ERCOT vs PJM: The Same 200 MW Solar Project Has Two Different Revenue Stacks
Take the same 200 MW solar project and place one copy in PJM and one in ERCOT.
For teaching purposes, give both projects exactly the same energy assumptions:
Nameplate capacity 200 MW
Annual generation 438,000 MWh
Illustrative merchant energy price $40/MWh
-------
Energy revenue $17.52m
That is deliberately unrealistic as a market comparison.
ERCOT and PJM do not have the same nodal prices, basis, shape or curtailment.
Holding energy revenue constant isolates the market-design difference.
Now add reliability revenue.
For the PJM copy, assume an illustrative capacity accreditation of 8%.
For the ERCOT copy, there is no PJM-style forward capacity-market payment.
Immediately the stacks diverge.
PJM adds a separate capacity product
PJM's Reliability Pricing Model procures capacity for future delivery years through Base Residual Auctions and related incremental auctions.
Resources clear in UCAP terms — accredited capacity, not nameplate MW.
For our teaching project:
Nameplate 200 MW
Illustrative accreditation 8%
-----
Accredited capacity / UCAP 16 MW
PJM's 2028/2029 Base Residual Auction cleared at the FERC-approved cap of $325/MW-day.
Using that current clearing price:
16 MW
× $325/MW-day
× 365
=
$1.898m annual capacity revenue
So the simplified PJM stack becomes:
Energy revenue $17.520m
Capacity revenue $1.898m
--------
Total $19.418m
Capacity is roughly 9.8% of that simplified total.
The revenue exists because two things are both true:
- the project receives accredited MW; and
- those MW clear the capacity auction at a price.
The model needs two inputs.
Never combine them into one assumed $/MW-nameplate line.
The current PJM price is a collar outcome, not a free-floating market price
The 2028/2029 auction procured 138,318 MW of UCAP and cleared at $325/MW-day.
That number was the approved ceiling.
PJM and FERC extended a price collar for the 2028/2029 and 2029/2030 auctions with an approximate:
Floor $175/MW-day
Cap $325/MW-day
So today's $325 is a real settlement price.
It is also the endpoint of an administrative collar.
Those are not contradictory statements.
For modeling, the distinction matters because you should not infer a normal statistical relationship such as:
latest auction = $325
therefore
long-run capacity price = $325
The current construct physically prevents the auction from clearing above the cap.
And the 2029/2030 auction has not yet produced a clearing price as of October 5, 2026.
A sponsor can use the current cleared delivery year.
A fifteen-year debt model still needs a view beyond it.
Price is only half the PJM capacity sensitivity
Keep the $325 price but change the illustrative accreditation.
| Accreditation | Accredited MW | Capacity revenue at $325/MW-day |
|---|---|---|
| 4% | 8 MW | $0.949m |
| 8% | 16 MW | $1.898m |
| 12% | 24 MW | $2.847m |
Now hold accreditation at 8% and move the price within the current collar:
| Capacity price | Annual capacity revenue |
|---|---|
| $175/MW-day | $1.022m |
| $250/MW-day | $1.460m |
| $325/MW-day | $1.898m |
And put both variables together:
| Illustrative accreditation | $175 | $250 | $325 |
|---|---|---|---|
| 4% | $0.511m | $0.730m | $0.949m |
| 8% | $1.022m | $1.460m | $1.898m |
| 12% | $1.533m | $2.190m | $2.847m |
That table is a better financing sensitivity than a capacity-price curve by itself.
The next article, Capacity Accreditation and ELCC, is about the vertical axis.
ERCOT does not currently have the PJM revenue line
ERCOT has repeatedly considered changes to its reliability framework.
The proposed Performance Credit Mechanism would have created a new reliability-related payment architecture.
The PUCT tabled the PCM in December 2024, concluding that the then-current design did not provide sufficient reliability benefit to justify moving forward and directing attention toward other market reforms.
As of October 2026, ERCOT still does not have a PJM-style forward capacity auction paying a separate $/MW-day amount for accredited installed capacity.
For our simplified ERCOT solar project:
Energy revenue $17.520m
PJM-style capacity revenue $0.000m
--------
Subtotal $17.520m
But stop there and the comparison becomes wrong in a different direction.
ERCOT's stack is not “energy only” in the literal sense.
It includes Ancillary Services and scarcity-related pricing mechanisms.
For a qualified flexible resource, those can be material.
Our solar example sets AS revenue to zero only to isolate the capacity-market distinction.
It is not a statement that every ERCOT project has zero AS opportunity.
RTC+B changed the ERCOT revenue architecture in December 2025
On December 5, 2025, ERCOT implemented Real-Time Co-optimization Plus Batteries.
ERCOT describes it as the most substantial enhancement to its Real-Time Nodal market design since 2010.
The practical change is important for project models:
energy and Ancillary Services are now cleared together in real time.
For batteries, RTC+B also introduced improved state-of-charge modeling and a single-model framework designed for energy-storage participation.
That means an ERCOT battery model built on pre-December-2025 operating history is not merely using old prices.
It is using prices generated by an older dispatch architecture.
You cannot reliably update that model by applying:
2024 ancillary service revenue
× haircut
=
2026 forecast
The optimization itself changed.
For storage, the dispatch engine now values the opportunity cost between energy and ancillary-service provision in real time.
That is a structural change, not a price assumption.
The $2,000 real-time number is an offer cap, not a simple all-in price ceiling
Another correction matters.
ERCOT's RTC+B framework distinguishes the Day-Ahead System-Wide Offer Cap and the Real-Time System-Wide Offer Cap.
Current ERCOT materials show:
Day-ahead HCAP / DASWCAP $5,000
Real-time HCAP / RTSWCAP $2,000
It is tempting to write:
Real-time ERCOT prices are capped at $2,000/MWh.
That is too simple.
The $2,000 parameter is a system-wide offer cap.
Real-time market pricing can also reflect scarcity-demand-curve and power-balance / constraint mechanics under the protocols.
So a merchant model should not mechanically truncate every real-time settlement-price scenario at $2,000.
Use the actual ERCOT pricing logic.
The financing lesson is broader:
an offer cap is an input to market formation, not automatically the final settlement-price formula.
PJM reliability value and ERCOT reliability value live in different places
For our PJM solar project, reliability value is visible as a separate line:
Accredited MW
× capacity clearing price
=
capacity revenue
For ERCOT, reliability value can appear through:
- energy scarcity;
- Ancillary Service prices;
- reserve / scarcity demand curves;
- specific reliability products and services; and
- contracts that monetize those market revenues.
There is no single ERCOT line that is economically equivalent to PJM capacity.
That is why this comparison is wrong:
PJM capacity revenue $1.898m
ERCOT capacity revenue $0
→ PJM is worth $1.898m more
The $1.898 million difference in our table isolates one market-design feature.
It does not value the two projects.
A real investment comparison needs the full nodal revenue stack in each market.
The financing question is where the revenue can be contracted
Both markets can support long-term PPAs.
So it is also wrong to say:
ERCOT is merchant and PJM is contracted.
Market design and commercial contracting are different layers.
A 200 MW ERCOT solar project can sign a long-term PPA and remove much of its energy-price risk while remaining in a market with no forward capacity payment.
A PJM project can also contract its energy while retaining capacity-market exposure.
For a lender, the stack is therefore better organized as:
Contracted energy
Uncontracted energy / basis
Capacity
Ancillary services
Other merchant revenue
not:
PJM revenue
ERCOT revenue
The lender discounts each line according to the contract and market rule behind it.
A $1.898 million capacity line can look like $13.7 million of debt — if you pretend it lasts 15 years
This is where forecast horizon becomes a financing issue.
Our illustrative PJM capacity revenue is:
$1.898m per year
If a lender were willing to treat that exact cash flow as certain for all 15 years of a loan, and the debt were sculpted to a 1.35x DSCR:
Incremental debt service capacity
=
$1.898m / 1.35
=
$1.406m per year
At an illustrative 6% debt rate over 15 years, the present value of that level debt-service stream is approximately:
$13.7m of incremental debt
That is not a lender quote.
It is a sensitivity showing what happens if you capitalize a one-year market observation across a fifteen-year financing.
The actual cleared capacity price is known only for the delivery years that have cleared.
Accreditation can change.
The market construct can change.
So the difference between:
Capacity revenue included for 15 years
and:
Capacity revenue included only where sufficiently supported
can be tens of millions of debt even though the annual capacity line is less than $2 million.
That is why capacity bankability deserves its own assumption.
Do not model the current PJM collar as one price
A clean model should separate three things.
Cleared price
For the 2028/2029 delivery year:
$325/MW-day
That is known.
Current rule range
For the current collar:
Floor approximately $175/MW-day
Cap approximately $325/MW-day
That is a rule.
Long-term forecast
Future capacity price
=
model assumption
That is neither the cleared price nor the collar.
Keep all three.
If the model uses $325 in every year, label that as a deliberate forecast assumption.
Do not let the historical clearing-price row quietly become the forward curve.
Do not backcast ERCOT RTC+B with the old market and call it history
For ERCOT, the same discipline applies differently.
The 2026 market is running under RTC+B.
Historical energy and ancillary-service revenues before December 5, 2025 were generated under the prior real-time design.
So a storage model needs to identify:
Pre-RTC+B observed history
versus
Post-RTC+B observed history
versus
backcast / simulated current-rule history
Those datasets are not interchangeable.
A battery's pre-RTC+B AS award pattern, energy dispatch and state-of-charge opportunity cost may not represent the co-optimized system.
This does not make historical data useless.
It makes the rule regime another dimension in the dataset.
The two project models should not have the same revenue rows
For our simplified solar example:
PJM
Energy / PPA
+ capacity revenue
+ eligible ancillary services
+ environmental / other contracted value
= gross revenue
ERCOT
Energy / PPA
+ eligible ancillary services
+ other market / contracted value
= gross revenue
There is no PJM-style capacity line to copy across.
For a battery the difference becomes even more pronounced because RTC+B directly changes the energy / AS optimization.
The correct model architecture follows the market architecture.
A simple project-finance comparison
Keep the same illustrative $17.52 million energy revenue and $3 million opex.
ERCOT — ignoring AS solely for this structural example
Energy revenue $17.520m
Opex (3.000m)
--------
CFADS $14.520m
PJM — add the illustrative current capacity line
Energy revenue $17.520m
Capacity revenue $1.898m
Opex (3.000m)
--------
CFADS $16.418m
At 1.35x DSCR:
ERCOT annual debt-service capacity
= $14.520m / 1.35
= $10.756m
PJM annual debt-service capacity
= $16.418m / 1.35
= $12.162m
Difference:
$1.406m per year
Again, this is not saying PJM supports more debt.
It says the PJM capacity line contributes $1.406 million of annual debt-service capacity if the lender credits that revenue.
The bankability assumption is what converts revenue into debt.
What can actually go wrong in each market
The most useful comparison is not which market is “safer.”
It is what variable can remove revenue.
PJM capacity line
Capacity price falls
Accreditation falls
Resource does not clear
Performance obligation / penalty applies
Capacity construct changes
ERCOT merchant / AS line
Energy price distribution changes
AS prices change
RTC+B optimization changes dispatch economics
Offer / scarcity parameters change
Resource qualification changes
Nodal congestion changes
Both markets contain rule risk.
The rule risk just sits in different lines.
What I would put in the investment committee table
| Question | PJM | ERCOT |
|---|---|---|
| Separate forward capacity market? | Yes — RPM | No PJM-style capacity market |
| Current forward reliability payment | Capacity $/MW-day on UCAP | No equivalent single capacity line |
| Capacity accreditation relevant? | Directly | Not as PJM UCAP revenue |
| Real-time energy + AS co-optimization | Market-specific PJM design | RTC+B since Dec. 5, 2025 |
| Battery state-of-charge model central to RT dispatch | Yes, per PJM rules for storage | Explicit RTC+B single-model framework |
| Long-term PPA possible? | Yes | Yes |
| Major modeling risk | Capacity price + accreditation + rule horizon | Nodal energy + AS + RTC+B rule regime |
The table does not tell you which market wins.
It tells you which workbook tabs need to be different.
The diligence questions are market-specific
For a PJM project:
- Which delivery years have actually cleared?
- What is the applicable capacity-zone price?
- What accredited UCAP is the project assuming?
- Is that accreditation current or forecast?
- What performance obligations and penalties attach?
- What capacity price is assumed beyond cleared years?
- Is the current collar being confused with a long-term forecast?
- How much debt disappears if post-cleared-year capacity revenue is excluded?
For an ERCOT project:
- Is the merchant model built on post-RTC+B rules?
- Which historical periods predate the Dec. 5, 2025 redesign?
- How are energy and AS co-optimized in the forecast?
- What resource qualifications support each AS revenue line?
- Which current offer / scarcity parameters are driving the tail?
- Is the project using a PPA, toll, hedge or merchant exposure?
- What nodal basis remains after the contract?
- For storage, how are state of charge, degradation and interconnection constraints represented?
The questions are different because the market products are different.
The conclusion is not energy-only versus capacity
That phrase is still useful shorthand.
It is no longer enough to build a project model.
PJM has a distinct forward capacity construct that currently has a FERC-approved collar and a 2028/2029 price at the $325/MW-day ceiling.
ERCOT has no PJM-style capacity auction, and the proposed PCM was tabled. But ERCOT is not a one-line energy market: RTC+B now co-optimizes energy and Ancillary Services in real time and changed the operating economics of flexible resources.
For financing, the distinction is not philosophical.
It is spreadsheet architecture.
In PJM, the model needs a capacity tab with separate price and accreditation assumptions.
In ERCOT, a battery model needs current-rule energy / AS co-optimization rather than a capacity line copied from another market.
The same 200 MW solar plant can have the same generation and the same assumed energy price and still produce a different bankable revenue stack because the market pays reliability through different mechanisms.
Primary sources: PJM — 2028/2029 Base Residual Auction Results · PJM — FERC-Approved Capacity Price Collar · PJM — Capacity Market / RPM · ERCOT — RTC+B Go-Live · ERCOT — Current Nodal Protocols · PUCT — December 2024 PCM Memorandum