An idea to clear out the SPP interconnection queue backlog to reduce renewable PPA costs
Clearing the current queue backlog is the focus of the Southwest Power Pool (SPP) generator interconnection staff. However, they are missing a key long-term solution to address the root cause of backlog, identifying network upgrade costs for developers.
Indeed, renewable energy (RE) developers could check if alternatives to network upgrades exist if these developers have study results in hand.
SPP staff should run multiple Definitive Interconnection System Impact Study (DISIS) study cycle models to identify the portfolio of network upgrades. That study would indicate possible costs for developers. As a result, they would then choose to stay in the queue or drop out. If RE developers default in PPAs due to SPP queue delays, that ultimately would increase the cost of the renewable projects.
SPP queue stats and background
SPP has 100 GWs of capacity of renewable energy projects in its backlog. These are from 533 interconnection customer (IC) requests. Unlike PJM, SPP is focused solely on clearing out the generator interconnection queue backlog. SPP’s generator queue backlog is not higher in volume than PJM’s 2000 projects and 200 GWs backlog.
Similar to PJM, SPP must seek multiple stakeholder committee approvals before FERC tariff filing. In SPP’s case, the Markets and Operations Policy Committee (MOPC) is the top committee that must review and approve the SPP stakeholder’s perspective.
SPP’s recent reforms
SPP’s lower stakeholder committee, Strategic & Creative Re-Engineering of Integrated Planning Team (SCRIPT), recently approved unanimously 3 strategies to reduce their current backlog. These include
- 1) reducing restudying by increased site control requirements and non-refundable DISIS study deposits,
- 2) increasing financial commitments from $2,000/MW to $4,000/MW, and making 25% of financial security “at-risk” payments after the start of phase 1 and end of decision point 1, and
- 3) streamlining DISIS study cycles by combining 2018 and 2019 and other study improvements.
So, what is missing?
None of the SPP SCRIPT changes address the core problem in the generator interconnection queue backlog – network upgrade cost estimates. If ICs know the transmission upgrade cost of interconnecting their solar project at the point of interconnection, they would be prepared to stay in the queue or drop out after submitting their request. But those upgrade costs are not unknown until SPP staff runs the model. And when ICs drop out, SPP must restudy.
The only way to avoid this would be for SPP staff to indicate potential transmission upgrade costs for each DISIS cycle.
What are the possible solutions?
I see at least 2 possible solutions in the interim for projects already in the queue waiting for SPP’s DISIS study results.
The first possible solution is IC having the option to trigger a study on their own to evaluate alternative Grid Enhancing Technologies (GETs) such as SmartValves or Dynamic Line Ratings (DLRs). That option would provide SPP staff and the Transmission Owner (TO) data on the possible options for the IC without dropping from the queue because the alternative is that a SPP study result shows a need for more than $10 million upgrade costs, which typically leads to the customer dropping out.
It’s time to use accurate line ratings
Wanted – creative transmission owners willing to try alternatives to network upgrades!
Running a study with all the projects in the queue to identify network upgrades for each DISIS cycle
The second possible solution is to avoid this need for multiple DISIS restudies and reduce the SPP and TO back and forth with the IC for study results.
What if SPP staff did proactive generator interconnection planning by studying all the network upgrades needed to accommodate DISIS 2018 cycle? This list of network upgrades needed to accommodate one interconnection cycle is the “portfolio of projects,” and their combined interconnection costs provide ICs an overall range for what could be their cost estimate.
Running an iterative process, SPP staff could perform a similar analysis for DISIS 2019 cycle. And similarly, for DISIS 2020 cycle. Knowing what the needed network upgrades and their overall costs are is crucial for the ICs. Then, the customers would be able to choose to either stay in the queue or drop out much sooner than the current practice, clearing the SPP staff workload. Additionally, this approach would provide TOs the data on what transmission projects would be needed in the long term to accommodate multiple generator requests.
Why is it important to know common network upgrades that apply to multiple DISIS cycles?
If SPP or PJM staff follow their normal queue cycles, renewable developers could be missing the In-Service Date (ISD) for their Power Purchase Agreements (PPAs). Once PPAs are in default, that has a downstream impact of increasing the costs of entering into future PPAs due to legal costs from tighter default controls and consolidation of RE developers who can afford those legal costs.
Lack of a diverse RE developer supplier pool means higher RE project costs to ratepayers. All this is avoidable at SPP, where the queue volumes are not as high as PJM’s! If SPP planning staff were to simply run combined DISIS cycle studies to determine the overall network upgrade portfolio, many problems could be avoided.
Shaking the queue backlog tree takes multiple paths. None shakes the tree stronger than providing what the RE developers need first and foremost – a network upgrade cost estimate. This idea of a common network upgrade identification for multiple DISIS studies would provide that desired data for ICs.
High hopes for MISO SPP joint interconnection study
A joint MISO SPP interconnection study underway could serve as a template for future MISO and PJM joint interconnection studies and other joint RTO studies. Stakeholders expect that MISO and SPP generator interconnection staff will identify the common network upgrades on their “seam.” The truth of the matter is Affected Systems studies are dragging the interconnection study timelines.
Developers could miss ISDs when their project has an impact on neighboring RTO’s transmission system. That coordination is not seamless yet because RTO-RTO coordinate first, then the RTO-TO coordinates. Unless developers are proactive, studies that impact multiple RTOs take even more time than regular DISIS studies in SPP or Definitive Planning Phase (DPP) studies in MISO.
Does SPP have staff to keep both FERC and interconnection customers happy?
The bottom line is that RTOs have limited interconnection engineers. RTOs must continue to plan for the transmission system while processing IC requests. Hiring more interconnection engineers is possible, but that takes time, as evidenced by recent PJM interconnection staff turnover. As soon as RTO engineers develop expertise, they get hired away by reputable renewable developers.
There is no grand solution that solves RTO interconnection queue backlogs in an instant. SPP RTO staff are right to focus on the existing queue backlog. However, they are missing the crucial piece of data that RE developers need regarding network upgrade costs.
Allowing ICs to find if GETs are a viable alternative to network upgrades for projects with the study results and identifying the portfolio of network upgrades needed for multiple DISIS cycles would help shake the queue backlog tree more. If that were implemented then only the ICs who could pay those network grades would stay in the queue. That reduces the overall cost of RE projects in the long term; otherwise, if RE developer’s default in their PPAs because they cannot meet the in-service dates, nobody wins. Also, SPP staff workload frees up for FERC tariff and other transmission planning work.
Source: Renewable Energy