FERC’S Order No. 2023 Aims at Improving and Expediting the Generator Interconnection Process

Time 33 Minute Read
August 4, 2023
Legal Update

On July 28, the Federal Energy Regulatory Commission (“FERC”) issued its long anticipated final rule addressing Improvements to Generator Interconnection Procedures and Agreements (“Order No. 2023”).  FERC Chairman Willie Phillips proclaimed that the new rule “represents the largest and most significant set of interconnection reforms since the pro forma interconnection procedures were created two decades ago.” 

According to FERC, the reforms included in Order No. 2023 are urgently needed because the “electricity sector has transformed significantly” in the twenty years since FERC first established standardized generator interconnection rules.  Increasingly large numbers of new resources are seeking to interconnect to the transmission grid.  FERC notes that many are renewable energy resources with different characteristics than the existing rules were designed to address.  Projects are also facing long interconnection queue backlogs in many regions which creates uncertainty regarding costs and timing.  FERC contends that interconnection delays and uncertainty could give rise to reliability concerns by hindering new entry.  Clean energy supporters have urged FERC to address these issues because they see them as impediments to state and federal environmental policies, including those that are heavily supporting the entry of renewable resources.


Order No. 2023 will apply to all FERC-jurisdictional1 owners and operators of interstate electric transmission facilities (“Transmission Providers”), i.e., to traditional transmission-owning utilities, as well as to Independent System Operators and Regional Transmission Organizations (“ISOs/RTOs”).  Except as noted below, each Transmission Provider will be required to revise its currently effective2 pro forma Large Generator Interconnection Procedures (“LGIP”), Large Generator Interconnection Agreement (“LGIA”), Small Generator Interconnection Procedures (“SGIP”), and Small Generator Interconnection Agreement (“SGIA”) to adopt the new pro forma standards of Order No. 2023.

Order No. 2023 proposes three main categories of rule changes. They are discussed briefly here and in greater detail below in the summary of the final rule’s most significant provisions. 

First, Order No. 2023 would require the adoption of a “first-ready, first served” cluster study process for interconnection requests.  This approach would replace the “first-come, first-served” model under the currently effective pro forma interconnection rules.  FERC believes that cluster studies encompassing numerous proposed generating facilities will increase the efficiency of the interconnection process, reduce delays and improve cost allocation by analyzing the transmission system impacts of multiple projects at the same time.

Second, Order No. 2023 seeks to increase the speed of interconnection queue processing.  It would do this by: (i) imposing various new requirements on Interconnection Customers3 to discourage speculative interconnection requests that are unlikely to result in completed projects but that can delay other interconnections; (ii) eliminating the “reasonable efforts” standard that currently governs the completion of interconnection studies and establishing a strict regime of financial penalties for missing study deadlines; and (iii) establishing a standardized affected system4 study process.  

The penalties proposal was controversial during the rulemaking process.  Many commenters argued that delays are often caused by factors beyond Transmission Providers’ control.  But Order No. 2023 sets penalty levels are materially higher than the NOPR suggested, although the final rule also includes new measures intended to delay or avoid the automatic imposition of penalties, including a novel appeals process.  Penalty issues are particularly complex in regions where the transmission grid is operated by ISOs/RTOs.  FERC precedent does not allow utilities to recover penalty costs from ratepayers and instead requires them to be paid by shareholders.  But not-for-profit ISOs/RTOs do not have shareholders and thus have limited, if any, ability to absorb penalties themselves.  Order No. 2023 addresses this issue but leaves its resolution to future proceedings.

Third, Order No. 2023 seeks to better incorporate technological advancements into the interconnection process.  It would do so by requiring Transmission Providers to: (i) allow more than one generating facility to co-locate on a shared site behind a single point of interconnection; (ii) evaluate a proposed addition of a generating facility at the same point of interconnection prior to deeming the addition to be a “material modification”5 if the addition does not change the originally requested interconnection service level; (iii) allow Interconnection Customers earlier access to the surplus interconnection service process; (iv) use operating assumptions in interconnection studies that reflect the proposed charging behavior of electric storage resources; and (v) evaluate the use of alternative transmission technologies specified in the final rule.  Order No. 2023 also imposes new requirements on Interconnection Customers seeking to connect non-synchronous generators6 and mandates that all newly interconnecting large generating facilities have “ride through capability”7 comparable to all other generating facilities.

Order No. 2023 closely tracks many of the proposals included in FERC’s 2022 Notice of Proposed Rulemaking on interconnection reform (“NOPR”).  But as noted in the summary below there are also a number of notable changes.  Broadly speaking, Order No. 2023 appears to reflect a compromise on some of the more sweeping proposed NOPR “reforms” in order to secure unanimous support for  significant changes.  One of the themes pervading Order No. 2023 is that Transmission Providers should not be burdened with tasks that might bring benefits but that have the potential to divert their attention and resources from the core objective of processing interconnection requests more efficiently.  Some Transmission Providers are nevertheless likely to argue that the requirements of the final rule are unduly burdensome and unreasonable under the deadlines in Order No. 2023.

Order No. 2023 will raise especially complex compliance issues in the ISO/RTO regions that span approximately two-thirds of the continental United States. In addition to the penalty issue noted above, ISOs/RTOs have been allowed to diverge from the existing pro forma interconnection rules under FERC’s “independent entity variation” standard.  Most ISOs/RTOs currently have interconnection regimes that are substantially different than the currently effective pro forma model. In many cases, ISO/RTO rules are already very similar to what Order No. 2023 requires, e.g., multiple ISOs/RTOs already conduct cluster studies.  But other ISO/RTO rules are not as closely aligned with the final rule.  Order No. 2023 permits ISOs/RTOs to justify keeping, or creating, alternative arrangements by making new showings that independent entity variations are warranted. Many questions, and possible disputes, are likely to arise when the ISOs/RTOs make their individual Order No. 2023 compliance filings.  By contrast, Transmission Providers outside of ISO/RTO regions will continue to have much less freedom to depart from pro forma interconnection rules and will likely have to implement the Order No. 2023 standards with few or no changes.

Concurring Opinions

All four Commissioners voted for Order No. 2023. Three wrote concurring opinions. 

Commissioner Danly explained that he supported the final rule because he thought that its changes were relatively narrow and that what he viewed as the most problematic aspects of the NOPR had been abandoned.  He also indicated that he would have preferred for FERC to deal with interconnection issues on an individual Transmission Provider basis rather than adopt generic national rules.

Commissioner Clements praised the final rule but argued that it represents a “baseline not a ceiling” and that additional improvements are needed.  She recommended that FERC consider several “deeper reforms” including: (i) linking the interconnection and transmission planning processes; (ii) aligning interconnection rules more closely with competitive resource solicitations; and (iii) transitioning to a new “focused” or “connect and manage” approach for energy-only resource interconnections (i.e., for resources that would not be eligible to sell capacity).  She also identified multiple additional “incremental improvements” that had not been included in the NOPR but which she believed warranted future consideration. 

Commissioner Christie expressed support for the final rule because he believed it properly focuses on the core objective of “identifying generation projects in the interconnection queue that are commercially more viable and then moving them ahead of requests that are speculative and which have been causing major backlogs.”  Commissioner Christie raised four additional points.  First, he emphasized that the final rule was  limited to requiring Transmission Providers to evaluate grid-enhancing technologies and did not require that such technologies be deployed.  He highlighted the fact that Order No, 2023 gave Transmission Providers sole discretion to make these evaluations.  Second, he stated that FERC should revisit its established affected systems repayment policy (but acknowledged that it was not changed by Order No. 2023).  Third, he expressed concern that the imposition of study delay penalties on ISOs/RTOs and requiring Transmission Providers to provide “heatmap” information to Interconnection Customers could result in costs being inappropriately allocated to consumers.  In particular, he complained that the final rule “essentially punts” on the question of penalty cost recovery by ISOs/RTOs. Fourth, he argued that the Commission should “hold harmless” ISOs/RTOs that have made, or are presently making, substantial progress on their own interconnection reforms by accepting ISO/RTO alternatives to the Order No. 2023 pro forma requirements.

Next Steps

Requests for rehearing will be due 30 days after the date that Order No. 2023 was issued, i.e., on August 28, 2023 (August 27 falls on a Sunday).  Commissioner Danly encouraged parties to raise any arguments about FERC potentially exceeding its authority under the Federal Power Act or failing to meet its evidentiary burden.  

Order No. 2023 will become effective 60 days after it is published in the Federal Register.   Transmission Providers’ compliance filings will be due 90 days after the final rule’s publication date.  The NOPR had proposed a 180-day compliance period but Order No. 2023 asserts that compliance filings must be made sooner because timely interconnection reform is so important. 

The interconnection reforms set forth in Order No. 2023 were first proposed alongside extensive reforms to FERC’s transmission planning and cost allocation rules.  The later proposals were also meant to facilitate the development of clean energy resources and are still pending in a separate rulemaking.  Commissioner Phillips and Commissioner Clements have stated that they believe the Commission should adopt the transmission planning and cost allocation reforms next.  It is unclear whether Commissioners Danly or Christie, who have previously expressed misgivings about the legal and policy merits of such  proposals, will agree.  The Biden administration and Congressional Democrats are likely to urge FERC to take action now that legislative efforts to address transmission planning and cost allocation issues appear to be stalled.8

Summary of Most Significant Provisions in Order No. 2023

I. Implementing a First-Ready, First-Served Cluster Study Process

a. Interconnection Information Access

FERC adopted the NOPR proposal to require Transmission Providers to post on their public websites a heatmap of estimated incremental injection capacity, expressed in MW, for each bus in the Transmission Provider’s footprint under N-1 conditions.  Transmission Providers will also need to provide a table of results showing the estimated impact of the addition of a proposed project based on user-specified MW amount, voltage level, and point of interconnection for each monitored facility impacted by the proposed project using specified metrics.  Transmission Providers are obligated to update this information within 30 days after the completion of each cluster study and restudy, but the information displayed in the heatmap is illustrative, non-binding, and subject to change.  

FERC declined to adopt the NOPR proposal to require Transmission Providers to offer prospective Interconnection Customers informational interconnection studies.  FERC agreed with various commenters that such studies would provide limited benefit and could divert Transmission Provider resources away from conducting cluster studies.   

b. Cluster Study Process

Pointing to a myriad of associated benefits, including increased efficiency, greater certainty for Interconnection Customers concerning the timing of studies and the amount of network upgrade costs, fewer withdrawals, and reduced risk of restudy, FERC adopted the NOPR proposal to make cluster studies the required interconnection study method.  FERC emphasized that the reforms adopted in the final rule do not prescribe how Transmission Providers form clusters. 

Cluster Study Request Window

FERC adopted the NOPR proposal to require that interconnection requests be submitted during a 45-calendar day cluster request window.  Interconnection Customers will also need to submit non-refundable $5,000 application fees with each interconnection request and provide all requested information within 10 business days of receiving an interconnection request deficiency notice (and no later than the close of the cluster request window).  FERC also adopted the NOPR proposal to create a customer engagement window but extended it from 30 days (as originally proposed in the NOPR) to 60 days. 

Scoping Meeting

FERC adopted the NOPR proposal to require Transmission Providers to hold scoping meetings with all Interconnection Customers whose interconnection requests were received in the cluster request window.  Non-disclosure agreements will be used to maintain the confidentiality of identifying or commercially sensitive information for Interconnection Customers participating in a group scoping meeting.  FERC dropped the NOPR proposal to require Transmission Providers to hold individual customer-specific meetings at the Interconnection Customer’s request.   

Posting of Metrics for Cluster Study Processing Time and Restudy Processing Time

FERC adopted the NOPR proposed revisions to require Transmission Providers to post cluster study and restudy processing time metrics, including the number of cluster studies completed within 150 calendar days of the close of the customer engagement window.  The metrics must be measured from (i) the close of the customer engagement window for the cluster study processing time metric and (ii) when the Transmission Provider notifies Interconnection Customers in the cluster that a restudy is needed.  FERC declined to grant Transmission Providers additional flexibility to maintain metrics and their associated timelines. 

Interconnection Request Evaluation

FERC adopted the NOPR proposal to require Transmission Providers to queue clusters based on when they are created and to consider all interconnection requests submitted within a cluster request window to be equally queued.  FERC clarified that if (i) a Transmission Provider deems moving a point of interconnection to be a material modification to the interconnection request, and (ii) the Interconnection Customer still chooses to proceed with the proposed modification, the interconnection request will be deemed withdrawn.

Fewer than Three-Year Extension

FERC adopted the NOPR proposal to require that Interconnection Customers receive an extension of fewer than three cumulative years of the generating facility’s commercial operation date without needed to request such an extension from the Transmission Provider.  FERC clarified that the commercial operation date reflected in the initial interconnection request will be used in calculating permissible extensions. 

Cluster Study Provisions (Pro Forma LGIP Sections 6, 7)

FERC concluded that a 150-calendar day cluster study deadline proposed in the NOPR would provide adequate time for Transmission Providers to perform the stability, power flow, and short circuit analyses required for complex clusters consisting of numerous interconnection requests.  FERC declined to allow Transmission Providers flexibility to set their own study deadlines.

Restudies Triggered by Higher or Equally Queued Generating Facility

FERC adopted the NOPR proposal to revise the pro forma LGIP to make clear that that restudies can be triggered by a withdrawal or permitted modification by a higher or equally queued interconnection request. Transmission Providers will have the flexibility to assess whether a restudy is necessary.

Timing of LGIA Tender, Execution, and Filing

FERC adopted the NOPR proposals to incorporate (i) a 60-calendar day LGIA negotiation period; and (ii) site control demonstrations and LGIA deposit requirements.  Interconnection customers may still request a Transmission Provider to file an unexecuted LGIA but must satisfy requirements for submission of deposits, evidence of site control, and milestone progress data within 10 business days after the date of the filing of the unexecuted LGIA with FERC. 

Cluster Subgroups

FERC declined to require Transmission Providers to conduct cluster studies on subgroups of Interconnection Customers based on areas of geographic and electric relevance although they can voluntarily chose to do so. 


FERC declined to impose specific requirements specifying how and when Transmission Providers must conduct cluster restudies. 

Exceptions to the Cluster Study Process

FERC declined to allow Transmission Providers to process some interconnection requests outside the annual cluster study process adopted in the final rule.

c. Allocation of Cluster Study Costs

FERC adopted the NOPR proposal, with modification, to allow each Transmission Provider to propose its own study cost allocation ratio for allocating the shared costs of cluster studies between a per capita basis and pro rata by MW.  Transmission Providers must, however, allocate between 10% and 50% of study costs on a per capita basis and the remainder pro rata by MW.  Transmission Providers may propose to retain their existing study cost allocation ratios if they fall within this range and meet the final rule’s other requirements. 

d. Allocation of Cluster Study Network Upgrade Costs

FERC required Transmission Providers to allocate most network upgrade costs based on a proportional impact method as proposed in the NOPR but directed that costs associated with substations at the point of interconnection that are designated as network upgrades should be allocated on a pro rata basis to those generators seeking interconnection at the substation.  In addition, the cost of shared interconnection facilities will be assigned to Interconnection Customers on a per capita basis unless they agree on a different sharing mechanism.

FERC declined to direct Transmission Providers to use a specific type of proportional impact method or distribution factor analysis or to use consistent, uniform thresholds to measure impact but directed Transmission Providers on compliance to provide tariff provisions describing the particular proportionate impact method that will be used for each type of system network upgrade.  In addition, FERC acknowledged that other allocation methods could potentially meet the “consistent with or superior to” standard or the “independent entity variation” standard. 

e. Shared Network Upgrades

FERC declined to adopt the NOPR proposal  to require Transmission Providers to allocate the costs of network upgrades between Interconnection Customers in earlier clusters and those in later clusters that benefit from the same network upgrade.  FERC determined that the proposal would not provide additional cost certainty to Interconnection Customers in earlier clusters and would burden lower-queued Interconnection Customers that could be required to reimburse a higher-queued Interconnection Customer late in the interconnection process.  Further, FERC determined that the potential for Interconnection Customers in a subsequent cluster being “free riders” of upgrades stemming from earlier clusters was minimized by the availability of transmission credits under FERC’s transmission pricing policy and because of the reforms made in the cluster study approach.

f. Increased Financial Commitments and Readiness Requirements

FERC adopted the following reforms to discourage speculative interconnection requests and to allow Transmission Providers to focus on processing viable interconnection requests:

Increased Study Deposits

Interconnection Customers must pay study deposits as part of the cluster study process.  FERC adopted the following deposit framework in the LGIP:

Deposit framework LGIP

Transmission Providers must collect an initial study deposit in an amount between $55,000 and $250,000  at the time of an interconnection request submission.  This is the only study deposit Transmission Providers may collect which modifies the NOPR proposal providing for different study deposits being due at each phase of the cluster study process. 

Demonstration of Site Control

Order No. 2023 adopted more stringent site control requirements than those proposed in the NOPR.  An Interconnection Customer must demonstrate the exclusive land right to develop, construct, operate, and maintain its generating facility, or where facilities are co-located, to demonstrate a shared land use right regarding co-located facilities.  Specifically, an Interconnection Customer must provide evidence of (1) 90% site control for a generating facility at the time of submission of its interconnection request and (2) 100% site control at the time of execution of the facilities study agreement. 

Commercial Readiness

FERC declined to adopt non-financial commercial readiness demonstrations as proposed in the NOPR.  Instead, all Interconnection Customers are required to provide commercial readiness deposits at the beginning of each study phase in the cluster study process.  The initial commercial readiness deposit will be equal to two times the study deposit to enter the cluster study.  The commercial readiness deposits for the second and third will be based on increasing percentages of the Interconnection Customer’s identified network upgrade cost assignment.  For the cluster restudy phase, the total commercial readiness deposit will be 5% of the Interconnection Customer’s network upgrade cost assignment identified in the cluster study, for the facilities study, the total commercial readiness deposit will be 10% of the Interconnection Customer’s network upgrade cost assignment identified in the cluster study or restudy, as applicable.

LGIA Deposit

FERC declined to adopt the NOPR proposal that the LGIA deposit should equal nine times the amount of the Interconnection Customer’s study deposit.  Instead, when executing an LGIA or requesting the filing of an unexecuted LGIA, Interconnection Customers must submit, as a security for construction of network upgrades and interconnection facilities, an additional amount that will increase the commercial readiness deposit to equal 20% of the estimated network upgrade costs in the LGIA.            

Withdrawal Penalties

FERC adopted the NOPR withdrawal penalty proposal with modifications.  Withdrawal penalties increase in amount as Interconnection Customers proceed through the interconnection process in order to incentive Interconnection Customers to continue evaluating whether their proposed generating facilities are commercially viable.  FERC’s schedule of withdrawal penalties amounts is based on the commercial deposit amounts as detailed in the table below:

Schedule of withdrawal penalties

Withdrawal penalties may be triggered when: (1) the Interconnection Customer withdraws its interconnection request; (2) the Interconnection Customer’s interconnection request has been deemed withdrawn by the Transmission Provider; or (3) the Interconnection Customer’s generating facility does not reach commercial operation.  Withdrawal penalties, however, are assessed only if the withdrawal has a material impact on the cost or timing of any interconnection request with an equal or lower queue position.  Immaterial impacts do not result in any assessment of penalties.  Also, regardless of impacts, penalties are excused if the withdrawal follows significant, unanticipated increases in network upgrade cost estimates.  Specifically, withdrawal penalties are excused if:  (1) the network upgrade costs assigned to the Interconnection Customer’s request have increased 25% compared to the previous cluster study report; or (2) the network upgrade costs assigned to the Interconnection Customer’s request have increased by more than 100% compared to costs identified in the cluster study report. 

Withdrawal penalty amounts collected are applied as follows:  (1) to fund studies and restudies in the same cluster; (2) if withdrawal penalty funds remain, to offset net increases in costs borne by other remaining Interconnection Customers from the same cluster for network upgrades shared by both the withdrawing and non-withdrawing Interconnection Customers prior to the withdrawal; and (3) if any withdrawal penalty funds remain, they will be returned to the withdrawing Interconnection Customer.

g. Transition Process

Order No. 2023 requires Transmission Providers to offer existing Interconnection Customers up to three transition options, depending on the phase of the serial study process to which their interconnection requests have progressed:  (1) a transitional serial interconnection facilities study; (2) a transitional cluster study comprised of a clustered system impact study and individual facilities studies; or (3) withdrawal from the interconnection queue without penalty.  Transmission owners must offer the transitional serial study option and the transitional cluster study option to Interconnection Customers within 30 calendar days of the date of the Transmission Provider’s initial filing.  Order No. 2023 imposes penalties equal to nine times the cost of a transitional serial interconnection facilities study on any Interconnection Customer who withdraws from a transitional serial interconnection facilities study. 

II. Increasing the Speed of Interconnection Queue Processing

a. Eliminating the “Reasonable Efforts” Standard and Adopting a Financial Penalty Regime for Late Interconnection Studies

FERC’s existing pro forma LGIP establishes deadlines for Transmission Providers to complete interconnection studies but only requires “reasonable efforts” to meet them.  Order No. 2023 finds that “a majority of transmission providers across the country regularly fail”  to meet the deadlines and face no consequences for doing so.  By contrast, Interconnection Customers face “financial and commercial consequences due to late interconnection study results and may be considered withdrawn from the interconnection queue for failing to meet their tariff-imposed deadlines.”  Order No. 2023 therefore adopted a modified version of the NOPR proposal to adopt financial penalties for untimely transmission studies.  FERC appears to view the new penalty regime as necessary both in its own right and as a balance against the new obligations that Order No. 2023 places on Interconnection Customers. 

Under Order No. 2023, delays of cluster studies beyond the tariff-specified deadline will incur a penalty of $1,000 per business day; delays of cluster restudies will incur a penalty of $2,000 per business day; delays of affected system studies will incur a penalty of $2,000 per business day; and delays of facilities studies will incur a penalty of $2,500 per business day.  The penalties are higher for studies that come later in the interconnection process because FERC believes that delays at that stage are more likely to harm Interconnection Customers with non-speculative projects.   The penalty levels are higher than the $500/level proposed in the NOPR because FERC agreed with arguments that harsher penalties were needed to incentivize more timely completions of studies. 

Maximum penalty amounts would be capped at: (i) 100% of the initial study deposits received for all of the interconnection requests in the cluster for cluster studies and cluster restudies; (ii) 100% of the initial study deposit received for the single interconnection request in the study for facilities studies; and (iii) 100% of the study deposit(s) that the affected system Transmission Provider collects for conducting the affected system study.  Tying the penalty cap to  study deposit amounts is intended “to ensure that the maximum penalty bears a relationship to the costs of the study that was late and is not unnecessarily punitive.”

Interconnection study penalties would be distributed to Interconnection Customers in a relevant study on a pro rata per interconnection request basis to offset their study costs. 

Many commenters objected to interconnection study penalties on the ground that delays were often caused by factors beyond Transmission Providers’ control, such as the vast increase in the number of requests, complex interactions between multiple interconnections, frequent modifications and withdrawals by Interconnection Customers, etc.  FERC concluded however, that its adoption of a cluster study model and various reforms to discourage speculative interconnection requests ameliorated these concerns.  FERC also took the position that it was providing protections for Transmission Providers that would keep the penalty regime from being overly harsh.  These include a 10-day grace period for late studies, the ability to obtain 30-day deadline extensions with Interconnection Customers’ consent, and a new process for appealing penalties to FERC.  FERC provided few details about the appeals process other than indicating that Transmission Providers would have to make a “good cause” showing that they should be excused from penalties.  FERC does not normally apply a “good cause” standard in substantive cases so it is unclear how likely future penalty appeals would be to succeed.  FERC likewise did not indicate whether appeals would be “paper” proceedings or might involve a fact-finding role for administrative law judges. 

As noted above, FERC precedent forbids public utilities from recovering penalty costs from their customers.  Order No. 2023 modified the NOPR to expressly prohibit non-ISO/RTO Transmission Providers from recouping study delay penalty costs through their transmission rates.  FERC also indicated that it would not even allow non-ISO/RTO Transmission Providers to recover penalty costs from Interconnection Customers who caused the delays.  Instead, FERC hinted that it could be receptive to requests to waive penalties in such scenarios. 

Order No. 2023 raises difficult issues in the case of ISOs/RTOs that lack shareholders or sources of funding that do not involve passthroughs to customers.  The final rule attempts to address this issue, in part, by holding that penalties related to interconnection studies performed by the transmission-owning members of an ISO/RTO will be assigned directly to the transmission owners instead of the ISO/RTO.  FERC also revised the NOPR to allow ISOs/RTOs to submit filings under section 205 of the FPA to propose a “default structure” to govern the recovery of all study penalty costs as an alternative to making separate filings to recover the costs of individual penalty assessments. 

In short, FERC is leaving the implementation details of ISO/RTO penalty recovery issue to be resolved in future individual Transmission Provider compliance section 205 proceedings.  There may be significant disputes over when it is reasonable for an ISO/RTO to assign a penalty to a transmission owner and/or Interconnection Customer that caused or contributed to study delays.  This could include fact patterns where an ISO/RTO and a transmission owner member work collaboratively to complete a study and disagree over which is to blame for a missed deadline.  It is also unclear what ISOs/RTOs would have to show in order to convince FERC that it would be “just and reasonable” to require customers to bear penalty costs that an ISO/RTO lacks the means to pay.

The new penalty regime will not be implemented until the third cluster study cycle after the effective date of Transmission Provider’s Order No. 2023 compliance filings.  This implementation date could be several years aways.  FERC expects that the transition time  will allow Transmission Providers to take measures to improve their study processing and for other Order No. 2023 reforms to reduce the volume of study requests that Transmission Providers must manage.

b. Affected Systems Studies

Order No. 2023 establishes a detailed and standardized affected system study process including uniform modeling standards, firm deadlines and pro forma affected system agreements.  FERC noted that the existing LGIP does not include any requirements establishing how or when Transmission Providers should complete affected system studies.  FERC believed that because of the absence of such requirements, affected system studies often lag behind those completed by the “host” Transmission Provider, i.e., the entity to whose transmission system a project would interconnect, and are sometimes completed very late in the interconnection process, causing additional delays and uncertainty for Interconnection Customers.  Furthermore, there is currently little consistency among Transmission Providers that have affected system study procedures. 

The final rule adopts a host of revisions to the pro forma LGIP to standardize affected system study procedures.  These include an initial notification requirement, a study process with firm deadlines, the establishment of interconnection queue priority for the purposes of network upgrade cost allocation, the presentation of study results and an assessment of those results, rules governing the scope of studies, the application of penalties if an affected system transmission provider fails to meet a study deadline, and the adoption of pro forma affected system study and facilities construction agreements.  FERC also added several new definitions to the pro forma LGIP.  However, Order No. 2023 declined to adopt the NOPR proposal that affected system Transmission Providers must hold an affected system study scoping meeting within seven business days of providing notice of intent to conduct an affected system study.

FERC reasoned that establishing the new standardized process will prevent the use of “ad hoc” approaches that could result in unjust, unreasonable, or unduly discriminatory treatment of Interconnection Customers. 

Unlike other features of Order No. 2023, the new affected system study process does not apply to non-FERC-jurisdictional Transmission Providers. 

c. Optional Resource Solicitation Study

Order No. 2023 declined to adopt the NOPR proposal to permit state entities or entities implementing state mandates to initiate an optional resource solicitation study.  The concept was that such studies could help resource planning entities to gather information on various potential resource mix scenarios that would support state policy objectives.  FERC concluded that there was insufficient evidence that such a requirement was justified and that the NOPR proposal could divert Transmission Provider resources to an extent that could impede interconnection processing improvements.  FERC also indicated that resource solicitation study proposals might be appropriate under some circumstances and that it would not close the door to future proposals.  

III. Incorporating Technological Advancements into the Interconnection Process

a. Increasing Flexibility in the Generator Interconnection Process

Co-Located Generating Facilities Behind One Point of Interconnection

FERC adopted reforms to require Transmission Providers to allow more than one generating facility to co-locate on a shared site behind a single point of interconnection and share a single interconnection request.

Consideration of Generating Facility Additions in Modification Process

FERC adopted reforms to require that a Transmission Provider must evaluate an Interconnection Customer’s proposed addition of a generating facility to its interconnection request at the same point of interconnection prior to deeming such change a material modification, so long as the proposed addition does not change the originally requested interconnection-service level and the request is received prior to the Interconnection Customer’s return of an executed facilities study agreement.  The Transmission Provider may automatically treat such requests received after an  Interconnection Customer’s return of the executed facilities study agreement as a material modification without review.  FERC also included an exception to this new requirement for Interconnection Customers seeking to add a generating facility of a different fuel type if the Transmission Provider employs fuel-based dispatch assumptions in its interconnection studies.

Availability of Surplus Interconnection Service

FERC adopted a requirement for Transmission Providers to allow Interconnection Customers to access the surplus interconnection service process once the original Interconnection Customer has either executed an LGIA or requested an unexecuted LGIA be filed with FERC to enable other generating facilities to use unused interconnection service earlier than currently allowed.

Operating Assumptions for Electric Storage Resources in Interconnection Studies

FERC adopted a requirement to require a Transmission Provider, at the request of  an Interconnection Customer, to use operating assumptions that reflect the proposed charging behavior of electric storage resources, unless good utility practice, including applicable reliability standards, require using different operating assumptions.  The requirements concern whether the interconnecting generating facility will charge during peak load conditions and do not apply to discharging.  Such operating requirements, including any requirements for the installation of control technologies, can be memorialized in the LGIA.  Transmission providers may pursue termination of the Interconnection Customer’s LGIA if the generating facility is operated inconsistently with the operating assumptions used in the interconnection studies.

 b. Consideration of Alternative Transmission Technologies

FERC adopted a requirement for Transmission Providers to evaluate, in both their LGIP and SGIP, specified alternative transmission technologies for potential use as appropriate and cost-effective network upgrades.  Transmission Providers are obligated to evaluate the following technologies for all Interconnection Customers in the feasibility study and system impact study:  static synchronous compensators; static VAR compensators; advanced power flow control devices; transmission switching; synchronous condensers; voltage source converters; advanced conductors; and tower lifting.  Transmission Providers are given “sole discretion” in determining whether to use an alternative technology, however, they must include an explanation of the evaluation results in the pro forma LGIP cluster study report.

Annual Information Report

FERC declined to adopt the NOPR proposal to require Transmission Providers to submit an annual informational report to FERC detailing whether, and if so how, advanced transmission technologies were considered in interconnection requests over the previous year.  FERC determined that the time and resources required to produce the annual informational report may delay interconnection queue processing which outweighs the incremental increased transparency to the evaluation process and deployment of alternative transmission technologies.  In addition, similar information is now required to be included in the in the pro forma LGIP cluster study report.

c. Modeling and Ride-Through Requirements For Non-Synchronous Generating Facilities

FERC adopted the NOPR proposal requiring an owner of a non-synchronous generating facility seeking interconnection to provide models to the Transmission Provider that contain the details necessary to accurately model the performance of the generating facility.  These models will be used to evaluate the response of the generating facility to system disturbances in accordance with the control system settings that would be used by the Interconnection Customer during the commissioning and operation of the generating facility.

FERC also adopted the NOPR’s proposal, with modifications, to establish “ride-through” requirements for non-synchronous generators during abnormal frequency conditions and voltage conditions within a “no trip zone,” as defined by NERC.  During abnormal frequency and voltage conditions within the “no trip zone,” non-synchronous generating facilities are required to configure or set their facilities to ride through disturbances and continue supporting system reliability consistent with their physical limitations.  FERC’s modifications recognize that non-synchronous generators may need to reduce active power production in order to prioritize reactive power output in support of transmission system voltage and that non-synchronous facilities may not be able to ride through disturbances with the same performance as synchronous generating facilities without costly equipment modification.

1 Under FERC’s “reciprocity rule,” non-jurisdictional Transmission Providers must also “voluntarily” accept Order No. 2023 requirements in order to continue to receive open access transmission (and interconnection) service from FERC-jurisdictional Transmission Providers. 

2 The currently effective pro forma arrangements were established in accordance with earlier FERC interconnection rules issued between 2003 and 2006 and further refined over the intervening years.      

3 The pro forma LGIP defines an “Interconnection Customer” as “any entity any entity, including the Transmission Provider, Transmission Owner or any of the Affiliates or subsidiaries of either, that proposes to interconnect its Generating Facility with the Transmission Provider's Transmission System.” 

4 The pro forma LGIP defines an “affected system” as an electric system other than a Transmission Provider’s transmission system that may be affected by a proposed interconnection.

5 Ordinarily, if an Interconnection Customer makes a “material modification” to its interconnection request it will lose its queue position.   

6 FERC defines “nonsynchronous” resources as those that are “connected to the bulk power system through power electronics, but do not produce power at system frequency (60 Hz).”  Nonsynchronous resources “do not operate in the same way as traditional generators and respond differently to network disturbances.”  Wind- and solar-power generators are examples of non-synchronous resources.

7 “Ride through” capability refers to a resource’s ability to remain online during system events and to continue to provide real and reactive power following a disturbance.

8 See, e.g., https://www.democrats.senate.gov/newsroom/press-releases/building-on-work-in-inflation-reduction-act-leader-schumer-calls-on-ferc-to-make-americas-energy-grid-cheaper-cleaner-and-more-reliable (letter from Senate Majority Leader to Chairman Phillips urging action on transmission planning and cost allocation reforms).

Jump to Page