Renewable project developers are bearing the burden of decades of transmission planning focused on transmission owner needs. Renewable projects are dropping out of generator interconnection queues because of the high cost of transmission upgrade costs. PJM, MISO, SPP are all dealing with the same issue – high volume of renewables projects in their interconnection queue. None of the transmission solutions proposed are anywhere close to construction in the next 5 years.
We need the Federal Energy Regulatory Commission (FERC) to step up to help renewable developers. We need multiple transmission projects and alternatives to transmission solutions to address this renewable need on the electric grid crossing state boundaries.
Traditional T planning is more focused on what the Transmission Owner needs, not what the RE developer wants
In normal transmission planning, the responsible planning authority is putting together a transmission line for meeting a) increased demand, b) retiring existing capacity, and c) replacing the old T line. With all of these options, it is the incumbent transmission owner who benefits. With a new capacity request, the interconnection customer’s responsibility is to pay for the transmission upgrade and the transmission owner to construct the upgrade.
At some Regional Transmission Organizations (RTOs), the interconnection customers can build, provided the transmission owner agrees.
PJM process and workshops
PJM started generator interconnection workshops. Out of 2,000 projects in 2020-21 in the PJM queue, only 225 have signed interconnection agreements. MISO and SPP were at the same stage PJM is currently. Both MISO and SPP have a revamped FERC process for interconnections that are still struggling to clear the backlog before the new process.
The new interconnection process at both MISO and SPP groups the studies received in a time window, then studies them together and assigns network upgrade costs to all the renewable projects based on their impact on transmission constraints. If PJM moves to this MISO and SPP process, we may expect similar delays.
An illustrative example of MISO South queue network upgrade costs
Below is an example of how capacity market prices impact project viability and why FERC should think of capacity market reform simultaneously with generator interconnection reform.
Take the case of a 150-MW solar project (J1465) in Louisiana. MISO’s study report shows only 55% of that capacity is deliverable to the market, and almost $32.5 million in transmission upgrade costs are assigned to the project. With a MISO capacity price of $7 per MW-day, it would take 85 years to recoup those upgrade costs. If the capacity price clears at the Cost Of New Entry (CONE) value of $250 per MW-day, it is less than 2 years for the payback period. We expect to know the latest capacity price for the Louisiana zone in mid-April 2021.
MISO T planning realizes this need to revamp cost allocation
Meeting MISO member TO needs is MISO T planning focus. Only 14% of the total 2020 MISO transmission expansion portfolio were driven by generator interconnection need. While it is important to plan for compliance with North American Electric Reliability Corporation (NERC) planning standards, it is also important to look at renewable project developers’ needs.
MISO realizes this, and hence it is worth noting here that MISO and SPP have a joint study to address their generator interconnection queue projects. The specific reason why this is important for developers is because projects at the border of both RTOs could have an impact on each other’s T plans. That could lead to an additional delay in the coordination of who has to pay and what share of network upgrades could result from running a MISO load flow model versus SPP’s.
Additionally, on a 3-year plan basis, MISO has started the cost allocation process for combining the generator upgrade projects and the current transmission project cost categories such as baseline reliability, market efficiency, and multi-value projects.
Renewable developers share some of the blame
There are too many speculative projects in RTO interconnection queues. Developers share some of the blame behind the backlogs because too many project requests are at the same point of interconnection, within the same county, and multiple requests by the same developer even though there is no way someone can pay for upgrade costs at multiple locations. Hence to reduce the backlog and have a cleaner slate of grid operator queues, RE developers should do their share of cleaning up the queue.
The Feds can help
The FERC can help by holistically looking at generator interconnection reform, hybrid interconnections (solar and storage at the same substation), capacity market, and transmission planning reform. Having a technical conference on each of these topics serially, providing time for written comments after the tech conference, then releasing a Notice of Proposed Rulemaking (NOPR), giving time for written comments to set the record, and then releasing a FERC Order takes at least 3 years. Developers don’t have that much time to tie up their capital.
It would be nice for the developers if the comment period ends with FERC Order, but it doesn’t because FERC gives RTOs time to file compliance plans and then implement them. And each RTO usually has the flexibility to implement a FERC Order because they all start from a different place. All this takes time that technology providers, states, cities, and communities don’t have to meet their renewable goals.
With new leadership at the Department of Energy (DOE) and new commissioners at FERC, all federal and state regulators need to focus on what the renewable project developers need.
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