Interconnection Is Not One Milestone: A Signed IA Can Still Leave an Eight-Month COD Gap
Fox Run Solar is a 200 MW project targeting December 2029 commercial operation.
Before the interconnection studies are complete, the sponsor's model says:
Solar project 200 MW
Target COD Dec-2029
Interconnection / utility allowance $20m
Then the study process comes back with an illustrative result:
Transmission-provider interconnection work $12m
Network upgrades $38m
Affected-system work $7m
----
Total identified grid-side cost $57m
The model was carrying $20 million.
The current grid package is $57 million.
That is a $37 million capex increase before anyone discusses schedule.
Now add the schedule.
Fox Run's EPC contractor can finish the plant in December 2029.
The transmission work required for full interconnection service is not expected to be ready until August 2030.
The project can therefore be mechanically complete and still unable to operate as modeled for eight months.
Assume, purely to put the delay into financing dollars, that average construction debt outstanding during those eight months is $180 million at 7%.
$180m × 7% × 8 / 12
= $8.4m additional interest
Fox Run's current interconnection surprise is therefore at least:
Upgrade cost above underwriting $37.0m
Illustrative extra debt carry 8.4m
------
Combined identified impact $45.4m
before lost revenue, PPA delay consequences, tax timing or other extension costs.
And Fox Run can still truthfully say:
We have an interconnection agreement.
That is why “Does the project have interconnection?” is the wrong question.
Start by asking which milestone the project actually has
Interconnection is a sequence.
For Fox Run:
Interconnection request
↓
Queue / cluster position
↓
Cluster study
↓
Restudy, if required
↓
Facilities study / detailed scope
↓
Interconnection agreement
↓
Engineering / procurement / construction
↓
Energization and commissioning
↓
Interconnection service usable as modeled
Each step removes a different uncertainty.
A queue position says the project has entered a process.
A study result says something about grid impacts, upgrade scope and cost.
An executed IA creates contractual rights and obligations.
Energization says the physical system can actually begin operating.
Those are different assets from a financing perspective.
The POI is already an economic assumption
Fox Run connects at a specific 230 kV point of interconnection in our example.
Move the POI and the project can change:
- gen-tie length;
- substation scope;
- network-upgrade requirements;
- affected-system impacts;
- losses;
- nodal basis;
- permitting;
- land rights; and
- schedule.
So the POI should not sit only in the electrical one-line.
It is an input to the investment case.
Before the studies are firm, I would keep at least:
Preferred POI
Alternative POI
Gen-tie miles
Estimated direct facilities
Estimated network upgrades
Expected schedule
Nodal revenue / basis assumption
on the same development page.
A cheaper site can be a more expensive project if it connects to the wrong part of the grid.
A queue position is not a right to inject 200 MW
Order No. 2023 changed the federal pro forma process toward cluster studies and stronger readiness requirements.
That reform makes the queue a more disciplined study process.
It does not turn the queue number into transmission capacity.
Fox Run can have:
Valid interconnection request YES
Cluster position YES
Site control YES
and still not know its final network-upgrade scope.
The cluster matters because Fox Run is studied together with other projects whose presence or withdrawal can change:
- power-flow impacts;
- which upgrades are required;
- cost allocation; and
- whether a restudy is needed.
So years spent in the queue do not economically “vest” a 200 MW grid right.
The project earns certainty as the process advances.
The study result converts grid physics into project capex
Fox Run's $57 million package has three economically different pieces.
Interconnection facilities
These are the facilities that connect the generating facility to the transmission system.
The pro forma documents distinguish the customer's facilities from the transmission-provider side of the interconnection.
The exact ownership and construction split belongs in the IA.
Network upgrades
FERC's pro forma LGIP defines Network Upgrades as additions, modifications and upgrades to the transmission system at or beyond the point where the interconnection facilities connect, required to accommodate the generating facility.
For Fox Run:
Network upgrades = $38m
That number is not simply another EPC line.
It can depend on transmission-owner engineering, equipment procurement, outages and construction.
Affected-system work
Fox Run can also affect another transmission system.
Order No. 2023 established a more standardized affected-system process with pro forma agreements and modeling requirements.
Our example carries:
Affected-system work = $7m
If the financial model tracks only the host-system study, it misses that exposure.
Cost and schedule have to be modeled together
Suppose Fox Run's study says:
Network upgrade cost $38m
Required in-service date Aug-2030
The sponsor cannot fix the financing model by changing:
Interconnection capex
$20m → $57m
and leaving December 2029 COD untouched.
The same study has changed two variables:
Cost
and
critical-path date
The schedule change can affect:
- construction-loan interest;
- availability-period expiry;
- PPA COD;
- delay security;
- tax-credit milestones;
- tax-equity funding;
- debt conversion;
- revenue start; and
- sponsor liquidity.
The $8.4 million carry example is intentionally simple.
A full model should push the eight-month delay through every document whose date is tied to energization or COD.
An executed IA is not the same thing as completed transmission work
This distinction is the heart of Fox Run.
Assume the IA is executed in 2028.
The contract may now establish:
- the generating facility and interconnection service level;
- required facilities and upgrades;
- construction responsibilities;
- milestone dates;
- payments and security;
- operating requirements; and
- rights around assignment, default and termination.
That is a major bankability step.
But the substation and line work do not appear because the agreement was signed.
Fox Run can therefore have:
IA executed YES
Sponsor construction complete YES
Transmission upgrades complete NO
Full energization available NO
The lender should never let those four statements collapse into one cell called:
Interconnection = Complete
Interconnection service does not itself give Fox Run transmission service
The federal pro forma documents distinguish Energy Resource Interconnection Service and Network Resource Interconnection Service.
Energy Resource Interconnection Service allows the customer to interconnect and be eligible to deliver output using available transmission-system capability on an as-available basis.
Network Resource Interconnection Service studies and interconnects the resource in a manner comparable to Network Resources.
But the pro forma definition is explicit on both concepts:
interconnection service in and of itself does not convey transmission service.
That matters commercially.
A signed IA does not, by itself, answer every question about:
- firm transmission rights;
- PPA delivery obligations;
- congestion;
- capacity-market accreditation; or
- regional deliverability constructs.
Those are additional market and tariff questions.
In PJM, for example, ELCC and Accredited UCAP add another layer to capacity value.
Do not read “NRIS” in an interconnection file as a dollar value in a capacity-revenue line without following the applicable regional rules.
The point of change of ownership and the POI are not necessarily the same point
The pro forma LGIP distinguishes:
- the Point of Change of Ownership, where the Interconnection Customer's facilities connect to the Transmission Provider's interconnection facilities; and
- the Point of Interconnection, where the interconnection facilities connect to the transmission system.
That distinction can sound legalistic until a lender asks:
Who owns the transformer that failed?
or:
Which party is responsible for the equipment whose procurement is delaying energization?
Fox Run's asset register and insurance schedule should line up with the IA ownership boundary.
The construction schedule should do the same.
The party map belongs beside the milestone map
For Fox Run, one organization may administer the queue while another owns and constructs the physical transmission equipment.
An affected system can add a third.
So keep a party matrix:
| Workstream | Responsible party |
|---|---|
| Queue / cluster administration | Transmission Provider / ISO-RTO, as applicable |
| Host-system study | Transmission Provider / designated study party |
| POI facilities | Per IA ownership / construction allocation |
| Network upgrades | Transmission Owner / other responsible party |
| Affected-system study | Affected-system process |
| Project gen-tie / collection system | Sponsor / EPC, as applicable |
| Energization approval | Applicable utility / transmission party |
| Market registration / operation | Applicable ISO/RTO and market participants |
The names will vary by region.
The point is to stop calling all of them “the utility.”
If the party that owes the schedule is not the party subject to the EPC LDs, the sponsor owns that interface risk unless another contract transfers it.
Storage makes the operating envelope more important than the nameplate
Now add a 100 MW / 400 MWh battery behind Fox Run's POI.
Keep the maximum requested net export at 200 MW.
Order No. 2023 requires transmission providers to allow certain co-located generating facilities behind a single POI and to evaluate proposed additions to an existing request before automatically declaring them a material modification.
That does not mean the battery can run any dispatch pattern the financial model invents.
Suppose the revenue model assumes:
Maximum solar output 200 MW
Battery discharge 100 MW
POI export limit 200 MW
Export controller YES
Night-time grid charging 100 MW import
The export controller can keep net injection at 200 MW.
That answers one engineering question.
It does not prove the study or IA permits the assumed 100 MW of grid charging.
Order No. 2023 specifically requires storage interconnection studies to use operating assumptions that reflect proposed charging behavior.
So Fox Run needs an interconnection operating envelope:
Maximum export
Maximum import
Grid charging allowed?
Charging from co-located solar?
Simultaneous solar + charging?
Export-control requirements
Reactive-power requirements
Studied SOC / charging assumptions
The battery optimization model must live inside that envelope.
Otherwise it is optimizing revenue the project has no grid right to earn.
A co-located battery can preserve export MW and still change the study
The most useful hybrid question is not:
Does total nameplate exceed the POI?
It is:
Does the proposed addition change the interconnection service level or studied system impact?
Order No. 2023 created a process that can allow a generating facility to be added without automatically losing queue position where the original requested interconnection service level is not increased, subject to the material-modification analysis.
That is helpful for storage additions.
It is not automatic approval.
Fox Run should model at least two development paths:
Battery added within existing interconnection envelope
→ limited / no material restudy outcome
Battery addition changes studied operation
→ modification / restudy / upgrade risk
The revenue model should not assume the first outcome before the interconnection team confirms it.
Site control and deposits are not “soft development costs”
Order No. 2023 moved the federal pro forma process toward first-ready, first-served cluster studies.
Under the current pro forma framework, the project faces stronger site-control and financial-readiness requirements as it advances.
FERC's Order 2023-A explainer confirms the core site-control ladder:
90% site control at interconnection request
100% by execution of the facilities study agreement
subject to limited alternatives where regulatory restrictions prevent obtaining site control.
The process also uses study and commercial-readiness deposits, with later commitments tied more closely to identified upgrade exposure.
That changes the development cash-flow model.
Before Fox Run has a financeable operating asset, the sponsor can already have meaningful cash or financial security tied up in:
land / site control
study deposits
commercial-readiness deposits
affected-system work
LGIA deposits / security
upgrade funding
The Order 2023 queue article should carry the exact ladder.
This article needs only one conclusion:
queue progress consumes real sponsor liquidity before it produces an operating grid right.
“Energized” also needs a definition
Even energization is not necessarily one date.
Fox Run's schedule can contain:
Backfeed available
Initial energization
First synchronization
Commissioning energy
Full export testing
Commercial-operation approval
PPA COD
Debt conversion
A project can receive station power or backfeed before it can export commercially.
It can synchronize before every test is complete.
It can be electrically ready before the PPA recognizes COD.
So if a lender says:
Interconnection must be complete before conversion,
the financing documents need a defined evidence package, not a generic milestone name.
Put the interconnection ladder in the sources-and-uses model
For Fox Run, the financing page should show both uncertainty and committed amounts.
Early development
Interconnection allowance $20m
Study status cluster stage
Target grid-ready date Dec-2029
Current study case
TP interconnection work $12m
Network upgrades $38m
Affected-system work $7m
----
Total $57m
Incremental capex vs underwriting $37m
Schedule case
EPC mechanical completion Dec-2029
Grid-ready date Aug-2030
Delay 8 months
Illustrative average debt $180m
Illustrative rate 7%
Extra carry $8.4m
Current combined impact
Interconnection capex increase $37.0m
Additional interest 8.4m
------
Identified impact $45.4m
Then add, separately:
Lost / deferred revenue
PPA delay consequences
extension fees
tax timing
equity bridge
LC / security extension
The project team can debate the inputs.
It can no longer pretend interconnection is binary.
The diligence questions change with the milestone
At queue entry:
- What facility and MW are actually requested?
- What POI is being studied?
- What interconnection-service level is requested?
- What operating assumptions were submitted for storage or hybrid resources?
- What site-control and deposit requirements remain?
At study completion:
- What are the transmission-provider interconnection facilities?
- What are the network upgrades?
- Is there affected-system work?
- What costs are allocated to Fox Run?
- What cost can change on restudy?
- Which upgrades are on the critical path?
At IA execution:
- What MW and configuration does the IA actually cover?
- Who owns and builds each facility?
- What security remains outstanding?
- Which milestone dates are contractual?
- What assignment / pledge rights do lenders need?
- What work remains after execution?
Before energization:
- Are network upgrades physically complete?
- Is backfeed available?
- Are testing and protection requirements complete?
- What permission is needed for export?
- Does the permitted operating envelope match the revenue model?
Fox Run “has interconnection” only when the sentence is completed:
It has which right, at which stage, for which operating configuration, subject to which remaining work?
That is the status a finance team can underwrite.
Primary sources: FERC — Pro Forma LGIP · FERC — Pro Forma LGIA / Large Generator Interconnection Rules · FERC — Order No. 2023 Explainer · FERC — Order No. 2023-A Explainer · FERC — Order No. 2023 Fact Sheet