As a county utility, how do we add reliable clean baseload power over the next decade?

As a county utility, you can add reliable clean baseload power over the next decade by combining small modular nuclear reactors (SMRs), long-duration energy storage (LDES), firm geothermal generation , and upgraded regional transmission links.

To achieve a 24/7 carbon-free power portfolio within a ten-year horizon, focus on these core strategies:

Clean Baseload Generation Technologies

• Small Modular Reactors (SMRs): Deploy factory-built nuclear reactors generating 50-300 MW per module, offering zero-emission, continuous power with a smaller footprint than legacy nuclear.
• Enhanced Geothermal Systems (EGS): Tap into deep subterranean heat using advanced hydraulic fracturing techniques pioneered in oil and gas to produce constant baseload power independent of weather or location constraints.
• Clean Hydrogen-Ready Turbines: Build combined-cycle combustion turbines fueled initially by a natural gas-hydrogen blend, transitioning to 100% green hydrogen as regional supply scales up.

Storage and Grid Optimization

• Long-Duration Energy Storage (LDES): Invest in non-lithium storage systems—such as iron-air, flow batteries, or pumped hydro—capable of discharging continuous power for 10 to 100+ hours to back up intermittent renewables.
• Grid-Enhancing Technologies (GETs): Deploy dynamic line rating and topology optimization on existing distribution and transmission lines to maximize carrying capacity without costly new copper builds.
• Virtual Power Plants (VPPs): Aggregate commercial and residential smart thermostats, heat pumps, and electric vehicle chargers to smooth out peak demand and reduce required baseload reserve margins.

Implementation Roadmap

If you can share your current peak load (MW), state location , and whether you own generation or solely distribute power, I can tailor a more precise technology mix and funding strategy for your utility.

If by “clean baseload” you mean power that is low-carbon, available through the night and during prolonged periods of low wind/solar, and dependable enough to count toward resource adequacy, I would not try to solve this with one technology.

For a county utility planning roughly 2026–2036, I’d build a clean-firm portfolio: existing nuclear/long-term nuclear contracts where available, geothermal and hydro where geographically feasible, plus renewables, storage, transmission, and demand flexibility. DOE’s current clean-firm framework explicitly includes nuclear, hydro, geothermal, and renewables paired with long-duration storage.

A practical 10-year strategy

1. Lock in the cheapest firm clean power first

A. Existing nuclear / nuclear PPAs — highest-value if accessible

If you can buy output from an existing nuclear plant through a long-term PPA or participate in a regional nuclear project, I'd investigate this before building a new plant yourself.

U.S. nuclear has historically operated around a 90%+ capacity factor, versus roughly 25–30% for utility-scale PV, making it unusually valuable for firm energy.

For a county utility, the key question isn't necessarily “Can we build a nuclear plant?” It's:

Can we contract for 100–500 MW of nuclear output without taking construction risk onto the county balance sheet? That could mean a long-term PPA, participation in an existing utility's project, or an eventual advanced-reactor offtake agreement.

2. Make geothermal your first serious new-build clean-firm candidate

Geothermal is particularly interesting because it provides 24/7 generation without the intermittency problem. EIA data show geothermal operating at substantially higher utilization than solar and wind.

There are two very different opportunities:

• Conventional geothermal if you are in a resource-rich area.
• Enhanced geothermal systems (EGS) if conventional resources aren't available.

I'd issue an RFI/RFP now—not necessarily to build immediately, but to establish whether developers can offer you a 15–25 year fixed-price clean-firm PPA beginning in the early/mid-2030s.

3. Build lots of cheap solar—but don't call it baseload

Solar should probably be a major part of the portfolio because it is comparatively quick to deploy and produces inexpensive daytime energy.

But don't make the planning mistake of treating 1 MW of solar as equivalent to 1 MW of firm capacity.

EIA's data illustrate the difference: utility-scale PV's annual capacity factor has been around the mid-20% range, while nuclear has been above 90%.

Instead, pair solar with:

• 4–8 hour batteries for daily shifting
• 8–24+ hour storage as that market matures
• transmission/interties
• flexible load
• firm generation

The objective becomes firming a portfolio, rather than making every individual generator firm.

4. Treat long-duration storage as a strategic option, not today's foundation

I'd procure some batteries now, but I wouldn't bet the county's entire 2036 reliability plan on one particular long-duration technology.

DOE describes long-duration storage as important for resilience and integrating renewables, while also noting that the technology is still maturing.

So structure the plan around technology-neutral capacity requirements:

“We need X MW capable of delivering Y MW for 12–100 hours under defined reliability conditions.” Then let developers compete with batteries, pumped hydro, thermal storage, flow batteries, compressed air, or other technologies.

That avoids locking the county into today's technology.

5. Don't overlook regional transmission

For a county utility, firm power doesn't have to be physically inside the county.

A portfolio such as:

300 MW nuclear + 200 MW geothermal + 500 MW solar + 300 MW wind + 300 MW battery + strong regional transmission

can be considerably more reliable than trying to construct 1,000 MW of generation locally.

Transmission diversity matters because geographic diversity reduces the probability that your entire renewable fleet experiences the same weather event simultaneously.

6. Preserve a small amount of dispatchable backup

I'd be cautious about prematurely retiring every gas turbine.

There is a major distinction between:

• running gas for 5,000 hours/year, and
• keeping a gas turbine available for 50–200 critical hours/year.

The latter can provide insurance while clean firm technologies scale.

If decarbonization is a hard requirement, investigate eventually replacing that role with clean hydrogen, renewable fuels, carbon capture, or additional long-duration storage. DOE includes CCS and hydrogen among technologies being developed for on-demand clean power.

What I'd actually put into a county IRP

I'd create three portfolios rather than choosing a technology today:

Those aren't recommendations for your specific load—they're planning magnitudes to illustrate the architecture. Your actual mix should come from an hourly production-cost/reliability model.

The key change: procure reliability, not megawatts

This is probably the most important point.

Instead of issuing an RFP saying:

“County wants 300 MW of clean generation.” I'd issue something closer to:

“County seeks 300 MW of new carbon-free capacity capable of meeting defined hourly availability and multi-day reliability requirements, with bidders permitted to propose generation, storage, hybrid resources, or portfolios.” Then score proposals on:

1. Firm capacity contribution
2. Energy cost ($/MWh)
3. Total delivered system cost
4. Performance during extreme weather
5. Duration of guaranteed output
6. Fuel/resource risk
7. Transmission requirements
8. Construction/development risk
9. Counterparty credit
10. Emissions
11. Black-start/islanding capability where valuable
12. 20–30 year lifecycle cost

That prevents the classic mistake of buying lots of nominally “clean” MW while still having a reliability problem.

One especially important financial opportunity

If the county utility is a governmental/tax-exempt entity, have your tax counsel examine elective/direct-pay treatment of federal clean-electricity incentives rather than assuming tax credits are irrelevant because the utility doesn't pay federal income tax.

The IRS says eligible government entities can potentially use elective payment for the Clean Electricity Production Credit, subject to registration and the applicable requirements.

That can materially change the economics of county-owned or county-participated projects.

My preferred sequence

2026–28:

• Forecast hourly load through 2040, including EVs, data centers, water/wastewater and electrification.
• Quantify the county's capacity-at-risk during extreme weather, not just annual energy.
• RFP for nuclear, geothermal and regional clean-firm PPAs.
• Begin solar + 4–8 hour battery deployment.
• Secure transmission/interconnection rights.
• Establish a 10–15 year clean-firm procurement framework.

2029–32:

• Bring the first large clean-firm resources online.
• Expand solar/wind and batteries.
• Pilot long-duration storage.
• Add demand-response/managed-load programs.
• Re-run the IRP annually as load and technology costs change.

2033–36:

• Make the big 20–30-year firm-capacity commitment based on what has actually proven itself.
• Potentially participate in an advanced nuclear or large geothermal project.
• Scale long-duration storage if it has demonstrated adequate reliability.
• Reduce dependence on fossil backup as firm clean resources become available.

Bottom line

I would not bet the county on “the next nuclear technology,” nor on batteries alone, nor on massive amounts of solar.

I'd pursue a three-layer system:

1. Clean firm: nuclear + geothermal/hydro where available 2. Cheap energy: solar + wind 3. Reliability layer: batteries + long-duration storage + demand response + transmission + limited dispatchable backup

That is much closer to how I'd design a resilient municipal utility than trying to identify a single technology that deserves the label “baseload.” DOE's current modeling similarly concludes that batteries and demand response are important but do not eliminate the value of clean-firm resources.

If you tell me the county/state, current peak load and annual MWh, existing generation/PPAs, and expected 2035 peak, I can turn this into a 10-year county utility resource plan with MW targets, estimated capital requirements, procurement sequence, and a base/bull/bear scenario.

If the county utility is a governmental/tax-exempt entity, have your tax counsel examine elective/direct-pay treatment of federal clean-electricity incentives rather than assuming tax credits are irrelevant because the utility doesn't pay federal income tax.

The IRS says eligible government entities can potentially use elective payment for the Clean Electricity Production Credit, subject to registration and the applicable requirements.

What I'd actually put into a county IRP

I'd create three portfolios rather than choosing a technology today:

Yes. For a county-owned or county-controlled utility, I would not try to solve “baseload” with one technology. Over a 10-year horizon, the robust strategy is a clean-firm portfolio: resources that can reliably serve load during the hours when wind and solar are weak, backed by transmission, storage, demand flexibility, and a modest amount of dispatchable capacity during the transition.

The distinction matters: “baseload” is really an operational requirement—energy and capacity available when needed—rather than necessarily a particular type of generator.

My recommended 2026–2036 strategy

EIA's latest data illustrate why this needs to be a portfolio: nuclear has historically operated at very high capacity factors, while geothermal and biomass are the highest-capacity-factor renewable categories; wind and solar output varies with weather and time of day.

1. First, quantify the actual firm-power requirement

Don't start by saying “we need 500 MW of baseload.”

Build a 10-year hourly model incorporating:

• peak demand and annual energy;
• winter vs. summer peaks;
• electrification of heating and transportation;
• data centers/industrial prospects;
• existing generation retirements;
• transmission import capability;
• extreme-weather conditions;
• fuel-security requirements;
• reserve margin;
• correlated renewable droughts;
• several consecutive days of low wind/solar.

Then establish a target such as:

X MW of clean firm capacity + Y TWh/year of clean energy + Z MW of emergency capability by 2036. That is a much more useful procurement target than “baseload.”

This is increasingly important because U.S. electricity demand is moving upward after years of relatively flat growth; DOE's 2025 nuclear analysis specifically identifies industrial growth, data centers, transportation and building electrification as drivers of demand and notes the need for carbon-free generation capable of serving 24/7 loads.

2. Preserve and buy into nuclear before trying to build your own

If your utility is in a region with existing nuclear plants, long-term nuclear PPAs, contracts for differences, minority ownership, or participation in uprates/extensions would be among my first calls.

Existing nuclear is an unusually valuable clean-firm resource because the plant is already built.

For new nuclear, I'd be more cautious. A county utility probably shouldn't be the sole entity taking first-of-a-kind construction risk.

Instead, consider:

• joining a multi-utility consortium;
• signing an offtake agreement;
• taking a minority ownership position;
• participating in a standardized Gen III+ project;
• evaluating SMRs only after there is a credible reference project and cost/schedule history.

DOE's current nuclear analysis explicitly identifies nuclear as a clean-firm complement to renewables, but also highlights construction cost, schedule, supply-chain and deployment risks.

The key is to buy nuclear risk at the portfolio level rather than betting the county's balance sheet on one reactor.

3. Hunt aggressively for geothermal

If your county/region has viable geothermal resources, this deserves serious attention.

Geothermal has a fundamentally different value proposition from solar:

solar: enormous cheap energy, but intermittent geothermal: comparatively small resource base, but potentially continuous generation

EIA identifies geothermal among the renewable technologies with the highest capacity factors because the underlying resource is relatively constant.

Enhanced geothermal systems are particularly interesting for places without conventional high-quality geothermal reservoirs. I would treat them as a commercialization bet, however—not assume that a 2030s resource will perform like an existing conventional geothermal plant.

4. Build lots of renewables—but procure them as a firming system

I wouldn't frame solar and wind as competitors to baseload.

I'd procure something closer to:

solar + storage + wind + transmission + demand response

rather than standalone intermittent generation.

For example, a hypothetical 2036 portfolio might look like:

• 300 MW solar
• 200 MW wind
• 100 MW geothermal/nuclear/hydro participation
• 150 MW / 1,200 MWh long-duration storage
• substantial transmission imports
• 75 MW flexible demand
• residual emergency generation

The exact numbers would come from the hourly reliability model.

This approach takes advantage of the fact that storage doesn't have to generate electricity continuously—it shifts electricity from times of abundance to times of scarcity.

DOE's Long Duration Storage program specifically targets technologies capable of providing 10+ hours of storage and seeks major cost reductions by 2030.

5. Treat 8–12-hour batteries as a reliability resource, not merely a solar accessory

This is one area where I'd move relatively quickly.

A 4-hour battery is excellent for shifting solar into the evening. But if your question is “What happens during a prolonged renewable shortfall?”, you need longer-duration resources.

I'd procure a staged portfolio:

2026–29: 4-hour lithium-ion + some 8-hour projects

2029–32: 8–12+ hour systems, including technologies other than lithium-ion where economics justify them

2032–36: Scale whichever technologies demonstrate acceptable cost, availability, degradation and cycling performance.

California's experience is already moving in this direction: in June 2026 the CPUC highlighted completion of an eight-hour battery project developed through its integrated-resource-planning process.

6. Don't underestimate transmission

For a county utility, transmission may be the cheapest clean firm resource you can buy.

A geographically diverse portfolio is dramatically more reliable than generation concentrated in the county.

You could, for example, contract for:

• wind from a windy region;
• solar from a high-insolation region;
• hydro from a water-rich region;
• nuclear from an existing nuclear site;

and use firm transmission/import rights to bring that energy home.

That creates geographic diversification against local weather.

I'd therefore treat a transmission upgrade as part of the generation portfolio rather than as an unrelated infrastructure project.

7. Make demand itself part of your firm capacity

This is probably the most underused option by public utilities.

Suppose your projected peak is 800 MW but you can reliably reduce 100 MW for several hours during extreme events.

You effectively don't need to build 100 MW of generation.

Potential resources include:

• managed EV charging;
• commercial HVAC;
• water/wastewater pumping;
• municipal buildings;
• industrial interruptible load;
• thermal storage;
• residential batteries;
• smart water heaters;
• building pre-heating/pre-cooling.

A county utility has a particularly useful advantage here: it can coordinate electricity, buildings, transportation, water and other public infrastructure instead of treating them as separate systems.

8. Keep a reliability backstop

I would not recommend retiring every dispatchable thermal resource immediately.

Instead, establish a declining role:

2026–30: Use existing gas/other dispatchable generation for reliability while clean resources are built.

2030–33: Reduce annual utilization substantially as storage, transmission and clean firm generation arrive.

2033–36: Retain only the capacity justified by extreme-weather reliability modeling, ideally transitioning toward low-carbon fuels or carbon-management options where technically/economically credible.

This is different from building a new fleet of gas plants that then becomes economically and politically difficult to retire.

A useful target portfolio

For a county utility starting from scratch, I'd investigate something roughly like this—not as a prescription, but as a planning benchmark:

By 2030

• 20–30% clean firm generation/contracted firm imports
• 40–50% wind + solar
• 10–20% batteries/storage
• 10%+ hydro, demand response and other flexible resources
• existing dispatchable capacity retained for reliability

By 2036

• 30–40% nuclear/geothermal/hydro/other genuinely firm clean resources
• 35–50% wind + solar
• 10–20% long-duration + conventional batteries
• 5–10% demand-side flexibility
• minimal fossil generation, primarily emergency/reserve

The percentages should ultimately be determined by your local load shape and transmission situation rather than a national template.

The procurement strategy I'd use

Rather than issuing one giant RFP, I'd run five parallel procurement tracks:

1. Clean firm: nuclear, geothermal, hydro and firm imports.
2. Clean energy: wind and solar PPAs.
3. Storage: 4-hour, 8-hour and 12+ hour resources.
4. Transmission: long-term firm import capability and upgrades.
5. Flexibility: demand response, managed EVs, thermal storage and distributed batteries.

Then evaluate everything against the same metric:

$/MW-year of dependable capacity + $/MWh of delivered energy + reliability contribution + carbon emissions + transmission cost + construction risk.

That prevents a cheap solar PPA from looking artificially attractive because its value is measured differently from a nuclear or geothermal contract.

The most important strategic choice

If I were advising the county board, my headline recommendation would be:

Don't try to find one clean replacement for a baseload plant. Build a diversified clean-firm system in which nuclear/geothermal/hydro provide the backbone, renewables provide inexpensive energy, storage shifts and firms that energy, transmission diversifies weather risk, and flexible demand reduces the amount of generation you have to build. DOE itself now frames advanced nuclear in essentially this complementary role: clean firm generation alongside substantial renewable deployment, rather than nuclear instead of renewables.

And for a county utility, I would put contracting/ownership structures and risk allocation almost as high on the agenda as technology. A 300-MW nuclear project with a 15-year construction risk profile can be a terrible public-utility investment even if nuclear is excellent technology; conversely, a well-structured minority investment in an existing reactor can be an exceptionally attractive clean-firm asset.

If you give me the county/state, current peak load, annual MWh, existing generation/PPAs, and expected 2035 load, I can turn this into a concrete 2026–2036 resource plan with MW targets, procurement sequence, indicative costs, and a comparison of nuclear vs. geothermal vs. storage vs. renewables.

By 2036

• 30–40% nuclear/geothermal/hydro/other genuinely firm clean resources
• 35–50% wind + solar
• 10–20% long-duration + conventional batteries
• 5–10% demand-side flexibility
• minimal fossil generation, primarily emergency/reserve

The percentages should ultimately be determined by your local load shape and transmission situation rather than a national template.

The procurement strategy I'd use

Rather than issuing one giant RFP, I'd run five parallel procurement tracks:

1. Clean firm: nuclear, geothermal, hydro and firm imports.
2. Clean energy: wind and solar PPAs.
3. Storage: 4-hour, 8-hour and 12+ hour resources.
4. Transmission: long-term firm import capability and upgrades.
5. Flexibility: demand response, managed EVs, thermal storage and distributed batteries.

Then evaluate everything against the same metric:

$/MW-year of dependable capacity + $/MWh of delivered energy + reliability contribution + carbon emissions + transmission cost + construction risk.

That prevents a cheap solar PPA from looking artificially attractive because its value is measured differently from a nuclear or geothermal contract.

The most important strategic choice

If I were advising the county board, my headline recommendation would be:

Don't try to find one clean replacement for a baseload plant. Build a diversified clean-firm system in which nuclear/geothermal/hydro provide the backbone, renewables provide inexpensive energy, storage shifts and firms that energy, transmission diversifies weather risk, and flexible demand reduces the amount of generation you have to build. DOE itself now frames advanced nuclear in essentially this complementary role: clean firm generation alongside substantial renewable deployment, rather than nuclear instead of renewables.

Adding reliable, clean baseload power over the next decade as a county utility requires navigating a complex landscape of rising power demands, grid reliability mandates, and decarbonization goals . Because baseload power must run continuously (24/7/365) regardless of weather conditions, your strategy needs a mix of proven generation assets, storage, and demand-side management.

• Advanced Nuclear (Small Modular Reactors - SMRs) offer a zero-emission, compact baseload option. While regulatory and deployment timelines stretch, the first commercial SMRs are targeting operation within this decade, making early site evaluation and partnership via programs like those tracked by the Department of Energy a viable long-term play.
• Enhanced Geothermal Systems (EGS) provide continuous, weather-independent clean energy outside of traditional volcanic regions. Advances in fracking and drilling techniques from the oil and gas sector have made EGS scalable; you can explore resources and data via the Geothermal Rising association.
• Clean Hydrogen / Co-firing provides a pathway for existing or new high-efficiency combined-cycle natural gas turbines (CCGTs). Utilizing natural gas bridged with a transition to green hydrogen (or equipped with carbon capture and sequestration - CCS) allows for dispatchable, low-carbon generation.
• Biomass and Biogas (Landfill Gas / Anaerobic Digestion) capture methane or utilize sustainable wood waste to fuel traditional turbine generators. This delivers true local baseload power while simultaneously abating high-global-warming-potential fugitive emissions.
• Long-Duration Energy Storage (LDES) paired with renewables (wind and solar) acts as synthetic baseload. Technologies like iron-air, flow batteries, or pumped storage hydro can bridge multi-day generation lulls. You can review technology readiness via the Long Duration Energy Storage Council.
• Regional Interconnections and Power Pooling cooperation allows smaller county utilities to contract clean baseload shares from larger regional transmission organizations (RTOs) or joint action agencies, spreading capital risk and transmission costs.

To help narrow down the best path for your specific county, could you tell me:

• What is your current peak load and generation mix?
• Are you part of a Joint Action Agency or a larger RTO/ISO?
• What are your state's mandated clean energy deadlines?

Yes. For a county utility, I would not treat “baseload” as synonymous with one technology. The objective should be clean firm capacity: electricity that can be counted on during a multi-day winter cold snap, summer heat wave, low-wind period, or transmission constraint.

The strongest strategy for the next decade is a portfolio with three layers:

DOE explicitly identifies nuclear, geothermal, low-impact hydro and zero-carbon fuels as firm resources that can complement variable renewables.

1. First, quantify the problem as a reliability requirement

Don't start with “How many MW of baseload should we build?”

Start with:

How many MW of clean firm capacity do we need in 2030, 2035 and 2040 under severe-weather scenarios?

Model at least:

• Peak winter and summer load
• Electrification and large industrial/data-center loads
• Multi-day low-wind/low-solar events
• Generator outages
• Transmission constraints
• Fuel-price scenarios
• Extreme weather
• 90/95/99%+ resource-adequacy targets
• Hourly production for the entire portfolio

This is increasingly important because electricity-demand forecasts have been rising sharply, driven by data centers, manufacturing and electrification.

2. Lock in some existing clean firm power now

For a county utility, buying rather than building can be extremely attractive.

Look for:

• Long-term PPAs from existing nuclear plants
• Shares of existing hydro projects
• Firmed renewable PPAs
• Regional capacity contracts
• Participation in new nuclear projects
• Joint ownership with neighboring public utilities

This gives you dependable capacity while larger projects are being developed.

There is a useful real-world precedent: Grant County PUD's current resource planning combines existing hydro, new solar/storage, wholesale purchases and PPAs while investigating geothermal, pumped storage and SMRs for longer-term needs.

3. Put nuclear on the 10-year critical path—but manage the risk

If your jurisdiction can participate in nuclear development, I would start that process now, even if the plant doesn't arrive until the latter half of the decade or later.

There are two distinct approaches:

A. Buy into an existing/new large nuclear project

Potentially the more bankable approach if you can secure a long-term allocation.

B. Advanced nuclear / SMR

Potentially attractive for a county utility because of smaller increments, siting flexibility and potential use of existing power infrastructure.

But don't assume SMRs will be a guaranteed 2032 resource. Regional planners are still treating advanced nuclear as an emerging technology with uncertain commercial timelines; the Northwest Power and Conservation Council's current planning, for example, uses an SMR-based “clean baseload” proxy but assumes a much later commercial availability date.

New York is particularly interesting right now: NYSERDA's June 2026 policy paper is explicitly examining financing, risk allocation, technology selection and procurement mechanisms for advanced nuclear, and the state's energy planning anticipates a significant role for new nuclear.

4. Investigate geothermal much harder than most utilities do

This is probably the most underappreciated clean-firm option.

Traditional geothermal is geographically constrained, but enhanced geothermal systems could substantially expand the geography. DOE estimates at least 90 GW of potential geothermal capacity by 2050, including states east of the Mississippi where conventional geothermal hasn't historically been available.

For a county utility, I'd commission a geothermal screening study now:

1. Map subsurface temperatures.
2. Identify existing oil/gas wells and drilling expertise.
3. Screen abandoned wells and brownfield sites.
4. Determine transmission interconnection possibilities.
5. Evaluate conventional and enhanced geothermal separately.
6. Seek a developer willing to fund exploratory drilling.

If you can get a credible 50–200 MW geothermal project in your territory, that's an unusually valuable resource because it produces electricity around the clock rather than requiring renewable generation to be stored.

5. Build renewables—but design them around firm capacity

Solar and wind shouldn't be dismissed because they're not baseload.

They're extremely useful because they provide cheap energy, while clean-firm resources provide adequacy.

Think of the system as:

Solar + wind = energy
Nuclear + geothermal + hydro = firm generation
Batteries + long-duration storage = flexibility
Demand response = avoided capacity

Storage already provides grid balancing and reliability services, and long-duration technologies can shift energy over substantially longer periods.

California's 2026 planning is a useful example: its regulators are simultaneously procuring clean generation and storage while planning transmission upgrades rather than treating any single technology as the answer.

6. Don't underestimate 8–100-hour storage

Four-hour lithium batteries are excellent for daily peaks. They are not the same thing as surviving a week-long renewable drought.

I'd procure progressively:

• 2–4 hour batteries for daily peak shifting
• 8–12 hour systems
• Demonstrations of 24–100+ hour storage
• Pumped hydro where geography permits
• Other emerging long-duration technologies

Eight-hour storage is already moving beyond the demonstration stage: California commissioned its first 8-hour battery project under its integrated-resource-planning process in June 2026.

But I'd be careful about making an unproven storage technology the backbone of your reliability plan. Treat emerging LDES as an option portfolio until it has demonstrated availability at scale.

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What I would actually do

For a county utility planning 2026–2036, I'd establish a target such as:

By 2036, procure enough clean firm resources to cover the county's modeled extreme-weather capacity requirement, while obtaining the majority of annual energy from the lowest-cost clean resources.

Then pursue roughly this sequence:

2026–28

• Aggressive efficiency/demand-response program
• 2–4 hour battery procurement
• Solar/wind PPAs
• Existing nuclear/hydro PPAs
• Geothermal resource assessment
• Nuclear/SMR feasibility and site screening
• Transmission/interconnection studies

2028–31

• Add 8–12 hour storage
• Contract for additional firm nuclear/hydro
• Select geothermal development partner
• Make investment decision on nuclear project
• Begin permitting for major clean-firm project

2031–36

• Bring geothermal and/or nuclear online
• Expand long-duration storage
• Continue renewable additions
• Retire or minimize dependence on fossil generation as clean-firm capacity becomes available

The key financial principle

Don't ask which technology has the lowest $/MWh.

Ask:

What is the least-cost portfolio that delivers electricity during the 100 worst hours—and especially the worst 10, 20 and 100-hour events—while meeting our emissions requirements?

A 24/7 nuclear or geothermal MWh may cost more than a solar MWh, but comparing them directly can be misleading because they perform different system functions. DOE's current advanced-nuclear analysis makes essentially this point: nuclear is most appropriately compared with other clean firm resources, including geothermal, hydro, renewables paired with long-duration storage, and potentially fossil generation with carbon capture.

If you're a county utility in New York specifically, I'd put existing nuclear purchases + advanced nuclear participation + geothermal screening + 8–12-hour storage at the top of the agenda. New York is currently developing policy mechanisms specifically intended to make new nuclear projects financeable, so the timing is unusually relevant.

If you give me the county, current peak load (MW), annual load (GWh), existing generation/PPAs, and expected 2035 load, I can turn this into a 10-year clean-firm resource portfolio with approximate MW requirements, sequencing, risks, and procurement strategy.

• Nuclear (SMRs) : Small Modular Reactors offer zero-emission baseload power with a smaller footprint and modular scaling suited for county-scale demand, though licensing and initial capital costs remain high.
• Geothermal (Enhanced/EGS) : Advanced Enhanced Geothermal Systems can harness heat virtually anywhere, providing steady 24/7 power independent of weather conditions, moving beyond traditional hydrothermal sites.
• Natural Gas with CCS : Pairing high-efficiency combined-cycle gas turbines with Carbon Capture and Sequestration provides dispatchable baseload while drastically lowering net greenhouse gas emissions.
• Long-Duration Energy Storage (LDES) : Pairing oversized regional solar and wind with iron-flow, compressed air, or pumped storage systems allows intermittent renewables to reliably mimic baseload profiles over multi-day periods.
• Biomass and Biogas : Capturing methane from local municipal solid waste landfills, wastewater treatment plants, or agricultural waste provides local, dispatchable generation while reducing fugitive emissions.

To help tailor this strategy, could you share:

• Your county's current peak load and baseline demand?
• Existing local natural resources (e.g., agricultural waste, geothermal potential, proximity to existing pipelines or nuclear plants)?
• Your state's clean energy mandates or deadlines for the next decade?

Yes. For a county utility in North Carolina, I would not bet the next decade on a single “baseload” technology. I’d build a portfolio around existing nuclear + new clean firm capacity + storage + efficiency, with advanced nuclear/geothermal as options rather than assumptions.

The key distinction is that you want firm, dispatchable, low-carbon power, not necessarily a traditional baseload plant running flat-out 24/7. DOE’s recent analysis defines clean firm resources to include nuclear, hydro, geothermal, and variable renewables paired with long-duration storage.

My preferred 10-year strategy

1. First, lock in nuclear power rather than trying to build a reactor yourselves

For a county utility, contracting for existing nuclear output is probably the lowest-risk way to add clean firm power.

Duke's nuclear fleet achieved a 96.9% capacity factor in 2025, and nuclear supplied roughly 18% of U.S. utility-scale generation.

Depending on your wholesale arrangements, I'd investigate:

• long-term nuclear energy/capacity PPAs;
• partial ownership of an existing nuclear unit;
• long-term contracts for nuclear uprates;
• participation in a future SMR project rather than developing one independently.

That last distinction is important. A county should be a customer/partner in a nuclear project, not necessarily the developer.

2. Make 2026–2030 about buying time

The most valuable resource over the next four years is probably not a new baseload plant. It's getting enough firm capacity in place while longer-lead projects develop.

I'd aggressively pursue:

Solar + batteries + demand response + existing nuclear contracts.

Solar by itself isn't baseload. But solar paired with substantial storage can provide a predictable evening peak resource, while nuclear provides the underlying energy.

The scale of this market is already enormous: EIA expects 86 GW of U.S. utility-scale capacity additions in 2026, including 43.4 GW solar and 24 GW batteries.

And North Carolina's current regulatory direction is already moving this way: the NCUC-approved Carbon Plan includes 3,460 MW of controllable solar and 1,100 MW of battery storage targeted for service by 2031.

3. Treat SMRs as a 2032–2036 option, not your 2028 reliability solution

This is where I would put serious county-level effort.

North Carolina is unusually well positioned because Duke is already pursuing SMR development. Its current plan evaluates an SMR at Belews Creek and a large reactor option at W.S. Lee, with potential new nuclear generation around 2037.

The state's regulatory work has previously contemplated roughly 300 MW SMRs entering service in 2034–35.

For your utility, I'd therefore seek an option on future nuclear capacity, rather than committing today's ratepayers to a technology whose schedule and cost are still uncertain.

Something like:

"We will contract for 50–200 MW of future clean firm capacity from an advanced nuclear project if it meets predefined cost, licensing, construction and reliability milestones."

That gives you upside without making the entire resource plan depend on SMRs arriving on schedule.

4. Don't overlook geothermal—but test it locally before counting it

Geothermal is particularly attractive because it is genuinely continuous, weather-independent generation. EIA describes geothermal generation as carbon-free, renewable and capable of continuous output.

But conventional geothermal resources are geographically constrained. Enhanced geothermal systems (EGS) are potentially much more interesting for a broader set of locations, but they're still an emerging technology.

So I'd spend a relatively small amount—say $1–5 million on feasibility/resource characterization and partnerships, rather than underwriting a huge project.

If the geology works, geothermal could become one of your best 2030s resources.

5. Build storage as a reliability resource, not merely a solar accessory

I'd procure storage in layers:

• 2–4 hour batteries for daily peaks and ancillary services;
• 8–12+ hour storage for extended renewable shortfalls;
• eventually multi-day storage where economics justify it.

The objective isn't "100% renewable electricity every hour."

It's:

solar/wind → storage → nuclear/geothermal/hydro → demand response → emergency reserves

with enough diversity that a cloudy, windless winter day doesn't become a crisis.

DOE's own clean-firm analysis emphasizes that batteries and demand response are valuable but do not eliminate the need for clean firm resources.

6. Make demand reduction part of your generation portfolio

For a county utility, this can be extraordinarily valuable.

A MW you don't need during the system's worst hour is economically similar to a MW of generation—without building a power plant.

I'd create programs for:

• managed water-heater loads;
• commercial HVAC;
• industrial interruptible loads;
• EV charging management;
• municipal buildings;
• water/wastewater pumping;
• thermal storage;
• behind-the-meter batteries;
• time-of-use rates.

Your water utility itself can become a grid resource. Pumping reservoirs during low-cost/low-demand periods and reducing pumping during system peaks can provide capacity without reducing service reliability, provided hydraulic constraints are respected.

7. Keep an eye on the actual North Carolina planning environment

This is especially important if you're a municipal/public-power utility rather than an investor-owned utility.

North Carolina's Public Staff explicitly evaluates resource adequacy, generation alternatives, solar/storage assumptions, transmission and utility-owned generation through the state's IRP process.

And public-power entities are actively looking for long-term resources. For example, NC Municipal Power Agency 1 issued a 2026 RFP seeking long-term capacity and energy, including partial requirements, block power and ownership/offtake structures from new and existing resources.

So I'd investigate whether your utility can aggregate procurement with neighboring public-power utilities. That can radically improve your negotiating position for nuclear, geothermal, storage and other firm resources.

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What I'd actually do if I were running the utility

I'd establish a 10-year clean-firm procurement target, rather than a generic renewable-energy target.

For example, suppose you need another 200 MW of dependable capacity by 2035. I might initially target something like:

• 60–80 MW equivalent: existing/new nuclear contracts
• 40–60 MW: solar + batteries
• 20–40 MW: long-duration storage
• 20–40 MW: demand response/efficiency
• 30–60 MW: future SMR/geothermal/hydro option
• remaining requirement: regional market purchases/reserves

The exact numbers should come from an hourly production-cost and resource-adequacy model—not from these illustrative percentages.

The important thing is the portfolio structure.

The strategic principle

I'd use three procurement horizons:

2026–2029 — Certainty

Nuclear contracts + solar/storage + efficiency/DR + transmission/grid improvements.

2029–2032 — Optionality

Long-duration storage + geothermal pilots + position for an SMR/nuclear project.

2032–2036 — Clean firm buildout

Exercise the best nuclear/geothermal/storage options based on actual costs and construction performance.

That approach also fits the direction North Carolina is already taking: the state's clean-energy plan emphasizes reliability, affordability, grid modernization and a diversified resource portfolio rather than reliance on one technology.

If your goal is truly "reliable clean baseload," I'd rank the technologies today:

1. Existing nuclear contracts → best near-term answer
2. New nuclear/SMRs → best potential 2030s clean-firm addition
3. Solar + storage → best scalable near-term complement
4. Long-duration storage → increasingly important reliability layer
5. Geothermal → potentially excellent, but site-dependent
6. Hydro/pumped storage → excellent where physically available
7. Gas → reliability insurance, but not a clean-baseload solution

The biggest mistake would be spending the next five years waiting for an SMR while your load grows. Buy firm clean power now, build flexible resources immediately, and preserve a credible path to owning/contracting for new nuclear in the 2030s.

Adding reliable, clean baseload power over the next decade as a county utility requires balancing decarbonization mandates with grid stability and cost-effectiveness . Because traditional baseload (like coal or aging gas) is retiring or facing stringent emissions caps, county utilities must look toward a diversified, firm, and low-carbon portfolio.

Here is a strategic roadmap to guide your utility over the next ten years:

1. Evaluate Modern Nuclear (Small Modular Reactors)

• SMR Technology: Investigate utility-scale or micro-SMRs (Small Modular Reactors) providing outputs typically ranging from 50 MW to 300 MW per module. They offer true zero-emission baseload power with smaller footprints and phased capital deployment.
• Partnerships: Partner with regional or state power authorities and private developers to share regulatory and financial risks of early-adopter nuclear technologies.

1. Optimize Existing Assets and Infrastructure

• Hydroelectric Upgrades: If your county has existing hydro assets, invest in modernizing turbines and generators. Uprating can increase capacity factor and output without building new dams.
• Biomass / Biogas: Utilize local organic waste streams (e.g., wastewater treatment plants, agricultural waste, or landfill gas) to fuel combined heat and power (CHP) or dedicated biomass generation, providing a localized, circular-economy baseload.

1. Leverage Clean-Fueled Combustion Turbines

• Hydrogen-Ready Turbines: Invest in natural gas combined-cycle (NGCC) plants that are engineered with a clear pathway to co-fire or transition completely to green hydrogen (H₂) or renewable natural gas (RNG) as supply chains mature over the decade.
• Carbon Capture and Storage (CCS): If keeping or building gas/biomass peakers/baseload, evaluate the feasibility of retrofitting CCS technology to capture emissions before they enter the atmosphere.

1. Deploy Hybrid Renewables with Long-Duration Energy Storage (LDES)

• Oversized Solar/Wind + LDES: Pair solar PV and wind assets with emerging long-duration storage technologies (such as iron-air batteries, flow batteries, or pumped storage) capable of discharging for 10 to 100+ hours to simulate baseload reliability.
• Geothermal Energy: Explore enhanced geothermal systems (EGS) if your regional geology permits. Next-gen geothermal provides constant, weather-independent clean power with a high capacity factor.

1. Strengthen Interconnections and Regional Markets

• Transmission Expansion: Invest in local transmission upgrades to tap into regional clean energy pools, balancing local deficits with neighboring surpluses.
• RTO/ISO Participation: If not already participating, integrate deeper into Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs) to leverage capacity markets for firm power reliability.

If you'd like to narrow this down, tell me:

• What is your utility's approximate peak load and service territory type (rural vs. suburban)?
• Are you subject to strict state carbon-reduction deadlines within the next 10 years?

I can help tailor a more specific technology mix and funding strategy for your county.

If by “reliable clean baseload” you mean power you can count on during heat waves, winter evenings, multi-day renewable shortfalls, and other stressed conditions, I would not try to replace gas plants with one technology. For a California county utility, the strongest strategy over 2026–2036 is a portfolio of firm generation + long-duration storage + abundant low-cost renewables + transmission, with contracts structured around reliability rather than annual MWh.

California’s current planning is moving in exactly this direction: the CPUC’s 2026 procurement decision requires 6,000 MW of additional clean-energy/storage capacity by 2030–32, with at least 25% coming from clean firm power and/or ≥8-hour storage.

What I would build

1. Make geothermal the centerpiece of actual clean baseload

For a utility that genuinely wants 24/7 generation, geothermal is probably the most attractive new-build resource to investigate first.

It is not weather-dependent, has a small land footprint relative to solar/wind, and can provide high capacity factors. California's current IRP work is explicitly increasing attention to enhanced geothermal systems and estimates new EGS resource potential.

I would issue an RFI now for:

• conventional geothermal PPAs;
• enhanced geothermal systems (EGS);
• geothermal projects with firm capacity guarantees;
• geothermal projects capable of following load;
• projects in California and neighboring western states.

The objective would be something like 10–20% of the utility's future dependable capacity from geothermal, rather than simply buying a percentage of annual energy.

2. Treat long-duration storage as a capacity resource, not just a battery

This is the other major piece.

A portfolio with, say, lots of solar and 4-hour batteries can look fantastic on an annual-energy basis while still being vulnerable to a two- or three-day renewable drought.

California's agencies are explicitly modeling 12-hour storage and geothermal as long-lead clean resources, and the CEC finds that LDES can cost-effectively support bulk-grid decarbonization.

I'd procure a mixture:

4-hour batteries → daily solar shifting and peak shaving
8–12-hour storage → overnight/multi-period reliability
24+ hour storage → extended renewable shortfalls

Technologies worth competing include pumped hydro, flow batteries, compressed-air energy storage, thermal storage and other emerging LDES technologies.

Don't prescribe the technology in the first solicitation. Prescribe the service:

“Deliver X MW continuously for Y hours under specified state-of-charge and recharge conditions.”

That lets the market compete.

3. Buy cheap renewables specifically to feed the firming fleet

The mistake would be thinking of solar/wind and baseload as competing resources.

They complement each other.

For example:

solar → midday surplus → long-duration storage → evening/night firm power

and

wind → nighttime/seasonal production → storage/load → firm capacity

California's current planning recognizes that the optimal clean portfolio includes substantial renewables, storage, geothermal and transmission rather than one technology.

So I'd deliberately overbuild renewable energy relative to instantaneous load, then monetize the surplus through storage, flexible loads and market sales.

4. Don't overlook nuclear—but don't make your 2030 plan depend on new nuclear

If your county can participate in an existing nuclear resource or obtain a long-term allocation from an existing/new project, nuclear is almost the definition of what you're asking for: zero-carbon, high-capacity-factor, dispatchable generation.

But I would distinguish:

Existing/advanced existing nuclear opportunity: pursue aggressively.

New large nuclear: potentially valuable, but difficult to make the backbone of a 10-year county procurement plan because of capital cost, permitting, construction and execution risk.

SMRs: maintain an option and perhaps participate in a demonstration/early project, but don't assume commercial SMR deployment will arrive on your preferred schedule.

In other words: buy proven firm capacity first; maintain an option on the next generation.

5. Think in terms of “firm MW,” not “clean MWh”

This is probably the most important change I'd make to a traditional utility procurement.

Suppose your county needs another 200 MW of dependable capacity.

Don't ask developers:

“Can you provide us 200 MW of renewable energy?”

Ask:

“How many MW can you guarantee during a specified 100-hour reliability event, at specified availability, regardless of weather?”

Then score proposals on:

• dependable MW;
• duration;
• forced-outage rate;
• ramp rate;
• minimum generation;
• fuel/resource availability;
• performance during extreme heat;
• transmission deliverability;
• black-start/islanding capability;
• 20–30 year cost;
• construction/permitting risk.

That will reveal the difference between energy that is clean and capacity that is actually dependable.

6. Build a layered portfolio

For illustration, if your county expects to need 500 MW of dependable clean capacity in the mid-2030s, I'd investigate something approximately like:

• 100 MW geothermal
• 100 MW nuclear/hydro/other firm clean contracts
• 150 MW long-duration storage
• 100 MW short-duration batteries
• 50 MW demand response/managed load

And separately procure considerably more than 500 MW of solar/wind energy to provide the fuel for the storage fleet and low-cost energy.

Those numbers aren't a recommendation without your load forecast—they illustrate the architecture.

7. Transmission may be as important as generation

A county can have a perfectly good PPA and still discover that its “firm” resource isn't firm at the county's bus.

California's current planning recognizes the need for major transmission expansion to bring new clean resources to load; the CPUC's 2025 portfolio was built around more than 60 GW of new clean generation/storage through 2035.

So I'd conduct a local deliverability study before signing major PPAs.

For a county utility, owning or contracting for transmission rights can sometimes be more valuable than owning another marginal generating project.

8. Use the next decade as three procurement waves

2026–2028 — lock in proven resources

• geothermal PPAs;
• solar + 4-hour batteries;
• hydro/nuclear firm contracts where available;
• demand-response programs;
• transmission/interconnection rights;
• one or more 8–12-hour LDES projects.

2029–2032 — build the firming layer

• additional geothermal/EGS;
• 12–24-hour storage;
• pumped hydro/other LDES;
• additional wind;
• larger managed-load programs;
• evaluate nuclear/SMR opportunities as they mature.

2033–2036 — optimize for the residual reliability problem

By then you should know whether your hardest problem is:

• summer evenings,
• winter mornings,
• multi-day renewable droughts,
• transmission congestion,
• or seasonal adequacy.

Then procure specifically for that problem rather than guessing today.

One California-specific opportunity

The state now has an Opt-In Certification Program for qualifying large clean-energy and storage projects, including geothermal and storage, with a consolidated permitting process and a target decision timeline of 270 days once an application is complete.

For a county, that creates an interesting strategy: become the anchor customer/partner that makes a large clean-firm project financeable, rather than trying to develop the entire project yourself.

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My bottom line

I would make the county's 2036 target something like:

“80–90% of annual electricity from zero-carbon resources, with enough contracted firm capacity and storage to maintain reliability through a multi-day renewable shortfall.”

And I'd build around three pillars:

Geothermal/nuclear/hydro = firm clean generation
Solar/wind = inexpensive energy
8–24+ hour storage = reliability bridge

That is considerably more robust than trying to find a single “clean baseload” technology.

California's own 2026 planning is increasingly converging on this architecture: clean firm resources and long-duration storage are being explicitly procured alongside renewables, rather than assuming batteries and solar alone solve reliability.

If you give me the county utility's current peak MW, annual MWh, expected 2035 peak, existing generation/contracts, and whether you're municipally owned or an LSE/CCA, I can turn this into a specific 2026–2036 resource portfolio with MW, estimated capital/PPA costs, reliability contribution, and an annual procurement schedule.

To add reliable clean baseload power over the next decade, county utilities must deploy a diversified mix of geothermal energy, advanced nuclear small modular reactors (SMRs), long-duration energy storage (LDES) paired with renewables, and clean hydrogen.

Because traditional "always-on" fossil plants are retiring, a modern baseload strategy relies on a combination of naturally constant clean resources and technology that mimics baseload traits.

1. Primary Clean Baseload Technologies

• Geothermal Energy : Provides a true 24/7 capacity factor often exceeding 90%. Recent advancements in Enhanced Geothermal Systems (EGS) allow counties to tap into deep heat even in regions without natural hot springs.
• Nuclear Small Modular Reactors (SMRs) : Offers a compact footprint and highly reliable output. SMRs are ideal for county utilities due to lower upfront capital costs compared to traditional large-scale nuclear plants and their ability to scale up in 50MW to 300MW increments.
• Biomass and Waste-to-Energy : Utilizes local agricultural waste or municipal solid waste. This solves landfill constraints while producing steady, controllable electricity, though emissions tracking is required.

2. Synthesized Baseload (Firming Up Renewables)

If your county lacks geothermal or nuclear capabilities, you can synthesize clean baseload power by pairing intermittent generation with modern grid infrastructure:

• Long-Duration Energy Storage (LDES) : Deploy iron-air, flow, or pumped-hydro storage capable of discharging power for 10 to 100+ hours to bridge multi-day weather lulls.
• Overbuilding Renewables + Curtailment : Pair wind and solar installations across geographically diverse areas with regional transmission lines to guarantee a high minimum baseline of power.
• Clean Hydrogen Fuel Cells : Store excess daytime solar power as green hydrogen, then run it through fuel cells or converted combustion turbines during peak demand or extended dark periods.

3. Step-by-Step 10-Year Deployment Roadmap

To achieve operational status within the next decade, your utility should follow a structured timeline due to long permitting and construction cycles:

[Years 1-3] Resource Assessment, Feasibility Studies, and Site Selection
     │
[Years 3-5] Permitting, Environmental Impact Reports (EIR), and Interconnection Filings
     │
[Years 4-6] PPA Negotiations, Securing Federal Grants, and Financing
     │
[Years 6-10] Procurement, Facility Construction, Grid Integration, and Commissioning

1. Phase 1: Resource & Grid Mapping (Years 1–2) : Evaluate your county's specific geography for geothermal viability, deep well capabilities, or available land near existing transmission infrastructure.
2. Phase 2: Permitting & Community Engagement (Years 3–5) : Initiate early environmental reviews and public comment periods, especially for nuclear SMR or biomass projects, to secure local alignment.
3. Phase 3: Secure Funding & Financing (Years 4–6) : Leverage federal infrastructure grants, clean energy tax credits, or green bonds to offset high initial capital expenditures.
4. Phase 4: Construction & Interconnection (Years 6–10) : Execute engineering procurement, build out local substation upgrades, and bring the asset online to meet your mid-2030s targets.

To help narrow down the best path forward, could you share a bit more about your county's geographic region, existing generation assets , or approximate target capacity (MW)?