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FERC approved the first-ever merger of transmission planning and generator interconnection, possibly creating a template for clearing the national backlog. Read on for our breakdown and this week's key numbers.
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SPP consolidates planning to speed-up the queue
SPP just received approval for an ambitious tariff overhaul: a new plan that merges transmission planning and generator interconnection into a single process for the first time at any US RTO. The Consolidated Planning Process (CPP) cuts study timelines from over 400 days to roughly seven months and gives developers a standardized $/MW cost rate before they even submit an interconnection request. It could reduce the speculative entries and late-stage withdrawals, and become a template for clearing the national backlog.
What happened
On 13 March, FERC unanimously accepted SPP's proposed tariff revisions to establish the CPP framework, effective 1 March 2026. The CPP replaces SPP's separate Integrated Transmission Planning (ITP) and Definitive Interconnection System Impact Study (DISIS) processes with a single integrated framework built around two study horizons, operating on a three-year planning cycle:
CPP-20: A 20-year transmission assessment, conducted every three years, that serves as the big-picture planning tool. It determines Planned Interconnection Locations (PILs), or pre-designated interconnection zones where transmission capacity exists or is planned to accommodate new generation. It sets the GRID-C rates that give developers upfront cost certainty (more on those below).
CPP-10: An annual 10-year assessment that handles the actual Interconnection Cluster Study (ICS), through which developers queue up, select a PIL, and pay their GRID-C contribution upfront. Projects are then studied as a cluster, with SPP targeting delivery of interconnection agreements within seven months of submission, down from 400-plus days under DISIS.
The centerpiece innovation is the GRID-C rate, or the Generalized Rate for Interconnection Development-Contribution. This is a pre-set $/MW charge, calculated from the CPP-20 transmission portfolio costs, that tells every developer exactly what they'll pay for system network upgrades before they enter the queue. There are four rates: ERIS regional, ERIS subregional, NRIS regional, and NRIS subregional, mirroring SPP's existing Highway/Byway cost allocation structure. The revenues get credited back to load which offsets their transmission charges.
SPP will open its first CPP queue window in April 2026 and publish the first GRID-C rates this fall.
Mark's take
This is the most important grid reform story of the year so far. Everyone talks about the interconnection queue problem. SPP has made the most credible attempt to fix it yet.
For me, it all came into focus reading about CPP’s planned interconnection locations, or PILs. Through CPP, SPP is planning where interconnections should be built, and how much new capacity they can handle at that location -- then it can encourage interconnection requests that match those needs. Developers who build at PILs get predictable costs. Developers who go off-plan will take longer and likely pay more.
And that’s how you get the speed. CPP pre-answers the hard questions. By the time a project enters a study, it’s already met the readiness criteria and has a price via GRID-C. You get the speed not by doing it the old way but faster, but by working-out a lot of the uncertainties ahead of time.
Going forward, I'm watching two things. First is the GRID-C rate. GRID-C is a function of how well reality matches the 20-year plan. This first cycle has no track record to calibrate against. If SPP builds a large transmission portfolio but the generation that actually shows up is smaller or less well-matched than forecasted, the per-MW cost to interconnecting generators rises because there are fewer MWs to spread it across. This could put GRID-C too high for projects to pencil…and developers will go elsewhere. So the first GRID-C will be a major market signal.
The other is whether CPP becomes a template. SPP has 105GW in its queue. PJM has north of 140GW. MISO, CAISO, and NYISO are all struggling with the same planning-interconnection disconnect. In its approval, FERC gave CPP unusually high praise. Commissioner Chang called it "a bold step;” Commissioner Rosner called it "the innovation that America needs". That’s big hypeman energy from FERC, and a not-so-subtle hint to other RTOs to get moving. My guess is the other RTOs will give it that good hard look, but wait to see where the GRID-C price shakes out before submitting their own version.
Who this helps:
Renewable and storage developers in SPP. Cost certainty before submitting a request. Study timelines cut by more than half. PILs for where the grid can actually accommodate new generation.
Utilities and load-serving entities. The GRID-C revenue from generators offsets load's transmission cost obligations under Schedule 11. SPP estimates $100m+ in savings from avoiding duplicative extra-high-voltage projects alone, plus $6m in administrative savings every four years.
Transmission owners and developers (ITC Great Plains, etc.). A clearer, faster planning process means a more predictable pipeline of approved transmission projects. The subregional cost allocation -- 67% of 100-300kV project costs allocated to the subregion -- keeps the benefits closer to where the investment happens.
Who should be nervous:
Speculative queue participants everywhere. The CPP's financial security requirements are significantly higher than Order 2023 minimums. Non-refundable GRID FS payments at the Decision Point, plus 20% of any directly assigned upgrade costs. CPP will hit them where it hurts.
Developers betting on unplanned locations (UPILs). If you choose to interconnect at a location SPP hasn't pre-studied, you accept additional cost risk. You still pay the GRID-C, plus you may get hit with Directly Assigned Upgrade Costs for network upgrades below 100kV. Concerns came up in the FERC proceeding that UPIL customers face discriminatory treatment -- FERC disagreed, but the cost asymmetry is real.
Meter reading (12 Mar - 19 Mar)
A quick read on the numbers shaping the market. The capex, the contracts, the regs, all anchored in the so-what.
$12bn // the combined enterprise value of Google's $4.75bn Intersect acquisition and the simultaneous spinout of IPX Power, a new IPP launching with 4.4GW solar and 8.8GWh storage. That gives Google the in-house capability to build clean power generation co-located directly with its AI data centers, signaling a new hyperscaler playbook of owning the developer, not just buying the electricity.
704MW // Nameplate capacity of Orsted's Revolution Wind project, which began delivering power to the New England grid this week, enough for 350,000+ homes. The project was one of the five that the Trump administration halted construction on before Christmas over national security concerns, restarting after developers and states successfully sued. The project's survival despite federal headwinds shows that once steel is in the water and PPAs are signed, killing offshore wind projects might be harder than expected, but it’s an uphill battle.
$23.1bn // PJM's forecast data center load cost increase, across the last three capacity auctions, as quantified by its independent monitor. Wholesale power in PJM cost $67bn in 2025, up 54% from $43.5bn in 2024. Capacity costs drove the surge -- up 262% YoY, rising from 6.5% of total costs to 16%. This is the clearest data yet on what the AI buildout costs ratepayers.
$421m // Fervo Energy's non-recourse project financing for Cape Station, marking the first time an enhanced geothermal systems (EGS) project cleared the bankability bar. Non-recourse is the gold standard of infrastructure capital, and requires convincing a syndicate of banks that your technology and revenue stack are predictable enough to underwrite. RBC, Barclays, BBVA, HSBC, MUFG, Societe Generale, JPMorgan, BofA and Sumitomo just said yes. Apart from the commissioning of Cape Station, this is the signal EGS has been waiting for.
350MW // Google’s demand response at its new planned data center campus near Detroit in its partnership with DTE Energy, under the Clean Transition Tariff. Google has also said it plans to fund more than 2GW of new clean energy in Michigan to serve it. The hyperscaler is showing that "flexibility as speed to power" doesn’t mean regulators define pathways to faster interconnection, if data centers agree to be flexible. Instead, the hyperscaler is creating that pathway itself. This seems like a copy-paste playbook to get faster interconnection in exchange for flexing its data centers.
700 workers // the laid-off employees Ultium Cells is recalling to retool a Tennessee EV battery plant for lithium-iron phosphate energy storage production. GM and LG are pivoting excess EV battery capacity to BESS as slowing EV demand leaves them with more factory floor than they need. BESS demand is surging on the back of data center load growth, and they have the plant and workforce sitting idle. The LFP chemistry choice also confirms the tech’s dominance in stationary storage.
Explore more Signals on Sightline here.
On the docket
The policies, rulings, and company moves worth watching.
Virginia's 2026 General Assembly ending without a budget, deadlocking over data center tax exemptions. The session closed March 14 without a budget, with Senate Democrats refusing to pass one without a clause sunsetting data center tax breaks in 2027 and major regulatory bills, including SCC approval requirements for new data centers, all failed. Virginia is the world's largest data center market, and whatever framework emerges will set a precedent other states follow.
The first sodium-ion battery on the US grid. Peak Energy and RWE’s pilot, sited at the RWE lab near Milwaukee, marks a milestone for sodium-ion as a commercial grid storage technology — and the first deployment of the chemistry on the MISO network. Sodium-ion avoids the lithium, cobalt, and nickel supply chain constraints of conventional Li-ion batteries, and Peak's passively cooled design cuts lifetime storage costs by an average of $70/kWh, it says.
Massachusetts Gov. Healey exec order for 10GW of new resources and 5GW of storage by 2035. The order targets 4 GW of solar, 3.5 GW of demand reduction (efficiency, VPPs, EV charging management), and a separate 5 GW storage buildout, a direct response to Massachusetts having some of the highest electricity prices in the country.
New Mexico regulators’ probe into a $400m pre-merger stock sale between Blackstone and TXNM Energy. State regulators have launched a formal investigation into the transaction, adding regulatory risk to what is already an $11.5bn utility take-private. The probe could complicate or delay closing.
Trump administration considering $928m settlement to cancel two TotalEnergies offshore wind leases. After going 0-for-5 in court trying to halt wind farms already under construction, the administration is apparently drafting settlements that would pay TotalEnergies to abandon its Attentive Energy (NY) and Carolina Long Bay (NC) leases before construction begins, and commit the company to accelerated gas infrastructure investment in Texas. If TotalEnergies refuses, the administration says it will cancel the leases anyway, setting up costly litigation either way.
New & upcoming at Sightline Climate
The latest research, features, and data drops on the Sightline Climate platform.
Clean fuels have a feedstock problem. That’s the takeaway from our Q1 2026 Clean Fuels Outlook: HEFA is still the only scaled SAF pathway, but UCO is already tight, AtJ is emerging because ethanol is more abundant, and a lot of announced supply still hasn’t reached real project execution.
Then there's the even bigger supply crisis that everyone is already talking about. Our Fuels Analyst, Oliver Booth, published a take demonstrating how the current supply shock makes clean fuels look more strategic, but it also exposes how dependent much of the market still is on fragile global feedstock and shipping chains.
Events
Where the market is meeting, and where to find us
📅 Future of Utilities: Energy Transition Summit // Amsterdam, 18-19 March, 2026 // A key event on the European calendar for utilities, OEMs, and investors in the EU market. Join our Head of Research, Julia Attwood, on site.
📅 CERAWeek // Houston, 23-27 March, 2026 // Dubbed the Super Bowl of energy, where energy executives, policymakers, and technology leaders converge. Join our CEO, Kim Zou, on site.
📅 Europe Energy Tech Summit // Bilbao, Spain, 15-16 April, 2026 // Europe's premier energy innovation event, hosted at the Euskalduna Conference Centre. Join me, Charles Bondu, and our Head of Research, Julia Attwood, on site. (Powerstack subscribers can get 15% discount with the code: SIGHTLINECLIMATE)
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