Skip to content

The FERC (Inter)connection: PJM files for and FERC issues proposed reforms of the interconnection process

Related people
Image of Geroge (Chip) Cannon
George Chip Cannon


Washington, D.C.

View profile →

Image of Porter Wiseman
Porter Wiseman

Senior Counsel

Washington, D.C.

View profile →

13 July 2022

June was an interconnection milestone. On June 14, PJM Interconnection, L.L.C. (“PJM”) filed a “comprehensive reform” of the interconnection process set forth in its Open Access Transmission Tariff (“OATT”).1 Two days later, during its June Open Meeting, Federal Energy Regulatory Commission (“FERC” or the “Commission”) announced a Notice of Proposed Rulemaking (the “Interconnection NOPR”)2 that proposes to overhaul the Commission’s pro forma interconnection procedures and agreements across the U.S.3

Both PJM and FERC propose a transition from the first-come/first-served serial interconnection study process established almost two decades ago in FERC’s Order No. 20034,  to a first-ready/first served cluster study process. The cluster study model is not new—a number of transmission providers, including Independent System Operators and Regional Transmission Organizations (“ISO/RTOs”) such as the California Independent System Operator Corporation, Southwest Power Pool, Inc. and Midcontinent Independent System Operator, Inc., have already adopted a cluster study process. But it is a major change for PJM and, by releasing a NOPR, FERC is signalling its intent for the cluster study process to be mandatory for all FERC-jurisdictional transmission providing utilities.

Both proposals set forth a similar approach to interconnection queue management and interconnection studies, but are different in scope and level of detail. The PJM Proposal, which PJM seeks to implement as is, was filed under Section 205 of the Federal Power Act (“FPA”)5 and is a “fully-baked” revision of PJM’s OATT. It is narrowly focused on implementing a shift from a serial study process to a cluster study process, and almost all of its design features support that transition. The Interconnection NOPR, initiated by FERC under Section 206 of the FPA6, is more ambitious and not as fully developed. It preliminarily finds the interconnection processes and pro forma agreement set forth in Order No. 2003 to be unjust and unreasonable7,  and mandates not only a shift to a cluster study process, but a range of other changes intended to streamline the interconnection process and offer more alternatives to developers. However, in keeping with its status as a NOPR, FERC defers a number of details to the rulemaking process, inviting comment from affected parties before crafting a Final Rule.

Clogged and backlogged

A transparent, efficient process for generator interconnection is critical to an open access transmission model, and has been the de facto driving force behind transmission expansion.8 But interconnection delays have become an increasingly severe problem in generator development. The deadlines for completing interconnection studies are aspirational at best, and are routinely missed by months or years.9 As of the end of 2021, the nation’s interconnection queues were clogged with over 1,400 GW of planned generation and storage,10 which far exceeds both the plausible capacity of the transmission system or peak load requirements for the foreseeable future. PJM alone had 2,700 projects, representing more than 250 GW, in its interconnection queue as of May 2022.11 Without reform, the problem only promises to get worse, as the number of projects in the queue continues to grow exponentially.12 “The volume of New Service Requests more than tripled in the past three years,” PJM notes.13 These delays are not only frustrating—they can result in missed opportunities, forgone tax credits, breaches of contract, and difficulties acquiring components for the planned facility as estimated prices and supply fluctuate. The delays are particularly vexing in the context of the energy transition—as older generators retire, their replacements are stuck in the queue. 

As the Commission explains, Order No. 2003, which established pro forma interconnection procedures and agreements for all jurisdictional transmission utilities, is now 19 years old, and the industry has undergone dramatic changes in that time.14 Order No. 2003 was issued in an era when most generators were large, expensive, dispatchable, and had long development timelines.15 As a result, interconnection applications were relatively few, and the system upgrades needed to accommodate a new project could generally be fairly discretely assigned to that project.16 By contrast, most generation facilities proposed today are smaller, cheaper, intermittent, and “can be constructed and placed into operation more quickly than traditional types of generating facilities.”17 They also tend to have thinner profit margins, which can be severely impacted by unpredictable interconnection costs.
Another perennial challenge arising from the first-come/first-served interconnection processes has been cost allocation. Generators are obliged to pay the cost of network upgrades needed to interconnect their projects. While developers in most cases are entitled to eventually recover network upgrade costs from the transmission owner, the need to make large upfront payments may render a project non-viable.18 Moreover, “the process frequently allocates to individual interconnection customers the [entire cost of] network upgrades that may create additional interconnection capacity needed for several interconnection customers,”19 but the responsibility for these costs remains that of the highest queued customer. As a result, a higher queued customer, upon being allocated costs that make its project uneconomic, may withdraw from the queue. This necessitates restudies, which not only drive up the cost of interconnection and cause delays, but are also likely to result in a reallocation of costs that will increase the costs of projects further down the queue. This is particularly disruptive, as those projects have likely already made decisions based on the original study results and cost estimates. Particularly considering the thin margins and time-sensitive schedules for many renewable projects, this can, in turn, result in a “cascade of withdrawals” as those projects are also rendered uneconomic.20

As discussed in more detail below, a first-ready/first-served cluster study model addresses these problems by studying all projects of a given cluster or cycle together, allocating costs among all participants in the cluster, and encouraging non-viable projects to leave the queue early.

How does a first-ready/first served cluster study interconnection process work?

Under the current serial process used by most transmission providers, new service requests enter the queue in chronological order and are studied individually. All upgrade costs necessary to accommodate a given project are assigned to that project, even if other projects benefit as much or more from the upgrade. By contrast, projects in a cluster study process are studied together in a “cluster” (or “Cycle” as PJM terms it), and then the allocated network upgrade costs are based on each project’s contribution to the need for upgrades.21

The FERC and PJM proposals also seek to incentivize marginal projects to leave the queue by only allowing “ready” projects to advance. Under the current serial interconnection regime, entering and remaining in the queue is relatively inexpensive, and there are few checks once a project enters the queue to ensure that it remains viable. The result has been a large number of projects that withdraw before commercial operation.  In the case of PJM, 80% of projects that enter the queue do not reach commercial operation. By contrast, the first-ready/first-served framework would be intended to ensure that projects are “ready” by fixing “decision points” at which the project developer must choose to move forward by making a “readiness deposit” and providing evidence of the project’s progress such as site control, environmental permits and commercial viability. Projects that fail to make the readiness deposit or the required demonstrations are terminated from the queue, and projects that withdraw (with certain exceptions, such as unexpected cost increases) are subject to a forfeiture of their deposits or withdrawal penalties.

Below, we address the PJM Proposal first because it is more detailed and discrete, and demonstrates what the transition to a cluster process might look like. We then turn to examine FERC’s proposal in light of the context provided by PJM for the Interconnection NOPR and the collateral issues that FERC raises therein.

PJM’s interconnection reform proposal

The PJM Proposal is a finalized set of tariff revisions that were negotiated during an 18-month stakeholder process. According to PJM, the proposal has the support of the “vast majority of PJM stakeholders.”22 PJM describes its proposed cluster interconnection procedures as a “Cycle” mechanism. Each Cycle includes fixed “Decision Points” where a developer must demonstrate readiness and make a “Readiness Deposit” to secure its commitment to move forward. This system is intended to allow projects that are ready to progress to do so, while providing incentives for projects that are not ready to proceed to withdraw in an orderly fashion.23 The PJM Proposal includes not only a complete overhaul of the interconnection process, but numerous terminology changes as well. For example, Interconnection Service Agreements (“ISAs”) issued under the new process will be called Generator Interconnection Agreements (“GIAs”) (as they are in the FERC pro forma) and Interconnection Customers will be referred to as “Project Developers” going forward, a term designed to emphasize their active role in the interconnection process. PJM has requested an order from FERC by October 3, 2022, and an effective date for tariff changes of January 3, 2023. Initial comments on the PJM Proposal are due by July 14, 2022, and reply comments are generally anticipated within 13 days after that.

The PJM Proposal includes two new sets of interconnection procedures under the OATT. These are the “New Rules,” as set forth in a new Part VIII of the OATT, which will apply to New Service Requests submitted on or after October 1, 2021 (the date the AH2 queue window opened). Also included are “Transition Rules”, set forth in a new Part VII of the OATT, that are meant to address the backlog of interconnection requests prior to the AH2 queue window (filed by September 30, 2021 or earlier).

The new rules

Under the New Rules, each Cycle is a discrete and self-contained process, consisting of three Phases, each of which involves an interconnection study. PJM has designed its new interconnection procedures so that the studies for one Cycle will be complete prior to the initiation of studies for the next Cycle. To initiate a new Cycle, PJM will post the application date for a new Cycle once the prior Cycle reaches Phase II (after the first Decision Point and cluster study). Such notice will be at least 180 days prior to the deadline for submitting a “New Service Request” (i.e., an interconnection application). New Service Requests must include evidence of site control for at least one year and a study deposit ranging from $75,000 to $400,000, depending on the size of the project. This deposit is largely refundable (Project Developers will ultimately pay the actual costs of the studies and be refunded the balance) and will cover all three planned System Impact Studies.24 In addition, the Project Developer must submit a Readiness Deposit, which is equal to $4000 per megawatt of energy or capacity (whichever is higher). The Readiness Deposits serve two purposes—first as a gatekeeping mechanism to discourage speculative projects from entering the queue, and second as a source of funds to pay for network upgrades left underfunded when projects withdraw from the queue.

Once the applications have been reviewed for completeness, PJM will commence the study process. The study process occurs in three Phases each featuring a cluster study with a Decision Point and Readiness Deposit in between. These studies will determine the interconnection costs and network upgrade costs for each project in the Cycle. Network upgrade costs will be allocated among projects in a cluster based on a “but for” mechanism. Each developer will be required to pay 100% of “the costs of the minimum amount of Network Upgrades necessary to accommodate its New Service Request and that would not have been incurred . . . .but for that service request.”25 As more than one project may benefit from a given upgrade, PJM will allocate costs among them based on their contribution to the underlying reliability violation necessitating the upgrade. Significantly, costs will always be allocated within a Cycle, and not between Cycles.

At the end of each Phase, the Project Developer faces a Decision Point, where it may choose to withdraw or continue with the next Phase. If it chooses to withdraw, it will receive back a portion of its deposits (with further refunds possible at the end of the Cycle if those amounts are not needed to pay for underfunded network upgrades caused by the project’s withdrawal.) If it chooses to continue, it must pay an additional Readiness Deposit and provide specified evidence of its progress (such as continued site control and environmental permits). The additional readiness deposits are keyed to a percentage of the network upgrade costs that have been allocated to the project, to the extent that amount exceeds earlier Readiness Deposits. Thus, projects requiring few upgrades may need to pay little in the way of additional deposits, while those requiring a large number of upgrades will have to pay amounts commensurate with the scale of upgrades they require.

However, because there are roughly 2,700 projects currently in the PJM queue, PJM cannot shift immediately to operating under the New Rules. Instead, PJM has created a set of transition rules for projects already in the queue. 

The transition rules
As noted above, there were 250 GW of New Service Requests in PJM’s queue as of May 2022. Therefore, PJM has proposed a transition mechanism (the “Transition Rules”) to allow those interconnection requests to move forward while transitioning to the New Rules.
Under the Transition Rules, if FERC approves the PJM Proposal, PJM will process existing new service requests from queue windows AD2 and earlier (March 31, 2018 and before) under the existing interconnection rules in its OATT. The “Transition Period” will not begin until all of these requests have been tendered an ISA for execution. The Transition Period will then begin on the “Transition Date,” which is the earlier of the effective date for the PJM Proposal (requested for January 3, 2023, though the Commission could set another date), or the date on which all the AD2 projects have been tendered an ISA, whichever is later.
The Transition Date will start a 60-day clock, affecting all existing new service requests in queue windows AE1 through AG1 (April 1, 2018 through September 30, 2020) that have not yet been tendered an ISA. These projects will have 60 days to provide “Readiness Deposits” equaling $4000 per MW and evidence of site control for their project for a year. Those that fail to meet these requirements will be terminated and withdrawn from the queue. The AE1 through AG1 projects remaining will undergo a “re-tool” study that will consider their impacts on the transmission system as a cluster, rather than individually.  Based on the outcome of this retool study, PJM will move those projects that do not require network upgrades, or that require network upgrades costing $5 million or less, into an “Expedited Process.”
The projects in the Expedited Process will then be processed using PJM’s existing serial cost allocation rules, rather than the cluster cost allocation rules. They will also be processed serially “such that PJM will determine the costs for which an Expedited Process project is responsible and tender a GIA for execution. If the first project does not execute the GIA and elects to withdraw, PJM will move to the next project in the queue.”26
The remaining AE1 through AG1 projects (those with network upgrade costs of over $5 million) will be assigned to “Transition Cycle #1.” These projects will be processed together and their upgrade costs allocated “Cycle-wide,” i.e., under the New Rules. Meanwhile, the next tranche of existing projects, those in queue windows AG2 and AH1 (October 1, 2020 through September 30, 2021) will be assigned to “Transition Cycle #2,” which will also be subject to cost allocation under the New Rules. All projects in the Transition Cycles will have to present evidence of site control, both at the outset of the cycle and at future Decision Points.
PJM’s proposal is highly detailed and PJM hopes to implement it without modification. The FERC proposal, by contrast, is higher level, and can be expected to change between the NOPR and the Final Rule.


FERC NOPR proposal

The Interconnection NOPR proposes a process that is broadly similar to that proposed by PJM, but which is likely to undergo some revision as comments are received from interested parties.

There are some notable differences between the Interconnection NOPR and the PJM Proposal, however.  Foremost among these differences are:

  • Readiness Deposits. Readiness deposits are an option under the Interconnection NOPR, not a requirement.  A project must demonstrate commercial readiness to advance in the queue, in addition to such requirements as site control. Commercial readiness can be shown by a power purchase agreement (“PPA”), inclusion in a resource plan, or a provisional interconnection agreement. Although the earlier studies in the cluster allow for a PPA term sheet, the final round of studies will require an executed contract. Projects that can’t demonstrate commercial readiness may instead make a readiness deposit instead. If the developer later makes a commercial readiness demonstration, then the deposit will be returned.
  • Withdrawal penalties. Instead of requiring Readiness Deposits of all developers, which are then subject to forfeiture if the project withdraws, FERC proposes the use of withdrawal penalties in the Interconnection NOPR. If a project opts to provide a Readiness Deposit, then that money will be put towards the Withdrawal Penalty. However, FERC also proposes in the Interconnection NOPR that those projects that opt for a Readiness Deposit be subject to higher penalties upon withdrawal than those that demonstrated commercial readiness - a provision that seems targeted at speculative projects. The withdrawal penalties are calculated by applying a multiplier to the original study deposit (which is keyed to facility size).
  • Cost allocation. FERC proposes a “proportional impact method” in the Interconnection NORP but does not specify exactly what it means by that. FERC seeks input on what analyses should be used for cost allocation.  FERC also proposes sharing the cost of network upgrades across clusters, a possibility that PJM excludes. FERC reasons that if prior upgrades benefit a later cluster, then the members of the prior cluster deserve some measure of refunds.
  • Subclusters. FERC proposes allowing transmission providers to conduct cluster studies that encompass only a portion of their balancing authority area. PJM, despite having a number of submarkets, does not make an equivalent proposal.

Other Interconnection Reforms Proposed by FERC

As noted above, the Interconnection NOPR is significantly broader in scope than the PJM Proposal, and seeks to address a wider array of problems with existing interconnection procedures. It also draws on comments in other ongoing FERC proceedings, such as the Transmission Planning and Cost Allocation Advanced Notice of Proposed Rulemaking.27 and the Joint Federal-State Task Force on Electric Transmission.28 As a result, FERC makes a number of proposals that are not directly related to a cluster study process. Some of these proposals address long-standing concerns with the interconnection process, while others are attempts to make the process more “user-friendly” for increasingly diverse modern resources.

  • FERC notes that one reason for clogged interconnection queues is the inability of developers to get information about the likely costs of interconnection except by submitting a new service request and entering the queue. As a result, one developer may submit multiple speculative projects, only one of which (at most) is likely to be completed. FERC thus proposes methods by which information can be gained without joining the queue: 1) a requirement that transmission providers offer optional informational interconnection studies to help potential customers to decide whether to enter the queue,29 and 2) a requirement that transmission providers provide an interactive “heat map” of available interconnection capacity, allowing developers to see graphically where the system can accommodate their projects with little or no network upgrades.30
  • FERC states that the current pro forma LGIA requires that transmission providers make “reasonable efforts” to meet study deadlines, but “nearly all . . . regularly fail to meet interconnection study deadlines.”31 This includes the transmission providers that have already moved to a cluster study process. FERC concludes that the “reasonable efforts standard”, under which no transmission provider has ever faced consequences for missing a deadline, is no longer just and reasonable. FERC instead proposes firm deadlines and financial penalties that would apply if the transmission provider fails to meet these deadlines.32 Such penalties would not be recoverable in transmission rates.33 The Commission notes that ISO/RTOs, as non-profits, raise unique problems, and asks for comment on how to implement penalties for these entities or whether there is another method to incentivize compliance.
  • FERC proposes standardizing the “affected system” study process. Sometimes the transmission provider with whom a project seeks to interconnect is not the only transmission provider that might be impacted (for example, imports into CAISO, where the generation facility may be several states away). Currently, affected system studies are handled differently by each provider. FERC proposes standardizing this process and including it in the pro forma GIP.
  • FERC observes that some “states take a portfolio approach to resource planning, in which resource planning entities procure an entire portfolio of diverse resources that all need to interconnect to the transmission system on approximately the same timetable.”34 FERC proposes that such resource planning entities be able to initiate a special cluster study that studies combinations of resources that have submitted supply bids. Such a process should reduce costs, as they could identify economies of scale from larger network upgrades.35
  • FERC proposes several mechanisms for incorporating technological advancements into the interconnection process.  These proposals include:
    - establishing a specific process for collocating generators behind the same point of interconnection;36
    - changing the material modification process so that it does not automatically apply to proposed changes that do not change the interconnection service level;37  
    - including operating assumptions in interconnection studies, so that, for example, studies do not assume that “all generating facilities in a constrained area will seek to generate simultaneously during light load conditions or that all electric storage resources will seek to charge during peak load conditions” or that generators will “operate in a manner in which they are physically incapable of operating,”38 as these sorts of study assumptions can result in “unnecessary and expensive network upgrade costs that make projects uneconomic”;39
    - Accounting for alternative transmission technologies such as dynamic line rating, transmission switching, static synchronous compensators, static VAR compensators or advanced power flow control devices in considering network upgrades;40 and
    - adopting modeling and performance requirements for non-synchronous generating facilities, such as solar photovoltaic, wind, fuel cell and battery storage, including imposing a ride-through requirement for system disturbances.41

As shown by the wide array of additional proposals, FERC is imagining a more comprehensive shift in interconnection processes than is PJM. It is also envisioning a more robust set of incentives for both transmission provider and project developer, with penalties for the transmission provider failing to meet deadlines and explicit withdrawal penalties for developers. FERC, of course, is not constrained by a stakeholder process, which undoubtedly limited PJM’s options. But FERC is also not itself a transmission provider, and is thus perhaps more willing to impose additional burdens on transmission providers to accommodate the changing resource mix.


With two such massive proposals released almost back-to-back, the obvious question is what will happen if they conflict.  FERC addresses this issue directly: “This [Interconnection] NOPR is not intended to divert or slow the potential progress”42 made independently by transmission providers and the RTO/ISOs, and promises to review filings made to implement such changes on the record established in those proceedings, and not based on compliance with the Interconnection NOPR. However, FERC then notes that it will evaluate how transmission providers meet any compliance obligations that arise in a Final Rule from the Interconnection NOPR “in light of the independent entity variation [standard] for ISO/RTO regions and the consistent with or superior to standard for non-RTO regions.”43 The result is therefore a somewhat muddled message—FERC will evaluate interconnection reform filings on their own merits, and not on the standards set forth in the NOPR. However, when and if a Final Rule emerges from the Interconnection NOPR, transmission providers like PJM may have to modify their interconnection processes to be consistent with the Final Rule.

At the June Open Meeting, Commissioner Danly emphasized the importance of commenting on the interconnection reforms: “[Y]ou absolutely must participate in these dockets if they affect you. And your comments should be as specific as possible to give us the best record to make choices.” Comments on the Interconnection NOPR are due on October 13, 2022, with reply comments due on November 12, 2022. Comments on the PJM Proposal are due on July 14, 2022.


1PJM Interconnection, L.L.C., Tariff Revisions for Interconnection Process Reform, Docket No. ER22-2110-000, at 1 (June 14, 2022) (“PJM Proposal”). PJM also submitted a companion filing making conforming changes to the PJM Consolidated Transmission Owners Agreement, PJM Interconnection, L.L.C., PJM Transmission Owners’ Tariff Revisions to Conform to PJM’s Proposed Interconnection Queue Tariff Reforms, Docket No. ER22-2114-000 (June 14, 2022)

2 Improvements to Generator Interconnection Procedures and Agreements, 179 FERC ¶ 61,194 (June 16, 2022) (“Interconnection NOPR”)

3 The majority of FERC’s proposed changes apply only to the Large Generator Interconnection Procedures and Large Generator Interconnection Agreement (“LGIA”), which govern the interconnection of generators over 20 MW. FERC has different pro forma procedures and agreements for small generators (those under 20 MW). We have noted where the proposals would affect the Small Generator Interconnection Procedures (“SGIP”) and Small Generator Interconnection Agreements (“SGIA”).

4Standardization of Generator Interconnection Agreements & Proc., Order No. 2003, 68 FR 49845 (Aug. 19, 2003), 104 FERC ¶ 61,103 (2003), order on reh’g, Order No. 2003-A, 69 FR 15932 (Mar. 5, 2004), 106 FERC ¶ 61,220, order on reh’g, Order No. 2003-B, 70 FR 265 (Jan. 19, 2005), 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003-C, 70 FR 37661 (July 18, 2005), 111 FERC ¶ 61,401 (2005), aff'd sub nom. Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).

5 16 U.S.C. § 824e

6 16 U.S.C. § 824f

7 FERC also finds parts of Order No 2006, Standardization of Small Generator Interconnection Agreements & Proc., Order No. 2006, 70 FR 34189 (June 13, 2005), 111 FERC ¶ 61,220, order on reh’g, Order No. 2006-A, 70 FR 71760 (Nov. 30, 2005), 113 FERC ¶ 61,195 (2005), order granting clarification, Order No. 2006-B, 71 FR 42587 (July 27, 2006), 116 FERC ¶ 61,046 (2006), setting forth the SGIP and SGIA, to be unjust and unreasonable.  Interconnection NOPR at P 22.

8Interconnection NOPR at PP 7, 20.

9 Interconnection NOPR at P 28.

10 Interconnection NOPR at P 18.

11PJM Proposal at 17.

12PJM Proposal at 19-25.

13PJM Proposal at 19.

14Interconnection NOPR at PP 2-3.

15Interconnection NOPR at P 7.

16Interconnection NOPR at PP 7-11.

17 Interconnection NOPR at P18.

18 Interconnection NOPR at P 35.

19Interconnection NOPR at P 55.

20 PJM Proposal at page 6

21 FERC and PJM handle these allocations somewhat differently. FERC proposes a proportional impact allocation mechanism, while PJM uses a “but for” method of allocation that assigns each Project Developer the minimum cost to interconnect its project based on costs that would not have been incurred but for the project’s inclusion in the Cycle. The Interconnection NOPR also permits some sharing of network upgrade costs across clusters, which PJM does not.

22 PJM Proposal at ii.

23 PJM Proposal at 1

24 PJM is doing away with the Feasibility and Facilities Studies as distinct entities.

25PJM Proposal at 60-61

26 PJM Proposal at 12

27Bldg. for the Future Through Elec. Reg’l Transmission Plan. & Cost Allocation & Generator Interconnection, 86 FR 40266 (July 15, 2021), 176 FERC ¶ 61,024 (2021)

28 Joint Fed.-State Task Force on Elec. Transmission, 175 FERC ¶ 61,224 (2021).  

29 Interconnection NOPR at P 42.

30 Interconnection NOPR at P 49.

31 Interconnection NOPR at P 167

32 Id.  at P 168.

33 Id.  at P 169.

34 Id.  at P 216.

35 Id.  at P 220.

36 Id.  at PP 238-245.

37 Id.  at PP 246-257.

38Id.  at 265.

39 Id.  at 268.

40 Id.  at 297-299

41 Id.  at 336.

42 Interconnection NOPR at P 6

43 Interconnection NOPR at P 6. The independent entity variation standard was established in Order No. 2003, see Order No. 2003 at P 827. “The independent entity variation standard recognizes that an RTO or an ISO has different operating characteristics depending on its size and location and is less likely to act in an unduly discriminatory manner than a transmission provider that is a market participant. The independent entity variation standard provides the RTO and ISO with greater flexibility to customize its interconnection procedures and agreements to fit regional needs.” Southwest Power Pool, Inc., 128 FERC ¶ 61,114, at P 15 (2009).

Related expertise