities to get these types of projects built outside of the Order No. 1000 requirements,/37 and it did so for good reason.
As state ROFRs have proliferated in response to Order No. 1000, arguments have also arisen that these policies unfairly impose costs on other states, as some of the projects subject to the ROFR may be regional projects partially paid for by neighboring states' customers under a regional cost allocation. But nearly all state ROFRs that have been tested in the courts have withstood those tests (the exception being Texas's 2019 ROFR legislation currently before the U.S. Supreme Court). Included in that list is Minnesota's ROFR statute, which was upheld by the 8th Circuit Court of Appeals in the face of accusations that it discriminated against or unduly burdened interstate commerce. On review by the court these arguments were found to be unavailing./38 Like FERC, the court in that case deferred to states' broad latitude to regulate the provision of electric service within their borders in upholding Minnesota's ROFR, rather than weighing in directly on the purported "costs" and "cost-shifting" caused by the existence of the ROFR requirements./39
Such cost shifting arguments are a common refrain among critics of state ROFRs. But while these arguments may carry a superficial "pro-competition" appeal, they rest on the false premise that subjecting transmission projects to Order No. 1000 processes will necessarily drive cost savings and efficiency gains--whereas the actual results borne out over the last ten years suggest anything but. Confronted with the realities of the Order No. 1000 experiment, complaints of cost shifting and utility obstructionism through the use of ROFRs appear to be at best hollow, and at worst a distraction from the ballooning costs and delays that have in fact been caused by mandated bidding processes. If one assumes that states avoiding these processes may in fact lead to long-term cost savings and more timely resolution of transmission needs, as discussed above, neighboring states would share in the benefits.
Perhaps the loudest criticism of ROFRs is that they pander to monopoly utility demands while impeding the kind of large-scale, multi-state transmission buildout that will be needed to bring higher levels of intermittent renewables online in the coming years. There is no doubt that greater coordination at the regional and inter-regional levels will be needed to decarbonize the grid while safeguarding reliability. But far from fostering that coordination, the stringent bidding requirements imposed by Order No. 1000 for regionally allocated projects can discourage cooperation by incentivizing utilities to pursue more limited local transmission projects, even where larger regional projects may offer a more effective long-term solution. This is an unsurprising response considering the burdensome processes and uncertainties that regional projects have been subjected to since the elimination of the federal ROFR--and the grid is now paying the price for this perverse incentive.
FERC itself is aware of these problems. Its NOPR issued last year in Docket No. RM21-17, in which FERC proposed to reinstate a conditional federal ROFR, made several statements to that effect:/40
"We are concerned that today's processes place unintended emphasis on the development of local transmission facilities or other transmission facilities not subject to competitive transmission development processes, potentially at the expense of regional transmission facility development, given trends observed since the issuance of Order No. 1000."/41
"[R]ecent transmission investment trends suggest that despite the increased investment in transmission facilities overall, in many transmission planning regions there has been comparatively limited investment in transmission facilities selected in a regional transmission plan for purposes of cost allocation as a result of a competitive process; transmission investment has instead largely been concentrated in transmission facilities generally not subject to competitive transmission development processes ...as opposed to investment in regional transmission facilities ... that serve a wider set of transmission needs[.]"/42
"We believe that ... allowing public utility transmission providers to propose conditional rights of first refusal ... may help public utility transmission providers address potentially flawed investment incentives that may be restraining otherwise more efficient or cost-effective regional transmission facility development."/43
FERC's December 2022 request for comments in Docket No. AD22-8 (an ongoing docket opened in 2022 to discuss transmission planning and cost management for transmission facilities developed through local or regional transmission planning processes) also appears to acknowledge flaws in the regional transmission planning and competitive bidding process. Notably, FERC asks whether the approach used in evaluating the costs of potential regional and interregional transmission projects:
Can or should ... be designed in order to maximize benefits to consumers, as opposed to focusing only on reducing costs? For example, a given project modification might increase up-front costs of the projects, but lower costs for customers in the long-run by enhancing project efficiency and thereby increasing anticipated economic benefits. Should any variance analysis mechanism required by [FERC] be designed in a manner that encourages such investments, or at a minimum does not inadvertently discourage them?/44
FERC is clearly coming to realize that just minimizing construction costs may not always be the best solution for customers or the grid in today's transmission planning landscape. It also seems to recognize that trying to treat the electric transmission industry as though it were, or should be, a true free market environment, rather than making use of more traditional regulatory tools, can in fact lead to unintended negative outcomes for both customers and the grid.
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1 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 136 FERC
61,051 (2011) ("Order No. 1000").
2 Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 12266 (Mar. 15, 2007) ("Order No. 890").
3 Order No. 890 at PP 444-561.
4 Order No. 1000 at P 1. Since the issuance of FERC Order No. 888 in 1996, transmission service providers have been required to offer non-discriminatory, open access transmission service to all parties on a comparable basis to the transmission service provided to their own generation through the establishment of open access transmission tariffs, or "OATTs."
6 Order No. 1000 expanded on Order No. 890's transmission planning requirements by directing public utility transmission providers to work within their transmission planning regions to create regional transmission plans identifying transmission facilities needed to meet reliability, economic, and public policy requirements as defined in the order, in alignment with the principles set forth in Order No. 890 and with "fair consideration of lines proposed by non-incumbents." Order No. 1000 at PP 47, 68-84. Identification of a transmission facility/project in a regional transmission plan does not automatically make it "regional" for Order No. 1000 purposes unless the plan also selects it for regional cost allocation. Id. at PP 63-64. Conversely, if any costs of a new transmission facility/project are allocated regionally, then the facility/project is considered regional even if it is built entirely within a single transmission provider's retail distribution service territory or footprint. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, 141 FERC
61,044 at PP 42, 52 (2012).
7 Order No. 1000 at P 286.
8 Order No. 1000 at P 161.
9 Order No. 1000 at PP 226, 258. "Local" transmission facilities are those which are not designated as "regional" in a regional transmission plan for cost recovery purposes.
10 Order No. 1000 at PP 318-319.
11 Order No. 1000 at P 253 n.231.
12 Order No. 1000 at P 287.
13 Ark. Code Sec. 23-3-205; Iowa Code Sec. 478.16; Ind. Code Sec. 8-1-38-9; Mich. Comp. Laws Sec. 460.593; Minn. Stat. Sec. 216B.246; Mont. Code Sec. 69-5-202; Neb. Rev. Stat. Sec. 70-1028; N.D. Century Code Sec. 49-03-02; 17 Okla. Stat. Sec. 292; S.D. Codified Laws Sec. 49-32-20; Tex. Util. Code Sec. 37.056(e).
14 Mississippi S. B. No. 2341 (2023), available at http://billstatus.ls.state.ms.us/documents/2023/pdf/SB/23002399/SB2341SG.pdf.
15 Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 179 FERC
61,028 at PP 358-382 (2022) ("2022 NOPR").
16 Generally speaking, "RMR contracts require power plants to continue operating to meet systemwide and local capacity needs for the term of the agreements in return for additional compensation." Hudson Sangree, CAISO Extends RMR Contracts for Gas Plants, RTO Insider (Sept. 5, 2022), https://www.rtoinsider.com/articles/30743-caiso-extends-rmrcontracts-gas-plants.
17 Drivers of Uplift, PJM, https://www.pjm.com/markets-and-operations/energy/drivers-of-uplift (last visited Mar. 14, 2023).
18 Johannes P. Pfeifenberger, et al., Cost Savings Offered by Competition in Electric Transmission: Experience to Date and the Potential for Additional Customer Value, The Brattle Group (Apr. 2019), https://www.brattle.com/wpcontent/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf ("Brattle Report").
19 Brattle Report at 1, 10.
20 Brattle Report at 18, 44.
21 Brattle Report at 1, 6.
22 Brattle Report at 1, 13.
23 Brattle Report at 30, 40, 46.
24 Brattle Report at 29, 40.
25 Emma Nicholson, et al., Building New Transmission: Experience To-Date Does Not Support Expanding Solicitations, Concentric Energy Advisors (June 2019), https://ceadvisors.com/wp-content/uploads/2019/06/CEA_Order1000report_final.pdf ("2019 Concentric Report").
26 2019 Concentric Report at 3-6, 18-24.
27 2019 Concentric Report at 6-13, 38.
28 2019 Concentric Report at 16.
29 2019 Concentric Report at iv, 15-18.
30 2019 Concentric Report at 16-17.
31 2019 Concentric Report at 25-28, 30-32.
32 2019 Concentric Report at 14-15.
33 Competitive Transmission: Experience To-Date Shows Order No. 1000 Solicitations Fail to Show Benefits, Concentric Energy Advisors (Aug. 2022), https://ceadvisors.com/wp-content/uploads/2022/08/Competitive-Transmission-ExperienceTo-Date-Shows-Order-No.-1000-Solicitations-Fail-to-Show-Benefits.pdf ("2022 Concentric Report").
34 2022 Concentric Report at 15-31.
35 2022 Concentric Report at 3, 18.
36 2022 Concentric Report at 32-35.
37 Order No. 1000 at PP 262-263.
38 LSP Transmission Holdings, LLC v. Sieben, 954 F.3d 1018, 1026-31 (8th Cir. 2020).
39 Id. at 1031 ("Minnesota enacted its ROFR law, in part, in response to the uncertainty produced by FERC's Order 1000. Its goal was 'to preserve the historically-proven status quo for the construction and maintenance of electric transmission lines.' ... This goal is within the purview of a State's legitimate interest in regulating the intrastate transmission of electric energy.").
40 One FERC Commissioner also raised similar concerns in his partial dissent from Order No. 1000, saying that under Order No. 1000, "local projects that have their costs assigned regionally generally cannot maintain a right of first refusal, thus discouraging transmission owners from seeking regional cost allocation for their local projects. For this reason, instead of encouraging more regional cooperation, the rule could ultimately discourage such cooperation by encouraging more local transmission projects." Order No. 1000, Partial Dissent of Commissioner Moeller, at 2-3. The experience implementing Order No. 1000 since 2011 indicates Commissioner Moeller's concerns were well-founded.
41 2022 NOPR at P 377.
42 2022 NOPR at P 344.
43 2022 NOPR at P 353.
44 Docket Nos. AD22-8 and AD21-15, Notice Inviting Post-Technical Conference Comments at 7 (Dec. 23, 2022).
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The white paper is posted at: https://consumerenergyalliance.org/cms/wp-content/uploads/2023/03/ROFR-Delivering-Affordability-and-Resiliency-to-Indiana-Consumers.pdf
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