Phase 1 of NapaSan's Climate Mitigation Plan routed the 30% federal credit, the depreciation, and the operating margin off-site for 14 years — through 2037. Phase 2 — customer-owned — keeps all of it on NapaSan's side. PG&E industrial rates are up 35–45% cumulative since 2023, and the §48E credit cliff hits 12/31/33 — two federal-and-market clocks that set the construction-start window. Your ~$13.8M Electrical Improvement Project is already in design phase: not a cost to carry, but a convenient moment to coordinate a tie-in while crews are already in the switchgear. The case here is customer ownership, §6417 cash to the general fund, and 20-year cost certainty, not a PG&E bill-savings play.
All numbers are preliminary projections built on public data + industry midpoints. Specific OEM and EPC partners, peer-customer references, and firm vendor pricing are not disclosed on this page — they sit behind a mutual NDA + non-circumvention at Phase 2 entry. Every dollar figure, MW size, $/kWh rate, GHG ton, and timeline date is subject to material revision based on (a) the free Phase-1 14-day memo using NapaSan-confirmed data, (b) firm vendor quotes received in Phase 2 bake-off, (c) site walk findings, (d) CPRA-confirmed utility data, (e) BAAQMD + PG&E Rule 21(M) interconnect study outcomes, and (f) NapaSan Board procurement decisions. This page is not an offer.
NapaSan's own capital planning carries an indicative ~$13.8M Electrical Improvement Project — replacing motor control centers installed in the 1970s–1990s and adding a looped power-distribution architecture — already in the design phase. With switchgear capacity already adequate, the value isn't avoiding a cost; it's coordinating a lower-friction tie-in while crews are already in the gear.
This is not BCal's roadmap. It's NapaSan's own capital plan, in the design phase right now. NapaSan has confirmed the sub-switchgear already carries adequate capacity, and any upgrade would be needed for any project — so we do not treat it as a project cost. Designing a customer-owned fuel-cell tie-in onto the new looped distribution while it is being engineered is simply lower-friction and better-coordinated than retrofitting later. The real construction-start drivers are the §48E credit cliff before the 2034 step-down and locking in customer ownership. BCal's free 14-day memo is a zero-spend first step — a technology-neutral read of where firm on-site generation fits your plan.
Three phases. Two decades. One construction-start deadline. Each milestone below is a contractual checkpoint, not a marketing slide.
230 kW third-party linear generator on your digester gas. 14-yr PPA through 2037. The third-party developer captures the 30% ITC + depreciation + operating margin. Recip cogen just absorbed $620K rebuild.
2-hour site walk. CPRA-confirmed utility + biogas data hand-off. Free 14-day Phase-1 memo (no NDA, no procurement action) lands.
LOI within 5 business days of site walk. NapaSan Board approval. Mutual NDA + non-circumvention signed. EPC + OEM bake-off begins.
CEQA, BAAQMD Reg 9-9, PG&E Rule 21/21M, biogas cleanup skid integration. Tie-in coordinated with the Electrical Improvement Project looped-distribution work while it is open.
A customer-owned fuel-cell block, sized to your biogas in the assessment, firming the overnight PG&E import. Bill-credit and demand-charge options across NapaSan meters, confirmed (not assumed) in the assessment.
Aligns with NapaSan recycled-water expansion + Climate Mitigation Plan. Inside the §48E full-credit window. Modular — only if demand math supports.
Per OBBBA July 2025: construction-start by this date locks in 30% §48E ITC + 30% §6417 Direct Pay. 2034 = 75%. 2035 = 50%. 2036 = zero.
The rebuilt 415 kW recip is hedged and eventually succeeded as the fuel cell takes baseload — running fewer hours each year rather than being retired. Less runtime means progressively lower NOx and Scope 1, and an easing BAAQMD compliance load.
14-yr third-party PPA terminates. Option to consolidate the 230 kW onto the customer-owned platform. Operating margin and any portfolio bill-credit options fully on NapaSan's side.
100% digester gas + directed-biogas / RNG. Climate Mitigation Plan complete. Portfolio bill-credit options extended across NapaSan-owned PG&E accounts, as confirmed in the assessment.
We can't read which one is keeping you up at night — but each below is independently documented in NapaSan's own records. The case for moving inside the §48E window doesn't depend on which one matters most.
The 230 kW third-party-owned unit on your digester gas is locked in through 2037. The third-party developer keeps the 30% ITC, the depreciation, and the spread vs PG&E retail. Customer-owned flips this. §6417 Direct Pay is the unlock for special districts.
Public PR · Jun 2023 · Napa Valley Register~$13.8M electrical rebuild in design now. NapaSan confirms the sub-switchgear already has adequate capacity, so this is not a cost to factor into the project. Coordinating the BTM tie-in while the looped distribution is being engineered is simply lower-friction than retrofitting later — convenience, not necessity.
NapaSan FY26/27 budget · capital planning (indicative)Board RES 25-001: $700K emergency mid-year amendment for chemicals + electricity (May 2025). PG&E industrial rates +35–45% cumulative since 2023. The 415 kW recip just absorbed a $620K band-aid rebuild — major-service interval clock ticking.
April 23, 2024 Board Packet (CIP #217) · RES 25-001 (May 7, 2025)The existing 230 kW third-party deal was Phase 1 of the Climate Mitigation Plan. NapaSan's FY26/27 budget shows electricity costs actually declined year-over-year — chemicals and insurance drove the increases — so this is not a bill-savings story. It's cost certainty, added on-site capacity, and de-risking the electrical rebuild. Plus MCE Deep Green tier signals premium-for-green appetite.
CWEA · MCE · NVR rate coverageThe honest framing: we don't know which of these tipped you into the call — and we don't need to. Phase 1 memo (free, 14 days, no NDA) re-runs the math against your actual rate class, gas-flow records, and the Electrical Improvement Project design package. Whichever pressure matters most to you, the numbers point to the same construction-start window.
Cash to the general fund. Risk off NapaSan's balance sheet. Strategic optionality on fuel, policy, and the routing of bill credits across every meter you own.
NapaSan is a political subdivision of California, eligible for §6417 Direct Pay under Treasury final regulations (March 2024). 30% of qualified project basis returns as cash to the general fund within 12–18 months of COD — the dollar figure sized against the confirmed capital number in the free memo. No tax-equity partner. No structuring drag.
This is general-fund cash, not a utility-bill saving. The §6417 rebate is one-time capital returned to NapaSan's general fund — freeing budget that would otherwise be raised or borrowed, independent of the electricity line item.
Anchor EPC + 2–3 California EPCs bid every scope. NERC CIP-013-3 + IEC 62443 cyber designed in (founder background: 20+ yrs hardware security in semiconductors). BAAQMD + CEQA + Rule 21(M) all carried by BCal. Owner's-rep model — NapaSan contracts directly with OEM and EPC.
What the 20-yr LTSA stands behind: contracted availability, guaranteed heat rate, NOx performance, and scheduled stack replacement to hold electrical efficiency across the term. BCal makes no output or savings guarantee — these are the OEM's own service commitments, the constructive answer to a request for production assurance.
Bill-credit and demand-charge options across NapaSan's PG&E meters — lift stations, pump stations, admin, recycled-water sites — confirmed (not assumed) in the assessment, including any RES-BCT eligibility once tested against this behind-the-meter configuration. A customer-owned structure preserves these options in a way an ESA generally cannot. RNG-flex roadmap from digester biogas to directed-biogas to RNG-blend.
Resilience is already addressed on-site (Mainspring + the planned microgrid), so backup power is not the pitch here — the strategic value is ownership, cost certainty, and credit optionality across the portfolio.
We don't manufacture cells, build EPCs, or operate plants. We assemble the multi-vendor, multi-credit, multi-regulatory transaction — and stand behind it. Owner's-rep model: you contract directly with proven counterparties.
Direct Pay for political subdivisions is procedurally distinct from corporate ITC monetization. We've structured the eligibility memo + IRS filing pathway with bond counsel review. No tax-equity partner needed.
A public proof point on the platform: a carbonate fuel cell has run on wastewater digester gas at the City of San Bernardino municipal water department — an industry reference for the same fuel and technology (not a BCal-built project). Deeper peer references at the 1.2–2.8 MW scale, OEM identities, and operational data are shared under executed mutual NDA.
Four chemistry families (SOFC · PAFC · microturbine · MCFC carbonate) evaluated per your gas flow + size. Anchor EPC + 2–3 California EPCs bid every scope. OEM and EPC identities disclosed under mutual NDA at Phase 2 entry.
We model bill-credit and demand-charge options across multi-meter public-agency portfolios, including whether RES-BCT (AB 512, public-agency program) is even available to a behind-the-meter single-customer configuration like this one. The Phase 1 memo confirms what applies to NapaSan's accounts rather than assuming eligibility.
NapaSan confirmed strong on-site heat demand — a ~1.3 million-gallon digester held near 99°F via heat exchangers — and a stated preference for using waste heat over firing a boiler. The fuel cell's recovered heat is a confirmed match for that duty, displacing boiler fuel rather than being a hypothetical CHP benefit.
The plant is built from multiple independently-operating cells, so a single module out for service does not take the site down — N+1-style redundancy rather than one large machine. Availability is contractually backed by the LTSA, with planned-maintenance windows scheduled around plant operations.
NERC CIP-013-3 + IEC 62443 designed in, not bolted on. EPA / CISA / WaterISAC pressure on wastewater controls is rising — won't be optional in 2027. Founder background: 20+ years hardware security in semiconductors.
OEM manufactures cells. EPC builds. LTSA operates. BCal orchestrates the multi-vendor, multi-credit, multi-regulatory transaction. Open-book on every line item — no markup hidden in EPC pricing. Milestone-paid developer fee.
Your 65% self-gen headline is an annual average. The night is where the PG&E line item lives. Phase 1 closes the night.
Plant load ~1.53 MW average across ~13 GWh/yr. Recip + 3rd-party PPA unit + solar cover ~65% on annual average; remaining ~35% from MCE Deep Green + PG&E import — concentrated overnight when solar is dark.
The capital number follows directly from the sizing — and the sizing follows from your 12 months of interval data and your available biogas, both now in hand. Rather than anchor you to a placeholder, the free Phase-1 memo delivers the itemized, open-book capital stack built on your numbers: equipment, EPC, biogas cleanup, permitting, interconnection, and the BCal developer fee, with the 30% §6417 Direct Pay rebate flowing to the general fund within 12–18 months of COD.
Structured to align BCal payment with NapaSan outcomes, and presented open-book as a share of the confirmed capital number — never as a markup buried in EPC pricing. The base is paid across pre-COD work; the largest tranche only triggers when the §6417 Direct Pay rebate actually arrives in NapaSan's general fund — BCal's incentive is locked to the cash showing up where you can see it.
Open-book pricing on every line in the waterfall — BCal earns through best-of-market sourcing, not through hidden markup. The exact fixed base and milestone schedule are set against the confirmed capital number in the free Phase-1 memo, then walked through with your team.
SGIP and LCFS excluded (SGIP permanently closed Dec 31, 2025 per CPUC D.25-12-003; LCFS stationary BTM = $0, transportation-only pathway). Financing modeled on tax-exempt municipal terms; the discount rate is set to NapaSan's own cost of capital in the memo.
The figures below are illustrative midpoints, not promises. PG&E industrial rates have risen ~35–45% since 2023, and BCal-side escalation is structurally lower (debt service flat, LTSA 2.5%/yr, RNG ~3%/yr). The delivered cost will be tested against your actual blended PG&E + MCE cost and your ~5¢/kWh self-generation — and note a portion of fuel is purchased natural gas. Drag the slider to test sensitivity.
The Year-1 picture is built from your 12 months of interval data and gas source test — not a template — and measured honestly against your ~5¢/kWh self-generation and blended PG&E + MCE cost, with a portion of fuel purchased as natural gas stated plainly. Where the durable value sits: §6417 Direct Pay cash to the general fund and a 20-year rate hedge. If it does not beat your number, the memo says so.
Status quo isn't free. Continuing the recip + paying PG&E + the forced 2034–35 capital cycle (at degraded §48E percentages) costs more than BCal in absolute dollars — and locks NapaSan into BAAQMD compliance risk.
The honest framing: the free Phase-1 memo tests whether a customer-owned fuel-cell block beats status quo + forced replacement over 20 years against NapaSan's actual costs — and says so plainly if it does not. The value lines that hold either way: ~32+ tons/yr NOx steadily reduced as the recip runs down, 30% §6417 Direct Pay cash to the general fund, bill-credit and demand-charge options across NapaSan meters (confirmed, not assumed, in the assessment), and a locked rate hedge against a PG&E + MCE generation cost curve that's already up 35–45% since 2023. Status quo also locks NapaSan into BAAQMD Reg 9-9 SCR retrofit pressure on the recip's next major mod.
As the fuel cell takes baseload, the aging recip runs fewer hours each year (target ramp-down ~2034), steadily reducing the dirtiest emissions source on the site. BAAQMD compliance load eases. Air-quality CEQA findings shift toward net beneficial.
FC ultra-low NOx eliminates BAAQMD Reg 9-9 BACT exposure entirely. Air-quality CEQA findings shift from significant-and-unavoidable to net beneficial. Running the cogen down could also generate banked NOx emission reduction credits under BAAQMD banking rules — speculative but high-potential given the magnitude of the source.
Our current numbers carry a ±20% confidence band (we used only public data). Each item NapaSan shares — via CPRA or NDA — narrows the band. Items 1–4 are CPRA; 5–8 trigger the mutual NDA + non-circumvention at Phase 2 entry. Model is fully transparent — toggle items below.
Both an owned structure and an energy-services agreement / PPA are workable here, and a 20-year LTSA covers O&M and maintenance under either one. The reason we lead with owning is a concrete cash upside: as a public agency, NapaSan can capture §6417 Direct Pay — a one-time rebate that an ESA cannot pass back at the same magnitude. If a maintenance-inclusive services agreement better fits NapaSan's balance-sheet posture, that path is fully open.
Size set to your available biogas and overnight import in the assessment. Fuel = the cogen's freed ~50% digester-gas share + a natural-gas top-up depending on sizing (sizing to available biogas is the lever — not 100% free fuel). Tie-in coordinated with the Electrical Improvement Project looped MV distribution while it is being engineered. Technology-neutral bake-off across the relevant platforms (SOFC / PAFC / microturbine / MCFC carbonate) — OEM resolved at Phase 2 entry under NDA.
Plus B-20 max-demand reduction · plus bill-credit and demand-charge options across NapaSan's PG&E meters (confirmed, not assumed, in the assessment) · plus 30% §6417 Direct Pay to the general fund within ~18 mo.
Modular — only if NapaSan demand growth + recycled-water expansion math supports. Construction-start before 12/31/33 to capture full §48E credit.
Phase 2 of the same plan that the existing 3rd-party deal was Phase 1 of. Not a critique of the prior decision — a continuation of it.
The rebuilt 415 kW recip is relieved of baseload and eventually succeeded as the fuel cell carries the load — running less over time rather than retired. June 2037: the existing 14-yr third-party PPA terminates; option to consolidate the 230 kW onto the customer-owned platform.
BAAQMD Reg 9-9 BACT exposure removed. Air-quality CEQA findings shift to net beneficial. Bill-credit options extended across NapaSan's PG&E accounts, as confirmed in the assessment.
Each step is a deliverable, not a meeting. Step 4 (LOI) puts NapaSan inside the §48E construction-start window with maximum schedule slack.
BCal-funded · public data only. Tariff modeling, load profile, sizing sensitivity, Electrical Improvement Project alignment, full incentive stack, portfolio bill-credit analysis, tech + EPC shortlist.
See data room2 hours on-site. Soscol central electrical room. Electrical Improvement Project design package. Biogas piping. Proposed FC + BESS pad. Tie-in feasibility memo within 5 business days.
Book site walkOne-page. Standard B2B. Unlocks: OEM bids, EPC partner introductions, peer CA WWTP biogas references with operational data, LTSA template. Triggers Phase 2 entry.
Download NDABCal drafts LOI for NapaSan FD&O review. §6417 Direct Pay eligibility memo + bond counsel concurrence. Board briefing material aligned to the Electrical Improvement Project capital schedule.
Request LOIMutual NDA + non-circumvention unlocks OEM identities, peer-deployment data, and LTSA templates. LOI puts NapaSan into the §48E construction-start window.
One-page. Mutual two-year term. Covers OEM identities, EPC partner introductions, peer-customer operational data, LTSA pricing comparables, portfolio bill-credit modeling. Designed for one-pass legal review.
Request NDA template (PDF)Letter of Intent within 5 business days of site walk. Preliminary economics, governance approval pathway, BCal developer-fee structure, capital-plan timing aligned to the Electrical Improvement Project, §6417 Direct Pay flow.
Request LOIOn-site at Soscol WRF. Central electrical room, Electrical Improvement Project design package walk-through, biogas piping, proposed FC + BESS pad, MCC tie-in points. Tie-in feasibility memo within 5 business days of the walk.
All projections on this page are preliminary and subject to material revision. Numbers shown are derived from publicly-available data (NapaSan ACFR, board packets, CIP 10-yr plan, FY budget, MCE / CWEA disclosures, PG&E tariffs, CARB / BAAQMD filings, public OEM datasheets, industry benchmarks) and BCal modeling assumptions disclosed under Block A/B/C/D of the parallel PDF term sheet. Every dollar figure, MW size, $/kWh rate, GHG ton, NOx number, and timeline date will change based on (a) the free Phase-1 14-day memo run against NapaSan-confirmed data, (b) firm vendor quotes received in Phase 2 bake-off, (c) site walk findings, (d) CPRA-confirmed utility + digester gas data, (e) BAAQMD + PG&E Rule 21(M) interconnect-study outcomes, (f) NapaSan Board procurement decisions, and (g) federal / state policy revisions to §48E, §6417, SGIP, RES-BCT, and BAAQMD rules. Specific OEM identities, EPC partner names, peer-customer references, and firm pricing terms are intentionally not disclosed on this page — they sit behind a one-page mutual NDA + non-circumvention at Phase 2 entry. BCal does not provide tax advice. NapaSan should consult its own tax counsel regarding §6417 Direct Pay and §48E ITC eligibility. This page is not an offer. Contact info@bcalenergy.com to initiate.