Clean Baseload Energy: Reality or Moonshot?https://www.byfounders.vc/insights/clean-baseload-energy-reality-or-moonshot
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Geothermal | Department of Energyhttps://www.energy.gov/topics/geothermal
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Key Challenges for California's Energy Futurehttps://ccst.us/reports/key-challenges-for-californias-energy-future-2/
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Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035 | Department of Energyhttps://www.energy.gov/cmei/examining-supply-side-options-achieve-100-clean-electricity-2035
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How We Can Make Energy Affordable for Everyone - MassCEChttps://www.masscec.com/blog/turning-tide-how-we-can-make-energy-affordable-everyone
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Powering a balanced future: Why clean baseload power mattershttps://arbor.co/updates/baseload-power/powering-a-balanced-future-why-clean-baseload-power-matters/
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Clean Firm Generation Technologies: What, Why, How ...https://www.catf.us/resource/clean-firm-electricity-technologies-why-what-how/
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Top 7 Energy Sources of the Future | 2026 Outlookhttps://www.deeptrekker.com/resources/energy-sources-of-future
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Sector Spotlight: Advanced Nuclear | Department of Energyhttps://www.energy.gov/edf/articles/sector-spotlight-advanced-nuclear
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Recent AI responses to this prompt
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
ChatGPT Search· Sep 25, 2026
If by “clean baseload” you mean electricity that is low-carbon, available around the clock, and dependable during prolonged periods of low wind/solar output, I would not treat this as a single-technology procurement problem. For a county utility, the practical strategy over 2026–2036 is a portfolio of clean firm resources plus transmission, storage, and demand flexibility.
DOE is explicitly describing rising demand for “clean firm” power, while EIA's recent operating data illustrate why nuclear and geothermal are fundamentally different from variable solar and wind: in 2025-era U.S. data, nuclear capacity factors were around 90%+, geothermal around 70%, versus roughly 20–30% for wind/solar.
A sensible 10-year portfolio
I would investigate five buckets:
Existing nuclear / new nuclear procurement
For genuinely 24/7 clean generation, nuclear is the most established large-scale option.
A county utility doesn't necessarily need to build a reactor itself. Look at long-term contracts, participation in a new project, purchasing from an existing nuclear fleet, or joining a consortium.
Advanced reactors/SMRs are worth evaluating for the 2030s, but I would treat them as a development opportunity rather than assuming a commercial schedule today. DOE itself describes advanced nuclear as an emerging pathway requiring coordinated deployment.
Geothermal
Conventional geothermal is geographically constrained, but enhanced/advanced geothermal could materially broaden the resource base.
Its attraction for a utility is that it can provide firm generation rather than simply adding more intermittent capacity.
A long-term offtake agreement could let you take technology risk without putting the entire capital burden on the utility.
Hydropower
Existing hydro is extraordinarily valuable as a firm/flexible clean resource.
New conventional sites are geographically limited, but opportunities can include purchasing output from existing projects, uprating existing facilities, and—in appropriate geography—pumped storage.
Don't overlook the value of flexibility rather than just annual MWh.
Renewables + substantial storage
Solar and wind should generally be viewed as energy resources, not substitutes one-for-one for firm capacity.
Pairing them with batteries and potentially long-duration energy storage (LDES) can turn inexpensive variable generation into a substantially more useful resource.
DOE specifically identifies LDES alongside advanced geothermal and SMRs as technologies whose commercialization creates both opportunities and risk for utilities.
Keep a smaller reliability backstop
Even with a clean portfolio, retain enough dispatchable capacity to handle unusual events while the new system is being built.
That could mean existing gas generation, contracted capacity, or other dispatchable resources depending on your state rules and emissions objectives.
The important distinction is capacity used for reliability versus baseload energy supplied continuously.
The key move: procure capacity, not just megawatt-hours
Suppose your utility needs another 100 MW of dependable supply.
Buying 100 MW of solar does not give you 100 MW of dependable generation at 2 a.m. during a cloudy winter week. Conversely, a nuclear or geothermal contract can provide substantially more dependable capacity per MW nameplate.
So I'd establish two separate procurement targets:
Requirement
What you procure
Annual clean energy
MWh
Firm capacity
MW available during system stress
Flexibility
MW that can ramp up/down
Multi-day resilience
MWh of storage/fuel/firm generation
Transmission resilience
Deliverability under contingencies
That prevents the common mistake of declaring a portfolio “100% clean” based on annual energy while still depending heavily on fossil generation during the hours that matter most.
What I'd do in the next 24 months
2026–2027: establish the requirement
Build a 10–15-year integrated resource model with at least:
The last point matters: DOE notes that large loads are creating new resource-adequacy and cost-allocation challenges for utilities.
2027–2029: lock in the near-term firm portfolio
I'd pursue several competitive solicitations simultaneously:
existing nuclear PPAs
geothermal PPAs
renewable + battery projects
standalone batteries
hydro opportunities
demand-response/large-load contracts
transmission/interconnection projects
Don't wait for advanced nuclear or advanced geothermal to become commercially mature before solving the nearer-term capacity problem.
2028–2031: make one or more long-lead bets
If the economics and regulatory environment work, this is where I'd consider taking a position in:
an advanced nuclear project,
a conventional nuclear expansion/restart,
an advanced geothermal project, or
a major long-duration storage project.
The advantage of participating early is that a county utility can potentially secure a portion of future firm capacity without having to own and operate the entire generating facility.
2030–2036: replace the temporary bridge
As new firm resources arrive, progressively reduce dependence on fossil generation for ordinary energy production while retaining whatever dispatchable capacity is needed for extreme reliability events.
Current federal policy is also unusually fluid: EPA changed its federal power-plant greenhouse-gas regulatory framework in September 2026, so I would explicitly model regulatory uncertainty rather than assuming today's rules will remain unchanged for the whole decade.
One particularly important option for a county utility
If you're relatively small, don't assume ownership is the best structure.
A very attractive model can be:
Long-term offtake + minority investment + shared risk
For example, instead of financing a $2–5 billion generating project yourself, the utility could commit to a 15–25-year purchase agreement and potentially take a minority equity position. That gives customers access to firm clean generation while spreading construction, operating and technology risk among multiple buyers.
I'd also make any large-load customer—data center, industrial plant, etc.—pay an appropriate share of the incremental generation and transmission commitment. DOE specifically flags cost shifting and stranded-asset risk as issues utilities should address when serving large new loads.
That is more robust than trying to identify a single “baseload” technology to carry the entire next decade.
If you tell me roughly your county's current peak MW, annual MWh, existing generation mix, and state, I can turn this into a concrete 2026–2036 resource plan with approximate MW additions, procurement sequence, and the major financial/regulatory risks.
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
Google AI Mode· Sep 25, 2026
Adding reliable, clean baseload power as a county or municipal utility over a 10-year horizon requires balancing strict regulatory mandates, capital constraints, and rapidly evolving generation technologies . Traditional baseload (coal and unmitigated gas) is increasingly sidelined by carbon constraints, leaving a mix of emerging and proven round-the-clock clean assets.
Here is a strategic roadmap tailored for a county utility scaling up clean baseload power through the next decade:
Advanced Geothermal Energy: Next-generation Enhanced Geothermal Systems (EGS) and closed-loop technologies have moved beyond traditional tectonic limitations. Unlike wind or solar, geothermal provides continuous 24/7 output with a small physical footprint, making it ideal for county-owned land portfolios.
Small Modular Reactors (SMRs): Microreactors and SMRs (typically under 300 MW) offer modular, factory-built nuclear generation without the multibillion-dollar financial exposure of legacy nuclear plants. County utilities can partner in joint-action agency pools to share the off-take capacity and regulatory overhead.
Long-Duration Energy Storage (LDES) + Firming: Pairing an oversised renewable portfolio (solar/wind) with emerging non-lithium LDES—such as iron-air, flow batteries, or compressed air energy storage (CAES)—allows a county to firm intermittent generation to mimic true baseload characteristics over a 100-hour duration window.
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
For a county utility, I’d treat this as a , not simply a “baseload plant” procurement. The objective over 2026–2036 should be enough dependable carbon-free capacity to cover peak demand and prolonged low-renewable periods, while using renewables and storage to minimize fuel and operating costs.
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
ChatGPT Search· Sep 13, 2026
If you’re a county utility planning for 2026–2036, I’d avoid treating “baseload” as synonymous with one giant generator. The better objective is clean firm capacity: electricity that can be counted on during the hours when wind and solar are weak, including multi-day stress events.
DOE’s latest analysis defines clean firm resources broadly—nuclear, hydro, geothermal, and renewables paired with long-duration storage—and concludes that a least-cost decarbonized system uses a portfolio rather than a single technology.
A practical 10-year strategy
1. Lock in existing firm clean power first
Before building anything, secure the lowest-risk megawatts available:
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
Adding reliable, clean baseload power over a 10-year horizon requires a strategic blend of mature generation technologies, grid-scale storage, and regulatory foresight tailored to a county utility's scale.
Here is a structured roadmap to guide your planning over the next decade:
Evaluate and Up-rate Existing Infrastructure
: If your county owns or purchases from local hydro, modernization and turbine upgrades can increase capacity factors and generation without building new greenfield sites.
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
Google AI Mode· Sep 9, 2026
Adding reliable, clean baseload (firm) power over a ten-year horizon requires a county utility to balance around-the-clock availability with strict decarbonization goals, capital constraints, and evolving regional reliability mandates. Traditional combustion generation is increasingly restricted, meaning utilities must look toward emerging and advanced firm power options.
Here is a strategic roadmap for a county utility to integrate clean baseload power over the coming decade:
Next-Generation Geothermal Energy : Transitioning past conventional hydrothermal limitations, enhanced geothermal systems (EGS) and closed-loop technologies use oil-and-gas-derived drilling techniques to unlock deep subsurface heat anywhere. Geothermal provides a high capacity factor (>80%) with a minimal land footprint, making it ideal for continuous local generation.
Question: As a county utility, how do we add reliable clean baseload power over the next decade?
ChatGPT Search· Sep 9, 2026
If I were advising a county utility for the 2027–2036 period, I would not try to solve this with one “baseload” technology. I’d build a clean-firm portfolio: resources that can reliably produce during prolonged periods of low wind/solar, backed by storage, transmission, and flexible load.
DOE’s current framing is similar: clean firm power includes nuclear, hydropower, geothermal, and renewables paired with long-duration storage; its modeling finds that batteries and demand response complement rather than replace clean firm resources.
A practical 10-year portfolio
Resource
Role
2036 target
Clean-Fuel Peakers and Repurposing: For immediate capacity bridging while long-lead clean baseload is built, evaluate retrofitting existing county thermal assets to co-fire or transition fully to green hydrogen or sustainably sourced renewable natural gas (RNG) captured from county wastewater and solid waste landfills.
Federal Funding and Financing Alignment: Capitalize on provisions under federal frameworks where tax credits and financing mechanisms heavily favor reliable, zero-emission baseload investments like nuclear and geothermal. Leverage public-private partnerships (P3) or municipal clean energy bonds to lower the cost of capital.
To help narrow down the best path for your specific county, could you share:
What is your approximate peak load and current generation mix?
Do you have access to local geothermal, heavy industrial waste heat, or landfill/ag-waste RNG resources?
Are you part of a joint-action agency or operating strictly as an independent county provider?
DOE’s recent planning work emphasizes a portfolio of advanced nuclear, geothermal, long-duration storage, renewables, grid upgrades, and flexible demand rather than one technology.
A practical 10-year strategy
Resource
Role
2026–30
2030–36
Existing nuclear / nuclear PPAs
Firm 24/7 clean energy
Secure extensions/PPAs
Continue
New nuclear
Large-scale clean firm capacity
Development/offtake
Construction/operation
Geothermal
Firm renewable generation
Site/resource studies
Build where resource supports it
Solar + 4–12h batteries
Cheap energy + daily capacity
Build aggressively
Expand
Long-duration storage
Multi-day reliability
Pilot/procure
Scale
Hydro / imports
Firm capacity where available
Contract
Expand contracts
Demand response
Reduce peak capacity requirement
Establish program
Scale
1. First, quantify the firm capacity gap
Don't start by asking “How many MW of baseload do we need?”
Instead model hourly load through 2036, including electrification, large new customers and extreme-weather conditions. Calculate:
peak MW and annual MWh
reserve margin
winter and summer peak requirements
renewable production during worst net-load periods
transmission/import capability
24-, 48-, 72-hour renewable droughts
outage of the largest generator/import path
fuel-security requirements
capacity needed after existing contracts expire
NREL's planning work explicitly models reliability hour by hour, rather than treating annual clean-energy percentages as sufficient.
That analysis will tell you whether your actual problem is, say, 150 MW of firm capacity, 500 MW, or primarily an energy/transmission problem.
2. Lock in the easiest firm clean power first
If you're in a region with existing nuclear generation, one of the most straightforward options is a long-term nuclear PPA or capacity contract, including potentially supporting continued operation of an existing plant.
For new-build nuclear, I'd begin development/procurement now, even if commercial operation isn't expected until the 2030s. DOE identifies nuclear as a clean, firm resource that can complement large amounts of wind and solar, while noting that construction cost, delivery and supply-chain risks remain important challenges.
For a county utility, that doesn't necessarily mean owning a reactor. Options include:
long-term PPA
utility consortium
capacity/offtake agreement
participation in an existing nuclear project
investment in a project in exchange for contracted output
This spreads construction and technology risk.
3. Put geothermal into the pipeline now
Geothermal is particularly interesting because it behaves much more like conventional generation than wind or solar.
DOE describes geothermal as firm, flexible renewable generation and specifically as baseload power with high capacity factors. DOE also sees significant potential for enhanced geothermal systems, including east of the Mississippi.
So even if your county doesn't have an obvious conventional geothermal resource, I'd conduct a geothermal resource screening study now. Enhanced/next-generation geothermal could become a meaningful 2030s procurement option.
4. Don't confuse batteries with baseload
Four-hour batteries are excellent for shifting solar into evening peaks, but they aren't a substitute for all forms of firm generation.
DOE categorizes long-duration storage from roughly 10 hours through multi-day and seasonal durations, with different technologies suited to different applications.
I'd therefore procure storage in layers:
2–4 hours: daily peak shaving
8–12+ hours: renewable shifting and extended evening coverage
potentially seasonal: only if your modeling demonstrates a need
Long-duration storage is still developing commercially, so a county shouldn't bet its entire reliability requirement on one emerging technology. DOE likewise describes LDES as a technology area still requiring commercialization and cost reductions.
5. Build lots of cheap clean energy around the firm core
There's an important economic distinction:
Firm generation provides reliability; it doesn't have to provide every MWh.
A system containing firm nuclear/geothermal/hydro plus solar, wind and storage can use the firm resources during scarcity while allowing inexpensive renewable electricity to supply much of the annual energy.
NREL's 2035 modeling found that wind and solar supplied 60–80% of generation in modeled clean-grid scenarios, alongside substantial storage and additional geothermal/hydro.
So I would avoid building a giant fleet of expensive 24/7 generators merely to produce energy that solar and wind could supply more cheaply.
6. Treat transmission as a generation resource
For a county utility, a firm clean-power contract from outside the county plus adequate transmission can be considerably easier than building generation locally.
Evaluate:
existing transmission headroom
interconnection queues
neighboring utility capacity
regional capacity markets
bilateral firm contracts
transmission upgrades
multiple import paths
But don't count an import as “firm” unless the contract and transmission rights actually survive the stressed conditions you're planning against.
A sensible procurement sequence
2026–2028: Secure the options
Commission an hourly 2036 integrated-resource study.
Establish the county's required firm MW and MWh.
Issue RFI/RFPs for nuclear, geothermal, hydro/imports and LDES.
Secure existing-nuclear or other clean-firm contracts where available.
Start geothermal resource assessment.
Build solar + 2–4h storage.
Begin transmission/interconnection projects.
Establish substantial demand-response capacity.
2028–2031: Commit to firm resources
Choose a diversified firm portfolio based on actual bids and reliability modeling.
For example—not a recommended fixed mix—you might ultimately have:
30–50% firm clean capacity + 50–70% variable renewable/storage capacity, with the percentages determined by your load shape, transmission position and regional market.
Advanced nuclear should be treated as a long-lead option, not something to wait until 2032 to investigate. DOE's updated analysis notes that U.S. electricity demand forecasts have risen substantially and that clean-firm capacity is increasingly important for new 24/7 loads.
2031–2036: Bring the portfolio online
By this point you want:
firm clean generation under long-term contract or ownership
substantial solar/wind
daily batteries
some multi-day storage
transmission redundancy
mature demand response
at least one additional firm technology in development as insurance
The key decision rule
I'd put every proposed resource through the same five questions:
How many MW can it actually deliver during our worst 50–100 hours?
How many consecutive hours/days can it sustain output?
What is the all-in cost per dependable MW, not merely $/MWh?
What happens if the project is delayed by three years?
Does it diversify or concentrate our technology, fuel, transmission and construction risk?
That produces a much more useful answer than simply comparing levelized costs.
Bottom line: for a county utility planning 2026–2036, I'd pursue a firm-clean backbone—existing/new nuclear, geothermal, hydro and/or long-duration storage—surrounded by large amounts of solar/wind, batteries, transmission and demand flexibility. Nuclear and geothermal are the clearest candidates for genuinely 24/7 clean generation; storage and transmission let you avoid paying for firm generation to run unnecessarily during ordinary conditions. DOE's current clean-energy planning similarly emphasizes this portfolio approach.
If you give me your county/state, current peak load, annual MWh, and whether you're an IOU, municipal utility, or co-op, I can turn this into a concrete 2026–2036 procurement roadmap with indicative MW quantities, project timelines, and decision gates.
2028–2031: Commit to firm resources
Choose a diversified firm portfolio based on actual bids and reliability modeling.
For example—not a recommended fixed mix—you might ultimately have:
30–50% firm clean capacity + 50–70% variable renewable/storage capacity, with the percentages determined by your load shape, transmission position and regional market.
Advanced nuclear should be treated as a long-lead option, not something to wait until 2032 to investigate. DOE's updated analysis notes that U.S. electricity demand forecasts have risen substantially and that clean-firm capacity is increasingly important for new 24/7 loads.
Adding reliable, clean baseload power as a county utility over the next decade requires navigating a complex landscape of shifting federal tax credits, capital constraints, and commercial readiness. Traditional fossil-fuel baseload options carry long-term regulatory and carbon risks, meaning public utilities must lean into firm, zero-emission generation technologies that can match continuous load profiles 24 ÷ 7.
Strategic pathways for a county utility to deploy clean baseload power over a 10-year horizon include the following options:
Advanced Geothermal Systems (Enhanced Geothermal & Closed-Loop): Leveraging oil and gas drilling innovations, next-generation geothermal can be deployed outside of traditional volcanic hot-spot zones. Enhanced Geothermal Systems (EGS) and closed-loop binary generators offer firm, weather-independent power with a minimal physical footprint and zero direct emissions. Partnering with project developers allows smaller municipal or county utilities to tap into mature-adjacent hydrothermal and EGS pipelines.
Small Modular Reactors (SMRs) and Microreactors: Nuclear tech has retained favorable tax backing for firm baseload projects. For a county utility, large-scale nuclear is financially and logistically out of reach, but SMRs (typically under 300 MW) offer scalable, factory-fabricated, and incrementally deployable nuclear baseload. Because lead times can stretch, the next decade is ideal for initial site-permitting, joint-action agency pooling, and Department of Energy (DOE) partnership alignment.
Firm Low-Carbon Fuels (Green Hydrogen and Renewable Natural Gas - RNG): If the utility operates existing combined-cycle combustion turbines or peaking units, transitioning fuel stock to 100% Green Hydrogen or locally captured RNG from municipal solid waste/wastewater treatment facilities can convert intermittent assets into clean baseload capacity. Co-firing or retrofitting existing county-owned generation assets minimizes greenfield siting battles.
Long-Duration Energy Storage (LDES) Paired with Oversized Renewables: While wind and solar are intermittent, pairing them with multi-hour or multi-day storage (such as iron-air batteries, flow batteries, or pumped hydro where geography permits) can mimic a true baseload profile. Integrated resource planning (IRP) should evaluate whether firm storage paired with regional solar/wind arrays undercuts the capital expenditure of nuclear or geothermal.
Joint-Action Agency Pooling and PPA Offtakes: County utilities rarely have the balance sheet to absorb the single-point failure of a multi-million-dollar emerging clean tech project. Pooling load through a joint action agency or signing long-term Power Purchase Agreements (PPAs) with regional clean baseload developers (such as commercial geothermal or regional hydro networks) transfers construction and operational risk away from county ratepayers.
To operationalize this over the next ten years, your immediate steps should involve updating your Integrated Resource Plan (IRP) with realistic market-based cost assumptions, evaluating local geologic or waste-to-energy resource potential, and looking into federal technical assistance frameworks via the DOE Office of Clean Energy Demonstrations to co-fund early-stage feasibility studies.
Adding reliable, clean baseload power as a county utility over the next decade requires navigating a complex matrix of federal incentives, shifting grid dynamics, and community expectations. Because baseload power must be always-on and weather-independent, your strategy needs to blend proven technologies with emerging clean alternatives.
Here is a strategic, step-by-step roadmap for a county utility to build out clean baseload capacity by 2036:
Evaluate Resource Adequacy and Load Growth
Demand Forecasting: Run high-resolution grid models accounting for regional electrification (EV adoption, industrial heat pumps, and localized data centers) to identify exact capacity shortfalls during peak and minimum load hours.
Capacity Credit Assessment: Determine how regional transmission organizations (RTOs) or independent system operators (ISOs) accredit capacity for various non-intermittent resources in your specific footprint.
Leverage Federal Funding and Financing Mechanisms
Inflation Reduction Act (IRA) Incentives: Maximize clean energy tax credits, utilizing "direct pay" options available to municipal and county utilities, alongside bonus credits for energy communities (e.g., coal-transition sites).
DOE Loan Programs Office (LPO): Explore Title 17 loan guarantees for innovative clean energy and advanced nuclear/storage projects that commercial banks might initially view as high-risk.
USDA REAP and GRIR: For smaller or rural county utilities, tap into Rural Utilities Service (RUS) funding for generation and transmission infrastructure upgrades.
Geothermal Energy: If your geography permits (especially enhanced geothermal systems or direct-use binary cycle plants), geothermal provides true 24/7 zero-carbon baseload with a small land footprint.
Biomass and Biogas: Capture methane from county landfills or wastewater treatment plants, or utilize sustainably sourced woody biomass in combined heat and power (CHP) configurations, ensuring carbon-accounting compliance.
Hydropower and Pumped Storage: Upgrade existing county-owned or local hydroelectric facilities for efficiency gains, or partner on regional pumped storage hydro to firm up variable renewables into pseudo-baseload.
Incorporate Bridge Technologies and Future-Proofing (2030–2036)
Hydrogen-Ready Natural Gas Turbines: Invest in high-efficiency combined-cycle gas turbines (CCGT) equipped with carbon capture and storage (CCS) or designed for future co-firing and 100% green hydrogen conversion as supply chains mature.
Advanced Small Modular Reactors (SMRs): Engage in regional municipal power agency consortia to co-invest in SMR nuclear technology, targeting initial deployments or power purchase agreements (PPAs) in the early 2030s for emissions-free, high-capacity-factor generation.
Pair Generation with Long-Duration Energy Storage (LDES)
Multi-Hour Storage: Complement your clean baseload assets with 8-to-24-hour storage technologies (such as iron-air, flow batteries, or compressed air energy storage) to smooth out minor generation variances and manage localized congestion.
Establish Strategic Regional Partnerships
Joint Action Agencies (JAAs): Pool resources with neighboring public power districts or municipal utilities to aggregate load, share financial risks of large-scale clean baseload procurement, and secure better pricing on long-term PPAs.
For a county utility, I’d treat this as a portfolio and procurement problem, not as a hunt for one technology. Over a 10-year horizon, the objective is to add enough firm capacity, energy, and fuel diversity that the system can reliably serve load during the worst hours—not merely to maximize annual clean MWh.
DOE’s recent work explicitly frames the problem this way: a decarbonized grid needs a combination of variable renewables, storage, transmission, and clean firm resources such as nuclear and geothermal.
A practical 10-year strategy
1. Lock in existing clean firm generation first
Before building anything exotic, investigate:
Long-term contracts or ownership stakes in existing nuclear plants
Uprates or life extensions at existing nuclear facilities
Existing hydroelectric resources
Firm geothermal where the resource exists
Power purchases from regional clean-firm generators
Nuclear is particularly valuable for a utility that needs genuine 24/7 output: U.S. nuclear plants have historically operated at very high capacity factors, with EIA reporting 92.3% in 2016 and nuclear generally having the highest capacity factors among U.S. generators.
For a county utility, buying into an existing operating plant can be much less execution-risky than trying to develop a new reactor yourself.
2. Build a large renewable portfolio—but don't call it baseload
Solar and wind should probably provide a substantial portion of your incremental energy because they're deployable and modular. But plan around their variability rather than pretending they are firm resources.
Pair them with:
4–8+ hour batteries
Transmission/interconnection upgrades
Demand response
Flexible hydro where available
Increasing amounts of longer-duration storage
NREL's modeling found that high-clean-energy systems require substantial storage and transmission in addition to wind and solar; in its 2035 scenarios, storage ranged from 120–350 GW of diurnal capacity and seasonal storage became increasingly important at very high clean-generation shares.
3. Make one clean-firm technology your "anchor"
For a 2030s procurement, I'd investigate three candidates rather than prematurely choosing one:
Option
What it contributes
Main issue for a county utility
Existing nuclear / nuclear PPA
Very high availability, large quantities of firm energy
Contract/market exposure; limited new supply
New nuclear / SMR
Long-lived, carbon-free firm generation
Construction and financing risk
Geothermal
Firm renewable generation
Resource/site uncertainty
DOE's 2025 nuclear analysis explicitly compares nuclear with geothermal, hydropower and renewables-plus-storage as clean-firm options, while noting that nuclear is currently one of the few clean-firm technologies demonstrated at large scale.
Next-generation geothermal deserves more attention than it gets. Enhanced and closed-loop geothermal could provide essentially around-the-clock generation without the intermittency of wind and solar, although commercial deployment and cost remain less mature than conventional geothermal.
4. Don't put all your "firm" eggs in one basket
A reasonable conceptual portfolio for a county utility might look something like:
30–50% incremental energy: wind + solar
10–20%: batteries and other short/medium-duration storage
20–40%: nuclear, geothermal, hydro, or other contracted clean firm power
5–15%: demand response, efficiency, distributed resources and other flexibility
Regional transmission/market purchases filling the remaining gaps
Those aren't recommended percentages—they're a starting point for scenario analysis. The optimal mix depends enormously on your existing fleet, load shape, transmission position, state regulation, and wholesale-market access.
The interesting move: procure "clean firm," not necessarily "baseload"
I'd actually change the procurement specification.
Instead of issuing an RFP for:
"500 MW of baseload generation"
issue an RFP for something closer to:
500 MW of dependable, dispatchable, carbon-free capacity capable of meeting specified hourly availability requirements for 20+ years.
Then let nuclear, geothermal, hydro, storage and hybrid projects compete against one another.
That prevents the utility from deciding the technology before determining what reliability service it actually needs.
A particularly useful structure: three procurement rounds
2026–2028: buy reliability
Secure relatively low-risk resources:
Existing nuclear PPAs/ownership
Wind and solar
4–8 hour batteries
Demand-response programs
Transmission/interconnection improvements
Efficiency and load management
At the same time, conduct a serious clean-firm solicitation.
2028–2031: commit to the next anchor
By then, you should have much better information on:
Load growth
Data-center/industrial demand
Battery costs
Geothermal projects
Advanced nuclear projects
Regional transmission
Wholesale-market conditions
That's when I'd make a major 15–30-year clean-firm commitment, rather than betting the county's finances on an immature technology today.
2031–2036: fill the remaining reliability gap
Use actual system performance to determine whether the remaining need is best met by:
Additional nuclear
Geothermal
Long-duration storage
Additional transmission
Flexible demand
More renewable overbuild
DOE estimates that long-duration storage could become a very large component of a deeply decarbonized U.S. grid, but it is still a developing commercial sector.
One thing I'd avoid
I would not make the 10-year plan depend entirely on a first-of-a-kind advanced reactor.
Advanced nuclear could ultimately be an important part of the mix. But DOE itself identifies construction cost overruns, project abandonment, supply-chain scaling and deployment timing as significant barriers.
A county utility has a different risk profile from a venture investor. You need the lights to stay on even if one technology deployment slips five years.
So I'd structure the portfolio such that an advanced nuclear or next-generation geothermal project can be an upside opportunity rather than a single point of failure.
The key planning metric
Don't optimize for $/MWh alone.
Have your IRP model at least:
$/MWh
$/kW-year of dependable capacity
Effective load-carrying capability
8760-hour reliability
Extreme-weather performance
Fuel-price exposure
Construction-delay risk
Transmission requirements
20–30-year total system cost
CO₂ and other emissions
Local economic impacts
Ratepayer exposure under high/low load growth
That last part matters enormously. DOE's recent nuclear analysis notes that conventional planning frameworks can overweight today's costs and underweight the long operating life and reliability value of clean firm assets.
Bottom line: for the next decade, I'd pursue renewables + storage for inexpensive energy, existing nuclear/hydro/geothermal for dependable clean energy, and one carefully structured clean-firm procurement for the 2030s. That gives the county a path to materially cleaner power without making reliability dependent on any single emerging technology.
If you tell me the county's peak load, annual MWh, current generation mix, state, and whether you're in an organized wholesale market, I can turn this into a concrete 2026–2036 procurement plan with MW targets, approximate costs, reliability margins, and a decision tree for nuclear vs. geothermal vs. storage.
$/MWh
$/kW-year of dependable capacity
Effective load-carrying capability
8760-hour reliability
Extreme-weather performance
Fuel-price exposure
Construction-delay risk
Transmission requirements
20–30-year total system cost
CO₂ and other emissions
Local economic impacts
Ratepayer exposure under high/low load growth
That last part matters enormously. DOE's recent nuclear analysis notes that conventional planning frameworks can overweight today's costs and underweight the long operating life and reliability value of clean firm assets.
Additional nuclear
Geothermal
Long-duration storage
Additional transmission
Flexible demand
More renewable overbuild
DOE estimates that long-duration storage could become a very large component of a deeply decarbonized U.S. grid, but it is still a developing commercial sector.
Extend contracts for existing nuclear generation where possible.
Investigate participation in nuclear uprates or existing-plant expansions.
Preserve existing hydro and evaluate modest efficiency upgrades.
Pursue power-purchase agreements with existing clean generators rather than assuming every new MW must be county-owned.
This is especially attractive because existing nuclear has already demonstrated the reliability characteristics you're looking for, while new nuclear still carries substantial construction and financing risk.
2. Make new nuclear your 10-year firm-power option
If your county has substantial, predictable load growth, I'd put new nuclear/SMRs into the serious-development pipeline now, but I would not make a 2030s nuclear project the only reliability plan.
The reason is timing. DOE's nuclear commercialization analysis says new nuclear deployment needs to begin this decade to scale meaningfully, and its 2025 update estimates the U.S. needs roughly 700–900 GW of additional clean firm capacity under its updated demand projections.
For a county utility, that means:
2026–28: site screening, feasibility, interconnection, community engagement, technology/vendor evaluation, and participation in a multi-utility procurement.
2028–31: commit only if the technology, cost-sharing structure, licensing pathway and construction contract are sufficiently mature.
Early/mid-2030s: target first commercial operation.
I'd favor joining a consortium or buying a defined share of a larger project over trying to finance a first-of-a-kind reactor alone.
3. Build geothermal into the portfolio
Geothermal is particularly interesting because it behaves much more like traditional baseload than solar or wind.
Conventional geothermal is geographically constrained, but enhanced/next-generation geothermal systems (EGS) potentially expand the resource base. DOE's 2025 geothermal analysis projects EGS costs falling substantially and explicitly treats next-generation geothermal as a clean-firm resource.
For a county utility, I'd spend relatively little money now on resource assessment and offtake agreements, rather than betting the entire plan on a specific EGS developer.
4. Pair lots of renewables with storage
Don't underestimate this option. A portfolio such as:
can provide a surprisingly large amount of firm capacity without requiring every MW of demand to be served by a conventional baseload generator.
DOE defines long-duration storage as 10+ hours, and is specifically targeting dramatic cost reductions in this category.
The key distinction is:
4-hour batteries are primarily an intraday resource; they aren't your complete answer to a three-day winter weather event.
So I'd procure batteries now while reserving part of the portfolio for longer-duration technologies as they mature.
5. Design for the ugly week, not the average day
This is probably the most important planning change.
Instead of asking:
"How many MW of baseload do we need?"
ask:
"During our worst 1%, 5%, and 10% weather/load conditions, where do every one of our MW come from?"
Model events such as:
3–5 days of unusually low wind
prolonged winter cloud cover
extreme summer heat
transmission outages
major generator outages
simultaneous regional demand peaks
fuel-supply disruptions
Then assign a capacity-credit value to every resource.
That exercise will tell you whether you actually need 200 MW of nuclear—or perhaps 100 MW nuclear + 150 MW geothermal + 300 MW renewables + storage + firm market contracts.
What I'd target by 2036
For a hypothetical county utility with 1,000 MW of peak load, I'd initially investigate something roughly like:
Resource
Illustrative target
Existing/contracted nuclear & hydro
150–250 MW
New nuclear/SMR or geothermal
150–250 MW
Solar
400–700 MW
Wind
200–400 MW
2–4 hour batteries
200–400 MW
10+ hour storage
100–250 MW
Firm market/neighboring utility contracts
100–200 MW
Demand response/managed load
50–100 MW
Those aren't recommended final numbers—the capacity mix needs to come out of your hourly load/resource modeling. But it illustrates the architecture: some genuinely firm generation surrounded by a much larger flexible clean-energy system.
DOE's modeling similarly finds substantial roles for wind/solar, storage, hydro and geothermal while retaining clean firm resources for reliability.
The procurement strategy I'd use
For a county utility, I'd divide the next decade into three buckets:
Develop now for 2030–36:
Nuclear/SMR, geothermal, pumped hydro and other 10+ hour storage.
Don't depend on yet:
Fusion and other genuinely first-commercial-of-a-kind technologies. DOE's current fusion roadmap targets commercial power in the mid-2030s, but that is still a development pathway rather than something I'd count as a guaranteed 2032 capacity resource.
The biggest mistake to avoid
Don't equate "clean" with "firm," or "renewable" with "reliable capacity."
Your utility should procure energy, capacity, flexibility and resilience separately. A 100-MW solar farm and a 100-MW nuclear plant are both 100 MW nameplate, but they provide very different reliability products.
If you give me your approximate peak load, annual MWh, expected 2035 load, existing generation/contracts, and whether you're municipally owned or an electric cooperative, I can turn this into a 10-year county utility resource plan, including a suggested MW mix, procurement timeline, reliability strategy, and rough capital requirements.
4-hour batteries are primarily an intraday resource; they aren't your complete answer to a three-day winter weather event.
So I'd procure batteries now while reserving part of the portfolio for longer-duration technologies as they mature.
5. Design for the ugly week, not the average day
This is probably the most important planning change.
Instead of asking:
"How many MW of baseload do we need?"
ask:
"During our worst 1%, 5%, and 10% weather/load conditions, where do every one of our MW come from?"
Model events such as:
3–5 days of unusually low wind
prolonged winter cloud cover
extreme summer heat
transmission outages
major generator outages
simultaneous regional demand peaks
fuel-supply disruptions
Then assign a capacity-credit value to every resource.
That exercise will tell you whether you actually need 200 MW of nuclear—or perhaps 100 MW nuclear + 150 MW geothermal + 300 MW renewables + storage + firm market contracts.
What I'd target by 2036
For a hypothetical county utility with 1,000 MW of peak load, I'd initially investigate something roughly like:
Resource
Illustrative target
Existing/contracted nuclear & hydro
150–250 MW
New nuclear/SMR or geothermal
150–250 MW
Solar
400–700 MW
Wind
200–400 MW
2–4 hour batteries
200–400 MW
10+ hour storage
100–250 MW
Firm market/neighboring utility contracts
100–200 MW
Demand response/managed load
50–100 MW
Those aren't recommended final numbers—the capacity mix needs to come out of your hourly load/resource modeling. But it illustrates the architecture: some genuinely firm generation surrounded by a much larger flexible clean-energy system.
DOE's modeling similarly finds substantial roles for wind/solar, storage, hydro and geothermal while retaining clean firm resources for reliability.
The procurement strategy I'd use
For a county utility, I'd divide the next decade into three buckets:
Advanced Combined Heat and Power (CHP) : Transition existing municipal or county waste-to-energy and biomass facilities to high-efficiency CHP, utilizing sustainable local organic waste streams for steady 24/7 output.
Invest in Next-Generation Nuclear (SMRs)
Small Modular Reactors (SMRs) : Over a 10-year timeline, commercialized SMRs (typically 50–300 MW) offer a modular, scalable, and zero-emission baseload solution specifically sized for regional and county utility footprints.
Consortium Partnerships : Partner with neighboring utilities or state agencies to share the high initial regulatory and siting costs of advanced nuclear development.
Incorporate Firming and Long-Duration Energy Storage (LDES)
Pumped Storage and Compressed Air : Pair variable renewables with long-duration storage (10+ hours) to flatten intermittent curves, effectively creating a synthetic baseload.
Emerging Chemistries : Monitor iron-air or flow batteries coming to market that offer multi-day discharge capabilities at a lower cost than lithium-ion for grid-level stability.
Secure Clean Firm Power Purchase Agreements (PPAs)
Geothermal Energy : Explore regional deep geothermal or enhanced geothermal systems (EGS) via long-term PPAs, providing reliable thermal-driven generation independent of weather.
Interstate Transmission Access : Invest in local transmission upgrades to tap into remote, high-capacity clean baseload zones (such as regional wind-plus-storage corridors or distant geothermal fields).
Navigate Financing and Federal Incentives
Direct Pay Provisions : Utilize federal funding mechanisms like the Inflation Reduction Act's "elective pay" to directly subsidize clean energy and storage deployment for public entities.
USDA REAP and DOE Grants : Leverage programs via the U.S. Department of Energy and rural utility financing structures to de-risk early-stage engineering and environmental impact studies.
If you'd like, let me know:
Your current peak load demand and generation mix
Whether you serve a rural, suburban, or industrial customer base
I can help tailor these strategies to your specific capacity needs and budget constraints.
Small Modular Reactors (SMRs) : Advanced nuclear SMR designs (typically under 300 MW per unit) offer factory-fabricated, scalable, and zero-emission continuous power. They are well-suited for repowering retiring coal or fossil sites where existing transmission interconnections and cooling water infrastructure are already established.
Clean Biomass and Biogas Combined Heat and Power (CHP) : Utilizing local forestry waste, agricultural byproducts, or wastewater treatment anaerobic digesters turns localized waste liabilities into carbon-neutral, dispatchable power. It also bolsters local rural economic supply chains.
Long-Duration Energy Storage (LDES) Paired with Oversized Renewables : While technically storage rather than pure generation, pairing solar or wind with emerging 8-to-24-hour storage technologies (such as iron-air, flow batteries, or pumped hydro) can simulate baseload profiles if regional resource-sharing pools (like WRAP) permit capacity accreditation.
Strategic Procurement and Regional Pooling : Aggregating demand through joint action agencies or issuing structured Request for Offers (RFOs) allows smaller county utilities to share financial risk, contract with utility-scale clean firm providers, and comply with state capacity mandates without bearing 100% of the capital expenditure directly.
To help tailor this strategy, could you share:
What is your utility's approximate peak load and service territory geography?
Are you bound by specific state carbon-reduction deadlines or renewable portfolio standards?
Do you have access to retiring fossil-fuel infrastructure or industrial waste heat sites?
Those percentages should be treated as a planning starting point, not a prescription—the right mix depends heavily on your load shape, transmission access, and what resources you can contract regionally.
1. Preserve and contract for nuclear first
If your county can access existing nuclear generation through its wholesale market, a long-term PPA or other contract for existing nuclear output is one of the quickest ways to add genuinely clean, around-the-clock energy. U.S. nuclear plants have historically operated at very high capacity factors; EIA notes that they generally run near full output and refuel roughly every 18–24 months.
For new nuclear, I'd be more cautious. Don't make a county utility the sole risk bearer for a first-of-a-kind reactor. Instead, consider joining a multi-utility consortium or signing an offtake agreement contingent on demonstrated milestones, cost ceilings and construction progress.
DOE's 2025 advanced-nuclear update explicitly identifies nuclear as a clean-firm resource and argues that clean firm resources reduce overall decarbonization costs.
2. Make geothermal your technology-development bet
Geothermal is particularly interesting because it provides what utilities actually mean by baseload: continuous renewable generation.
DOE describes geothermal as firm, flexible, renewable generation with high capacity factors, and its Enhanced Geothermal Shot analysis estimates at least 90 GW of potential U.S. geothermal capacity by 2050—including potential east of the Mississippi.
For a county utility, I would investigate:
conventional geothermal where the resource exists;
enhanced/next-generation geothermal;
partnerships with developers on demonstration projects;
geothermal heat/cooling for municipal facilities as a parallel opportunity.
The key is to procure geothermal competitively rather than assuming today's emerging projects will automatically be economical.
3. Build lots of cheap energy—but don't call it baseload
Wind and solar should probably supply a large majority of your annual incremental clean electricity, even though neither is firm by itself.
The trick is to stop asking:
“How many MW of baseload do we need?”
and start asking:
“How many MW and MWh do we need to survive the worst 1%, 0.1%, and multi-day weather events?”
That leads to a much more economical system: lots of inexpensive wind/solar energy, plus a smaller quantity of genuinely firm resources and storage.
4. Procure long-duration storage, not just batteries
I'd establish a storage portfolio with at least two durations:
2–8 hours: conventional lithium-ion batteries for daily solar shifting and grid services.
10–100+ hours: long-duration technologies for multi-day renewable shortfalls.
DOE's Long Duration Storage Shot specifically targets systems capable of 10+ hours of storage.
Don't bet the county's reliability on one emerging storage technology. Run competitive procurements and let developers propose flow batteries, thermal storage, compressed air, pumped hydro, iron-air, other chemistries, etc., subject to the same reliability and cost requirements.
5. Buy reliability from the regional grid
A county doesn't necessarily need to own all of its clean firm capacity.
I'd deliberately diversify geographically:
local resources + regional PPAs + transmission rights + capacity/firm-energy contracts.
A windless, cloudy week in your county doesn't necessarily coincide with one across a huge regional footprint. Geographic diversity is itself a reliability resource.
This is especially important because electricity reliability is ultimately an hour-by-hour system problem, not an annual-energy problem. EIA emphasizes that operators have to continuously balance generation and demand.
The procurement strategy I'd use
Rather than issuing one giant “clean power RFP,” create four procurement tracks:
Track A — Clean firm
Solicit 15–30 year offers for:
nuclear;
geothermal;
hydro;
other qualifying firm clean resources.
Require bidders to specify firm MW, annual MWh, forced-outage assumptions, fuel/resource risk, and availability during extreme weather.
Track B — Clean energy
Procure large quantities of:
solar;
wind;
existing clean generation.
Optimize this primarily for $/MWh, not capacity factor.
Track C — Firming
Procure:
4-hour batteries;
8–12+ hour storage;
eventually multi-day storage.
Pay explicitly for capacity and grid services rather than pretending storage is generation.
Track D — Flexibility
Pay customers to become part of the power system:
EV charging;
water heating;
municipal pumping;
wastewater treatment;
commercial HVAC;
thermal storage;
industrial load shifting.
DOE's work on virtual power plants recognizes that distributed customer assets can contribute to a resilient electricity system.
The most important planning exercise
Before choosing technologies, I'd spend the first 12–18 months building a 10-year hourly reliability model.
Model at least:
hourly load through 2036;
electrification/EV adoption;
data-center or industrial-load scenarios;
extreme cold/heat;
prolonged wind droughts;
prolonged cloudy periods;
generator outages;
transmission constraints;
fuel constraints;
hydro drought;
storage degradation;
demand-response availability.
Then calculate:
1. Annual energy requirement
2. Peak MW requirement
3. Firm capacity requirement
4. 24-, 48-, 72-, and 120-hour energy deficit
5. Expected unserved energy / loss-of-load metrics
That will tell you whether you actually need 100 MW, 300 MW, or 1 GW of clean firm resources. It is much more defensible than picking a baseload percentage.
A good 10-year sequence
2027–28:
Build the hourly reliability model, secure existing nuclear/hydro contracts, launch solar/wind procurement, and issue initial battery/storage RFPs.
2029–31:
Bring substantial solar/wind online; deploy batteries; secure regional transmission and firm clean-energy contracts; begin geothermal and/or advanced-nuclear participation.
2032–34:
Add the first tranche of genuinely clean firm new-build capacity and long-duration storage based on what the reliability model says is actually needed.
2035–36:
Re-optimize the portfolio rather than blindly following the original plan. By then, the economics and maturity of geothermal, advanced nuclear and long-duration storage should be considerably clearer.
One principle I'd put in the board resolution
Don't procure “baseload.” Procure clean energy, clean firm capacity, flexibility, and resilience as separate products.
That gives the county several ways to win: nuclear can provide firm energy, geothermal can provide renewable firm power, wind/solar can provide cheap energy, storage can shift it, and flexible loads can reduce the amount of expensive firm capacity you need.
And importantly, don't wait ten years for a perfect technology. Lock in the mature pieces now while creating options for the technologies that could become much more valuable by 2032–36.
