In the September 26, 2023, meeting of the Interconnection Process Working Group (IPWG) stakeholders were invited to review and submit feedback on Initial Commercial Operations Date in GIAs (PAC-2023-3).
Please provide feedback by October 17, 2023.
Clean Grid Alliance Comments to the IPWG on Commercial Operation Date in GIAs
Oct 17, 2023
Clean Grid Alliance appreciates the opportunity to provide supportive comments on the presentation by EDPR renewables (https://cdn.misoenergy.org/20230926%20IPWG%20Item%2007a%20Initial%20Commercial%20Operations%20Date%20in%20GIAs%20(PAC-2023-3)630278.pdf) regarding the benefits of allowing the initial COD date to be either 3 years from the requested date, or the earliest date the Network Upgrades can be completed, utilizing reasonable efforts by the Transmission Owner. This change is needed to address supply chain issues both transmission owners and generators are facing today, and will not be resolved any time soon. The change should be retroactive, applying to projects that are already experiencing the issue and would otherwise need to seek individual waivers that are extremely burdensome and resource intensive for both MISO and project developers. The expected cost and time savings to MISO with this change are significant, as the number of projects facing construction delays due to circumstances beyond their control is significant today, and does not appear to be slowing down any time soon.
Cordelio Power Comments to the IPWG on Commercial Operation Date in GIAs
Oct 17, 2023
Cordelio Power appreciates the opportunity to provide supportive comments on the presentation by EDPR renewables. Which outlined the many challenges developers face that may cause delay in projects COD. Given all the uncertainties and external market forces. We believe using the first estimated COD in the interconnection application to limit developers’ final COD is not reasonable.
As such, we believe that the provision in GIP Section 4.4.4 that limits the COD that is put into the GIA to be within three years of the original interconnection request should be removed. Although developers anticipate delays in the interconnection process (which is historically the critical path for many projects). Together with recent market supply chain challenges, it is extremely difficult to accurately select an initial COD.
For example, HV breakers and large transformers are the most affected, where products that previously had 12-18 months lead times can now have 4+ year lead times. Other supply chain issues for various components are anticipated to persist in the foreseeable future.
Also, MISO has recently had such significant delays that predicting an accurate COD at the time of project submission is impossible. ICs also attempt to estimate potential TO upgrade timelines and include this in their requested CODs, but actual TO estimates of these timelines are not available until later, upon issuance of the Facilities Study.
While it is true that interconnection customers can come online up to three years after the initial COD in their GIA via the GIA extension provisions. It would be beneficial for all parties if the most accurate COD known at the time of GIA negotiation, is memorialized in the GIA rather than the outdated COD from the time of the interconnection application. Lastly, if the current 3-year window is exhausted, an automatic extension should be granted once the developer demonstrates reasonable commercial progress.
Transmission Owners Comments on Initial Commercial Operations Date in GIAs
October 17, 2023
In the September 26, 2023, meeting of the Interconnection Process Working Group (IPWG) stakeholders were invited to submit feedback regarding the Initial Commercial Operations Date in GIAs (PAC-2023-3), and the Transmission Owners’[1] (TOs or Owners) feedback on the following questions posed by MISO is below:
Owners’ Responses
(1) For projects that have experienced delays in timely construction after GIA execution, what specific areas of Tariff remedies do you feel are inadequate and why?
Notwithstanding the foregoing, in the limited circumstance that the Interconnection Request is served by a contingent Network Upgrade with an in-service date that is farther out than the Commercial Operation Date permitted under this Section 4.4.4, Transmission Provider shall only terminate the GIA for failure to achieve Commercial Operation by that later in-service date of the contingent Network Upgrade.
While the language above appears to be intended to address the concern expressed in the Issue submitted by EDP Renewables (see below), it does not specify what will happen with the GIA, which will have a COD that is not possible for the IC to meet. This ambiguity creates issues for all three parties to the agreement because a generator reaching COD is the trigger for many obligations like:
Rather than simply stating that the agreement will not be terminated, the tariff should state that the Agreement will be amended as appropriate to reflect a feasible COD, and the process and timing for making these amendments should be outlined more clearly.
MISO should also consider whether adjustments to the list of exceptions for extending the Initial COD should also include the delays to the in-service date of upgrades being constructed by the Transmission Owner, and whether those exceptions should also apply to the second extension, which does not currently require any demonstration of progress.
Notwithstanding the foregoing, in the limited circumstance that a the Interconnection Request is served by a contingent Network Upgrade necessary to enable full commissioning of a Generating Facility with an in-service date that is farther out than the Commercial Operation Date permitted under this Section 4.4.4, Transmission Provider shall only terminate the GIA for failure to achieve Commercial Operation by that later in-service date of the contingent Network Upgrade necessary for full commissioning of a Generating Facility.
(2) What are the specific industry issues preventing timely engineering, procurement, and construction of facilities?
Industry issues preventing timely engineering, procurement, and construction of facilities are supply-chain issues resulting not only from COVID, but also increased demand for the resources needed to complete these projects, as more renewable generation is being built in a geometric-growth manner. Of note, breaker lead times are currently out 3 to 4 years.
The prolonged delays associated with getting projects through the MISO DPP affects both the IC and TOs relative to the ability to limit extending the COD to the original COD in the application regardless of how long the request was submitted relative to the negotiation of the GIA. The CODs requested in the queue application should be allowed to be pushed out when agreeable to both the TO and the IC. When a GIA is being negotiated, the COD included in the GIA should not be infeasible at the time of execution or require an immediate amendment to resolve. A limit of extensions to the Commercial Operation Date or In-Service Date to not exceed three years beyond the original Commercial Operation Date or In-Service Date is often not possible in the time remaining after the DPP is complete and the IC can begin construction activities, which are impacted by equipment lead times and construction labor availability.
Reference:
Attachment X, 4.4.4:
After entering the Definitive Planning Phase as defined in Section 7.2, any extension by Interconnection Customer or MHVDC Connection Customer to the In-Service Date or Commercial Operation Date of the Generating Facility or MHVDC Transmission Line shall be deemed a Material Modification except that the Transmission Provider will not unreasonably withhold approval of an Interconnection Customer’s or MHVDC Connection Customer’s proposed change in the In-Service Date or Commercial Operation Date of the Generating Facility or MHVDC Transmission Line if that change is the result of either
(a) a change in milestones by another party to the GIA or TCA,
(b) a change in a higher queued Interconnection Request,
(c) delays in the completion of the Definitive Planning Phase Studies, or
(d) Interconnection Customer demonstrates that engineering, permitting and construction of the Generating Facility will take longer than the process window for the Transmission Provider’s Definitive Planning Phase period.
Where such exceptions apply, extensions to the Commercial Operation Date or In-Service Date shall not exceed three years beyond the original Commercial Operation Date or In-Service Date. A change to either of these dates that exceeds three years from the date in the original Interconnection Request is a Material Modification. At the completion of the Definitive Planning Phase, the Commercial Operation Date shall be set forth in a GIA. Consistent with Article 2.3.1 of the GIA, once that GIA is executed or filed unexecuted, if the Generating Facility fails to reach Commercial Operation by the Commercial Operation Date set forth in the GIA, such Commercial Operation Date as set forth in the GIA may be extended by Interconnection Customer for a period up to three (3) consecutive years,] after which Transmission Provider shall terminate the GIA if the Generating Facility has still failed to reach Commercial Operation. Notwithstanding the foregoing, in the limited circumstance that the Interconnection Request is served by a contingent Network Upgrade with an in [1] service date that is farther out than the Commercial Operation Date permitted under this Section 4.4.4, Transmission Provider shall only terminate the GIA for failure to achieve Commercial Operation by that later in-service date of the contingent Network Upgrade.
Xcel Energy believes that the Tariff includes sufficient remedies to address the issue raised by EDP at the September 26, 2023 Interconnection Process Working Group. Providing additional remedies may produce unintended consequences and would essentially reintroduce Suspension into the generator interconnection process.
Xcel Energy recommends that BPM-15 and Attachment X be updated to provide additional details on the remedies available under Attachment X, Section 4.4.4.
In addition, if MISO and stakeholders determine additional relief is needed beyond the those included in the tariff, that the new requirements are also extended to Generator Replacement Projects.
National Grid Renewables (NG Renewables) appreciates that MISO (Midcontinent Independent System Operator) has requested feedback on Initial Commercial Operations Date in GIAs during its September 2023 Interconnection Process Working Group (IPWG) meeting.
NG Renewables acknowledges that there is a need to modify and amend the tariff to increase the three years between the projected COD provided in the initial Generation Interconnection Application and the COD committed to the Generation Interconnection Agreement (GIA). Moreover, MISO could also consider amending the tariff to increase the three-year grace period that extends the GIA’s injection rights for up to three years after the date listed in the GIA.
There are three major reasons that drive the need for that increase:
NG Renewables owned projects have been affected by all three factors listed above, and therefore we strongly recommend revising the tariff language to ensure that the Interconnection Customer can have a COD date in the GIA for up to five (5) years after the date initially listed in the application. If this goal is unachievable, NG Renewables would also recommend increasing the GIA’s injection right grace period for up to four (4) years after the COD listed in the GIA.
Thanks,
Nitin Kushwaha
Clearway Energy Group LLC (Clearway) appreciates the opportunity to provide feedback in response to Initial Commercial Operations Date in GIAs (PAC-2023-3) topic presented at the September 26, 2023 Interconnection Process Working Group (IPWG) meeting. We support the comments submitted by Clean Grid Alliance and offer the following additional comments. Section 1 summarizes our recommendations, while section 2 provides supporting detail.
1.0 Clearway’s Recommendations
Clearway recommends that MISO update and clarify the Tariff to allow the initial COD date to be either 3 years from the requested COD date or the earliest date all Network Upgrades and Interconnection Facilities can be completed utilizing reasonable efforts by the Transmission Owners. The Network Upgrades are the upgrades required for the interconnection projects to provide the levels of interconnection services they requested, which include Network Upgrades (both within MISO region and in Affected Systems) identified for the interconnection generator projects from the DPP cycle the interconnection projects are in and the contingent network upgrades from the prior cycle.
1.2 Allow generation COD adjustments beyond 3-year grace period in the following circumstances post execution of LGIA, in addition to the permitted circumstances in the current Tariff.
Clearway recommends that MISO revise and clarify the Tariff to allow adjusting projects’ COD for the following reasons:
The MISO current Tariff GIP 2.3.1 describes the scenario where an interconnection request is served by a contingent Network Upgrades with an in-service date that is further out than the COD provided for under 4.4.4, in which case the GIA cannot be terminated until the in-service date of the contingent Network Upgrades. MISO should clarify and define what are contingent Network Upgrades. We recommend that MISO should define contingent Network Upgrades as the upgrades required for the interconnection projects to provide the levels of interconnection services they requested, which include Network Upgrades (both within MISO region and in Affected Systems) identified for the interconnection generator projects from the DPP cycle the interconnection projects are in and the contingent network upgrades from the prior cycle.
When projects experience a Force Majeure event under the terms of the LGIA.
When a project can demonstrate that a supply chain issue outside the Interconnection Customer’s control is materially impeding the ability to meet COD. Please refer to Section 2.2 for more details around supply chain issues.
COD adjustment based on PPA off-take load-serving entities’ load-serving timeline need: to match generation resource build-out with load serving entity’s load-serving need. Such an extension would be warranted only if the project has a signed PPA, and load serving entity customers need the resource later than the COD of the generator customer.
We also recommend MISO calculate and publish annual ERIS and NRIS availabilities for the next 5 years for each project with an executed conditional Interconnection Agreement and other projects that will come online before their Network Upgrades are in service to enable those projects to project their energy and capacity volumes and, in turn, finance the project and meet their PPA obligations.
2.0 Flexibility is needed to address multiple barriers that can prevent Interconnection Customers from achieving on-time COD
2.1 FERC provided clear guidance in 2017 to MISO that a Transmission Provider should not force a customer to use a COD that is earlier than the in-service date of the Network Upgrades that would permit the requested interconnection service level.
Our understanding is that the language in MISO’s LGIP section 2.3.1—which precludes MISO from terminating the LGIA where the interconnection request requires a contingent Network Upgrade with an in-service date that is later than the COD—stems from a section 206 proceeding FERC initiated in 2017 where it found that at the time that LGIP section 4.4.4 was inconsistent with LGIA section 2.3.1. In its order directing MISO to revise the tariff, FERC clarified that section 4.4.4 should be revised to reference LGIA section 2.3.1. FERC also required that, once the LGIA is executed or filed unexecuted, three years must lapse before MISO can terminate the LGIA. Additionally, when the three years lapses, MISO must seek to terminate the LGIA except in the limited circumstance where an interconnection request be served by a contingent Network Upgrade with an in-service date that is later than the COD otherwise permitted under MISO’s tariff. In support, FERC cited to a 2014 SPP order where it was addressing proposed SPP generator interconnection procedure changes and characterized the order as finding that a Transmission Provider should not force a customer to use a COD that is earlier than the in-service date of the Network Upgrades that would permit the requested interconnection service. See Midcontinent Indep. Sys. Operator, Inc., 161 FERC ¶ 61,076, at P 11 & n.14 (2017).
Furthermore, in a 2014 SPP order, one of the proposals related to limited operation where SPP was proposing to require the advancement of previously approved NU and have the Interconnection Customer pay for it. SPP requested FERC to clarify that, if FERC would not allow SPP to require the advancement of previously approved network upgrades, all Interconnection Customers must meet their original commercial operation dates regardless of the in-service dates of previously approved Network Upgrades. FERC disagreed with SPP’s contention that all Interconnection Customers must meet their original CODs regardless of the in-service dates of previously approved Network Upgrades. FERC found that its pro forma LGIP does not require this and that SPP had not justified its proposal. See Southwest Power Pool, Inc., 147 FERC ¶ 61,201, at PP 99 & 114 (2014).
Notably, in 2015, MISO relied on FERC’s statement in the 2014 SPP order in a proceeding involving the LGIA for Mankato, an NRIS project, to support the fact that it had extended the COD for Phase II of Mankato’s project to 2018 to match the in-service date for NU required to support that phase of the project. MISO also indicated in the proceeding that it does not require a project to achieve commercial operation prior to the in-service dates of the full required Network Upgrades and contingent facilities for a project. See Midcontinent Indep. Sys. Operator, Inc.,150 FERC ¶ 61,180, at PP 7 & 20 (2015).
2.2 Study and procurement delays are persistent.
DPP studies have been taking an average of 3-4 years and we expect this timeline to increase. In addition, supply chain issues are impacting schedules for both Transmission Owners and Interconnection Customers and will continue to be challenging. In our experience, procuring main power transformers can take up to 3-4 years from the initial down payment, while procuring high voltage breakers can take 2-3 years. Collectively, these study and procurement delays impede Interconnection Customers from performing undercurrent COD requirements, where in projects can only set the initial COD date to be 3years from the originally requested COD, and then after LGIA execution, only a 3-year grace period is provided.
2.3 Mismatches between COD and in-service dates for Network Upgrades can jeopardize project financing.
Projects that must achieve COD before Network Upgrades are in service risk being able to secure financing. Lenders, for example, operational project investors that are accustomed to taking operational project risk, will be asked to take construction risk (by virtue of the construction risk associated with the Network Upgrades, which are managed and constructed by Transmission Owners), risking the ability of the project to raise permanent capital. If there is uncertainty regarding the project's ability to raise permanent capital due to contingent NUs not in-service, construction financiers will balk at providing construction loans without assured take-out capital at COD.
2.4 For projects with PPAs, mismatches between COD and in-service dates for Network Upgrades also threaten a project’s ability to fulfill its obligations to an off-taker.
Projects that must achieve COD before Network Upgrades are in service cannot meet their PPA obligations that require predictable and fixed levels of ERIS and NRIS. In such cases, ERIS and NRIS levels can vary from year to year, depending on system configuration, load, other generation that comes online, etc. Until the required Network Upgrades enter service, projects would have a hard time projecting the level of interconnection services to fulfill its PPA obligations, and to contract with load serving entities to meet their resource adequacy requirements.
Furthermore, sometimes load serving entities require renewable generation to provide bundled products (energy, capacity, and sometimes ancillary services). They do not accept bifurcated product schedules, meaning they don’t procure from a generation interconnection project where it can deliver ERIS first and then NRIS after the NRIS upgrades are in place.
2.5 The current COD requirements are out-of-sync with the planning and construction timelines for regional transmission projects and transmission upgrades from Affected Systems, upon which a growing number of Interconnection Customers depend.
MISO is on the leading edge of proactive regional transmission planning, including through its LRTP process, JTIQ, and other transmission planning initiatives. These large regional transmission planning efforts take a long time to unfold. Meanwhile, a growing amount of new generation depends on these transmission projects. In addition, the Affected System upgrades take even longer time to be planned and constructed. The result of that is the current 3+3 year COD requirements for generator interconnection projects are out-of-sync with planning and construction timelines for regional transmission projects. If generator projects continue to be required to come online before contingent Network Upgrades (for example, same cycle MISO network upgrades, prior-cycle upgrades, and Affected System upgrades) are in place, this misalignment between transmission and generation development timelines will exacerbate the challenges we highlight above pertaining to project financing and meeting PPA obligations.
Comments Prepared and Submitted by Clearway Energy Group:
Ling Hua (Grid Integration), Chris Barker (Grid Integration), John Miller (Market & Policy), and Gretchen Schott (Regulatory Counsel)
October 17, 2023
Ørsted Onshore North America Feedback on Commercial Operation Dates in GIAs
Please accept the following comments in support of the position taken by EDP Renewables at the September 2023 Interconnection Process Working Group meeting. Specifically, Ørsted Onshore North America (Ørsted) supports revising the language in Attachment X, Appendix 1, Section 4.4.4 of the MISO Tariff to allow the Commercial Operation Date or In-Service Date to be the later of either three years from the requested date, or the earliest date the Network Upgrades can be completed, utilizing reasonable efforts by the Transmission Owner.
Currently Section 4.4.4 of the MISO Tariff appropriately provides exceptions to when changes in the In-Service Date or Commercial Operation Date of the Generating Facility will not be considered a material modification and allows a three-year extension of the Commercial Operation or In-Service Date to bring the project online. The slight change proposed above recognizes that there are issues impacting both the generation developer and transmission owner that affects when a resource may be able to come online. This is especially true in the economic environment seen today with supply chain constraints, inflation, and high interest rates.
Given the far-reaching impact of the economic conditions that we have seen in the past few years and will continue to see going forward, Ørsted requests that the changes be applied retroactively. This would help ensure that the proposed changes would apply to projects that are currently experiencing delays without the need to seek individual waivers which is burdensome and resource intensive for both MISO and generation developers.
Thus, the changes discussed above will help address issues for generation developers, transmission owners and MISO. Ørsted appreciates the opportunity to comment and requests that the proposed changes be made to the Tariff and that the changes be applied retroactively.
Respectfully Submitted,
Lopa Parikh
Head of Electricity Policy
(857) 291- 6592
EDP continues to advocate for the preferred Tariff solution. Modifying the Tariff creates the most equity between Interconnection Customers. It also provides a permanent solution to the problem we are likely to see well into the future. Finally, it limits the number of waivers needed and the uncertainty with FERC's approval of waviers. EDP would recommend adding "the later of" to the language it proposed in the issue statement.
EDF Renewables (EDFR) supports the position taken by EDPR presented at the September 2023 IPWG. As the volume of interconnection requests that are entering GIA negotiations continues to rise, and due to the fact that many those requests were submitted prior to dealing with current market conditions, EDFR strongly suggests that MISO pursue Tariff modifications to deal with this issue in the most efficient manner rather than the current project by project approach that requires significant resources from both generators and MISO.
The contributing factors include but are not limited to the following:
While it is certain that each project is unique, these issues noted above are common to a large group of queue projects. MISO’s current stance of addressing on an individual project by project basis has a number of significant flaws, including the below:
For upcoming GIA negotiations, an easy solution would be to simply provide for the in-service/commercial operation dates to slide to the later of a) 3 years after the initial dates proposed in the application or b) the soonest date reasonably accommodated by the TO. See below proposed edits to Attachment X, Appendix 1, Section 4.4.4. This would proactively eliminate the issue for all projects moving to GIA after the Tariff changes are made effective and significantly reduce administrative and cost burdens for MISO, ICs, and TOs.
For projects that have had to execute GIAs with CODs that are in advance of the In-Service date that the TO can accommodate, a FERC waiver request could be submitted to provide a full 3 years past the COD that could reasonably be accomplished given a reaslistic TO schedule.
MISO could easily address this in a proactive manner as suggested above and save significant headaches having to deal with this same issue for hundreds of projects in the near future.
After entering the Definitive Planning Phase any extension by Interconnection Customer or MHVDC Connection Customer to the In-Service Date or Commercial Operation Date of the Generating Facility or MHVDC Transmission Line shall be deemed a Material Modification except that the Transmission Provider will not unreasonably withhold approval of an Interconnection Customer’s or MHVDC Connection Customer’s proposed change in the In- Service Date or Commercial Operation Date of the Generating Facility or MHVDC Transmission Line if that change is the result of either (a) a change in milestones by another party to the GIA or TCA, (b) a change in a higher-queued Interconnection Request, (c) delays in the completion of the Definitive Planning Phase Studies, or (d) Interconnection Customer demonstrates that engineering, permitting and construction of the Generating Facility will take longer than the process window for the Transmission Provider’s Definitive Planning Phase period. Where such exceptions apply, extensions to the Commercial Operation Date or In-Service Date shall not exceed the later of (a) three years beyond the original Commercial Operation Date or In-Service Date or (b) the earliest In-Service date that the Transmission Owner can accommodate, and a Commercial Operation Date set accordingly. A change to either of these dates that exceeds three years from the date in the original Interconnection Request is a Material Modification. At the completion of the Definitive Planning Phase, the Commercial Operation Date shall be set forth in a GIA. Consistent with Article 2.3.1 of the GIA, once that GIA is executed or filed unexecuted, if the Generating Facility fails to reach Commercial Operation by the Commercial Operation Date set forth in the GIA, such Commercial Operation Date as set forth in the GIA may be extended by Interconnection Customer for a period up to three (3) consecutive years, after which Transmission Provider shall terminate the GIA if the Generating Facility has still failed to reach Commercial Operation. Notwithstanding the foregoing, in the limited circumstance that the Interconnection Request is served by a contingent Network Upgrade with an in-service date that is farther out than the Commercial Operation Date permitted under this Section 4.4.4, Transmission Provider shall only terminate the GIA for failure to achieve Commercial Operation by that later in-service date of the contingent Network Upgrade.