Offer review · New Power Solutions / ECP · received Jul 2026 · opening proposal · review v1.0 · 08 Jul 2026
Mansfield Energy Acres

# New Power Solutions (Energy Capital Partners)

Power Plan Proposal for Energy Acres Mansfield, Ohio · 900 MW BTM + 100 MW Grid

NPS proposes 900 MW of behind-the-meter gas generation at Mansfield under a 20 year PPA, first power Q4 2028. The design is sound and the speed is real. The price sits high against every benchmark, three terms are off-market, five material terms are undefined, and the structure asks MicroLink to backstop the equipment orders thirteen months before NPS reaches its own final investment decision.

42/100
weighted score · red-flagged
$116.65
all-in per MWh · prime power
$228M
peak pre-FID exposure incl LCs
Q4 2028
first power · 217 MW
01 · Offer summary

# The real ask arrives next month, not in 2028.

Counterparty
New Power Solutions LLC. Signing entity not confirmed in deck.
Sponsor / parent
Energy Capital Partners (~USD 87B AUM, exclusive BTM partner). Not guaranteed: nothing in the offer obligates ECP to stand behind NPS.
Offer scope
900 MW BTM reciprocating gas generation in three 300 MW blocks (82 Jenbachers Block 1; 24 Bergen B36:45V20 each Blocks 2 and 3), 107 MW of 2 hour BESS per block, plus 100 MW FirstEnergy grid power Q4 2028. First BTM power 217 MW Q4 2028, full 1 GW Q1 2030. Optional 100 MW mobile fleet bridge.
Headline price
USD 47.00/kW-month on 250 MW contract capacity, 20 year term. All-in prime power USD 116.65/MWh (capacity USD 67.77 + fuel pass-through USD 30.63 at USD 3.55/MMBtu + VOM USD 18.25). Gas lateral (~USD 30M) excluded, adds ~USD 2 to 3/MWh.
Term
20 years flat. No extension options, step-downs, or exit pricing stated.
Total contract value
~USD 2.7B capacity charges Block 1 alone over term; ~USD 8.5B at full 750 MW contract capacity. Before fuel.
Decision deadline
None stated. De facto: August 2026, when the CRA schedule puts the first USD 7M Jenbacher deposit.
What they actually want
MicroLink or a backstop entity funds ~USD 195M of pre-FID equipment commitments plus USD 33M of LCs (lateral USD 30M, Rover FT USD 3M), thirteen months before NPS reaches its own FID (est. Aug 2027).
BATNA
FirstEnergy grid-only path (100 MW Q4 2028 claimed, unverified; bulk transmission timeline years beyond); no competing BTM proposal currently at term sheet stage for Mansfield; mobile/bridge generation as interim. Field requires Nick's confirmation of current counterparty pipeline before gate finalises.
Status
Opening proposal. Pricing and structure read as an opening position inside a negotiable band.
02 · Deal anatomy

# Conventional structure. The risk, the cash, and the exits are where it turns.

2.1 · Scope and technical

Design is credible: 34.5 kV distribution to dodge HV transformer lead times, cross-tied blocks, N+4 on the Bergens, 8,641 BTU/kWh HHV blended Block 1 and 7,731 on the Bergens, 3 to 4 nines at plant and 5 at rack. Single-line, load flow, short-circuit, and RAM studies offered for Block 1: request immediately regardless of negotiation path. Permitting strategy (straight to PSD for the full 900 MW, wide emissions envelope, amend downward) is the right playbook; the 12 month PSD plus OPSB timeline is aggressive. Ohio precedent exists at smaller scale: PowerConneX 120 MW and 216 MW OPSB-approved, Meta/Williams Socrates in construction. No heat recovery interface in the design (tracked separately).

2.2 · Price mechanics

Component Basis Number Character
Capacity charge
USD/kW-month on 250 MW contract capacity
47.00, ~USD 11.3M/month
Unconditional: economically 100% take-or-pay
Fuel + FT
Pass-through at cost
USD 3.55/MMBtu plan, ~USD 30.63/MWh
Commodity risk ours, 20 years
VOM
Pass-through on metered delivery
USD 18.25/MWh
At cost
Lateral
Excluded from headline
~USD 30M, per Dth or into capex
Adds ~USD 2 to 3/MWh, treatment undefined
Indexation
PPA priced to final capitalized cost (USD 774M reference)
Deadbands and collars mentioned
No band widths, no cap stated

2.3 · Risk allocation

##### Risks we carry

- Fuel and commodity, full pass-through, 20 years (market-normal)
- Demand and load ramp, via unconditional capacity charge from COD (not market-normal)
- Equipment residual, USD 195M of gensets under the CRA if the project dies (not market-normal at this size, unsecured)
- Construction overrun, shared via indexation with undefined bands (conditional)
- Counterparty performance, no sponsor guarantee, no remedies stated

##### Risks they carry

- Permitting, PSD/OPSB strategy plus mobile fleet mitigant (credible)
- Operations and maintenance, post-COD
- Schedule, nominally, but no COD liquidated damages stated, so in practice unremedied
- Post-FID capital, all costs after FID borne by NPS

2.4 · Commitment profile

Item Amount Timing Recovery
CRA equipment (Jenbacher A + B, Bergen 1, packaging)
~USD 195M
First USD 7M Aug 2026, ramping through Jul 2027
NPS reimburses at FID (Aug 2027, partly within their control); else relocate / NPS retains / liquidate to us
Lateral LC
USD 30M face
NTP six months pre-FID
Cancellation cost USD 2M at signing to USD 39M at month 18
Rover FT LC
~USD 3M
At Open Season, three months demand charges
Standard pipeline credit
Debt-equivalence
20yr × ~USD 141M/yr capacity obligation Block 1
From COD
Imputed debt under S&P methodology; visible to Mansfield lenders and the USD 40M round

2.5 · Exit and downside

Termination rights, buyout options, and remedy structures are all absent from the deck. The equipment fallback waterfall is weak: relocation binds us to NPS as power provider at another site, NPS retention is at their option, and liquidation lands on us in a thin, opaquely priced secondary market for new-model 60 Hz units (used inventory is largely older 50 Hz European CHP stock). One signal each way: Crusoe's ~750 MW Bergen order and VoltaGrid's 2.3 GW Jenbacher order mean motivated buyers exist today for stranded slots; Oracle reportedly reselling turbine slots is the early sign of slack. Recovery at par cannot be assumed in 2028.

03 · Scoring matrix · anchors applied, evidence in Section 04

# 42 out of 100, and the number is not the point: two automatic red flags block the gate.

Red flag status: BLOCKED. Pre-FID Exposure scores 1 and Flexibility scores 1. Under the red flag rule this offer cannot pass the gate without the flagged terms renegotiated or explicitly accepted in writing at founder level.

Criterion Weight Score Weighted Justification
Price vs market
20
2
8
High-market on all three priced anchors: capacity charge, all-in USD/MWh, capex per kW
Risk allocation
20
2
8
Demand, residual, and credit risk all ours; fuel pass-through is the only market-normal allocation
Counterparty credibility
15
2
6
No delivered BTM data center project; principals offshore-wind-weighted; sponsor named, not obligated (anchor caps at 2)
Schedule confidence
10
3
6
Ohio precedent at smaller scale, mobile fleet is real insurance, permitting timeline aggressive, FirstEnergy 100 MW unverified
Flexibility
10
1
2
Flat 250 MW from COD, 20 years, no ramp matching, no priced exit · red flag
Pre-FID exposure
10
1
2
USD 195M plus USD 33M LCs, unsecured, reimbursement trigger partly within their control, weak recovery · red flag
Strategic fit
10
4
8
Only credible Q4 2028 power path; BTM sidesteps PUCO tariff jurisdiction; 345 kV pathway creates real optionality
Contract completeness
5
2
2
Revenue share, indexation bands, remedies, signing entity all referenced but undefined
Total
100
42 / 100
Red-flagged: gate blocked
04 · Benchmark evidence · deep research run 08 Jul 2026 · stale after Oct 2026

# Every priced term against the evidenced range. Two-source rule satisfied on all scored terms.

Term Their number Market range and sources Src Verdict
Capacity charge
USD 47.00/kW-mo, 20yr
Mid-USD 40s justifiable at current equipment inflation (GE Vernova earnings guidance; Melius via CNBC; SemiAnalysis capex). PJM 26/27 capacity cleared ~USD 10/kW-mo as a floor reference only
3
High-market
All-in prime power
USD 116.65/MWh
Recip LCOE 80 to 100 (Thunder Said Energy); Bloom PPA ~99; new CCGT 45 to 100 (BCG/Lazard). Premium is speed and firmness, named and real, but unsized by them
3
High-market
Installed capex
~USD 2,580/kW incl 107 MW BESS
Recips 1,700 to 2,000/kW all-in (SemiAnalysis mid-2025); BESS explains part of gap. Implied ~22% gross capacity yield, low-to-mid teens levered IRR to them
2
High-market
Fuel pass-through
At cost, USD 3.55/MMBtu plan
Offtaker bears commodity under pass-through as standard; IPP hedging rare across the comparable set
2
At market
Reserve billing
Pay 250 of 300 MW installed
Comparable structures bill firm delivered capacity or share reserve value; we fund the asset, they keep the optionality
1
Off-market
Term structure
20 years flat
Offtaker trend 10 to 12yr initial plus extensions; S&P imputes risk-factored NPV of capacity payments as debt; Moody's implicit-debt treatment of DC commitments
2
Off-market
Minimum take vs ramp
Unconditional from COD
AEP Ohio DC tariff (PUCO, Jul 2025): 85% minimum, 4yr ramp, 12yr horizon. This offer is harder than the regulated benchmark on both axes
2
Off-market
CRA backstop
We fund ~USD 195M pre-FID
OEM deposits 20 to 25% nonrefundable are real; offtaker backstops occur but bespoke, no standardized instrument; secondary market for new-model 60 Hz units thin and opaque
2
Off-market
Grid revenue share
"Sharing market-related income"
Market norm is a locked percentage; no number benchmarkable because none is offered
1
Undefined
Mobile fleet bridge
USD 8.3M mobilization + 6.8M/mo per 100 MW
~USD 68/kW-mo before fuel, ~45% above permanent plant. Priced as insurance, not as a plan
1
High-market

Source caveat: nearly all BTM data center pricing is private. Ranges are triangulated from OEM disclosures, earnings calls, LCOE studies, PUCO filings, and analyst notes, not disclosed contract terms. Treat as indicative bands, dated 08 Jul 2026.

05 · Red flags and undefined terms

# Three flags, five questions. The questions go back with the response.

5.1 · Red flags

Term Why it is dangerous What clears it
CRA residual risk
USD 195M of new-model 60 Hz gensets in a thin, opaquely priced secondary market; unsecured position; reimbursement trigger (their FID) partly within their control; roughly five times the company round
Cap the exposure; first-priority security over slots and equipment; reimbursement at FID with interest; defined liquidation waterfall; or ECP warehouses the equipment risk
Unconditional capacity charge
"No minimum purchase" plus an unconditional USD 11.3M/month charge is a 100% take-or-pay for 20 years, harder than the AEP Ohio 85%/12yr regulated benchmark, against uncertain tenant ramp
Contract capacity phased to contracted tenant load with a defined ramp schedule
Uncapped indexation
PPA priced to final capitalized cost with deadbands and collars mentioned but no widths and no cap: converts a fixed price into cost-plus in disguise, in a market inflating 10 to 20 points per quarter
Tight deadband, hard cap on total capex pass-through, open-book EPC/OEM pricing, most-favoured pricing

5.2 · Undefined terms · send as questions

Referenced term What is missing Question to send back
Grid transition share
No percentage
What locked percentage of merchant, capacity market, and ancillary revenue flows to the offtaker once grid-connected, and how do capacity charges step down?
Indexation mechanics
No band widths, no cap
What deadband and collar apply to pricing indexed to final capitalized cost, and is there a hard cap with open-book substantiation?
Remedies
Entirely absent
What are the COD liquidated damages, the guaranteed availability level, the capacity payment abatement schedule, and outage step-in rights?
Signing entity and guarantee
Entity unconfirmed, ECP not obligated
Which legal entity signs the PPA and CRA, and will Energy Capital Partners guarantee its obligations?
Lateral treatment
Recovery route unpriced
Is the ~USD 30M lateral recovered per Dth or added to indexed capex, and what does each route add to the all-in USD/MWh?
06 · Negotiation map

# Their ask is an opening position inside a negotiable band, about 6% wide on price alone.

#### Tier 1 · Must moveWe do not sign as offered

CRA protection packageTheirs: we fund USD 195M unsecured, reimbursed at their FID. Target: capped, secured against slots/equipment, interest on reimbursement, defined waterfall, or ECP warehouses. Walk-away: no unsecured backstop above the founder threshold.
Contract capacity rampTheirs: flat 250 MW from COD. Target: phased to contracted tenant load. Walk-away: no 100% take-or-pay from day one.
Indexation capTheirs: bands mentioned, undefined. Target: tight deadband, hard cap, open book, MFN. Walk-away: no uncapped indexation.

#### Tier 2 · Should moveMeaningful value, winnable

Capacity chargeTarget ≤ USD 44/kW-month against open-book capitalized cost, or equivalent value via structure.
TermTarget 10 to 12 year initial with extensions, or a grid-arrival step-down/conversion.
Reserve billingPay firm delivered capacity only, or share the 50 MW reserve's merchant and expansion value.
Grid revenue shareA locked percentage in the PPA, not language.
RemediesCOD LDs, availability guarantee with abatement, step-in. Non-optional but expected to be conceded.

#### Tier 3 · Trade candidatesPriced before offered

Longer termTrade for a lower capacity charge; they price term length directly, so this is their favourite currency.
Bounded Mansfield exclusivityTrade for the CRA risk shift; scope, geography, and time limited.
Committed Block 2/3 expansion rightsTrade for ramp phasing; gives them volume certainty against our timing flexibility.
07 · Gate decision

# Request a revised offer. The counter-argument is real and it is about time, not terms.

Best argument against this recommendation: this is the only credible Q4 2028 power path at Mansfield. Genset slots are perishable, the CRA schedule is what holds the Q4 2028 date, and every quarter of delay costs more in tenant momentum and raise narrative than these terms cost in dollars. If the revised-offer round takes six months, the timeline the offer is selling may no longer exist.

Gate outcome

#### Proceed to term sheet

Blocked: two red flags outstanding.

#### Proceed with conditions

Not selected: conditions would replicate the Tier 1 list without leverage.

#### Request revised offer

Selected. Attach the 5.2 question list and the Tier 1 positions. Signal seriousness on timeline to protect the counter-argument.

#### Decline

Not selected: strategic fit is real and the band is negotiable.

Actions

Action Owner Date due
Send response: 5.2 questions + Tier 1 positions + timeline signal
Nick
Within 7 days (protects Aug 2026 slot economics)
Request Block 1 single-line, load flow, short-circuit, RAM studies
Shane
With the response
Verify FirstEnergy 100 MW Q4 2028 status (signed agreement? load study?)
Nick / Shane
Before revised offer lands
Confirm BATNA field: current competing power counterparty pipeline for Mansfield
Nick
Before gate re-run
Financing counsel view on CRA + 20yr obligation debt-equivalence vs the raise
Deniz
Before any term sheet

Sign-off

Full founder review required. Exposure (USD 195M + USD 33M LCs) exceeds threshold X and term (20 years) exceeds threshold Y on any plausible setting of both. Thresholds remain [X = 5, Y = 10 suggested] pending confirmation.

08 · Standard graphics · drawn from this review's data

# The five standard visuals, with this offer's numbers.

The Exposure Curve · cash at risk under the CRA
Cumulative committed dollars from the first Jenbacher deposit in August 2026 to the USD 228M peak in July 2027, one month before the FID reimbursement they control. This is the graphic the deck's slide 15 was designed not to be.
The Heat Map · risk allocation
Four of five high-impact risks are red. Both watch-zone risks are ours: exactly the Tier 1 list.
The Scorecard · this offer alone
Add a paired bar per criterion when a competing offer arrives; same anchors, same chart.
The Bands · price vs benchmark
Two dots outside or on the edge of the band, one at the top, one comfortably inside. The gap is the negotiation.
The Comparison · vs the regulated benchmark
The single most usable negotiation exhibit in the review: their private ask against Ohio's own public standard.