Hawaii’s LNG Detour: Why A Fossil Bridge Arriving In The 2030s Makes No Sense

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Hawaii is re-evaluating its electricity system again and LNG is back on the table as a proposed bridge between oil dependence and a renewable future. The idea is simple at first glance. Hawaii burns more oil for electricity than any other state and Oahu still relies on oil for most of its generation. LNG is cleaner than residual fuel oil at the smokestack and often cheaper per kWh after modern gas turbines extract more energy from the same heat. The argument is that a temporary shift to LNG creates breathing room while the islands continue to build wind, solar, and batteries. The appeal is easy to understand. A familiar thermal solution promises reliability and a measurable reduction in local air pollution. The problem is that the framing leaves out the full system picture and the lifecycle emissions I have been assessing for LNG supply chains for years.

Hawaii’s current electricity landscape makes the pressure to choose something immediate understandable. Most of Oahu’s electricity still comes from low sulfur fuel oil and diesel. Statewide consumption sits around 10 TWh a year, with Oahu dominating demand. Maui and Hawaii Island have higher renewable shares, but they also have lower total loads. Power prices remain the highest in the United States. Solar on rooftops is significant and increasingly central to daytime demand, but there is still a large thermal backbone under those panels. When the last coal plant closed, the gap was filled entirely with oil generation. The state’s legal requirement for 100% renewable electricity by 2045 means every new fossil asset must retire early or convert to something cleaner before it has delivered a full economic life.

Proponents of LNG tend to argue that oil dependence is too expensive, too polluting, and too volatile to maintain. They worry that relying heavily on solar and batteries before the system is fully reshaped risks reliability issues. They point out that residual fuel oil produces sulfur dioxide, particulates and heavy metals at levels that matter for public health. They argue that oil-fired generation is inflexible and that LNG in combined cycle turbines could reduce emissions while keeping firm capacity online. There is truth in all of this. Residual fuel oil is a dirty and expensive fuel. Meeting peak demand with existing oil plants is difficult. The utility does need dispatchable capacity to cover evening ramps and contingencies. These concerns justify a careful assessment of LNG, not a dismissal.

The infrastructure required for LNG in Hawaii is significant. The concept usually centers on a floating storage and regasification unit moored off Oahu, a set of pipelines to shore, and a new gas plant near the old Barbers Point coal site. Existing oil plants would be converted to dual fuel. The total capital cost of all associated facilities is often estimated at more than $1 billion. LNG creates new fixed charges that ratepayers fund regardless of how much the resource is used. Any LNG system built in the 2020s must recover its costs before 2045 or find a way to run on low carbon fuels that are still expensive and scarce. LNG promises lower fuel costs, but comes packaged with new debt and a new fossil interface that competes directly with renewables for dispatch.

Lifecycle greenhouse gas emissions are central to this debate. I have assessed LNG production and export chains in the United States for several years. The picture is rarely what the glossy brochures present. Methane leakage from upstream fields, gathering systems, compressors, and pipelines changes the climate math. Liquefaction requires large amounts of electricity and natural gas. Shipping LNG 3,000 miles across oceans is energy intensive. Regasification adds more losses. Combustion at the plant ends the chain, but everything before the plant stacks up behind the CO₂ coming out of the stack. For US LNG export facilities feeding Asian or Pacific markets, the full lifecycle emissions often reach levels close to heavy fuel oil when methane leakage is high. In the best cases, lifecycle LNG is cleaner than oil, but the difference is narrower than many assume when upstream emissions come from basins with known leakage problems.

Hawaii’s potential LNG sources would include British Columbia and the US mainland. BC’s upstream methane performance is better than some US basins, but the liquefaction plants there still impose an energy penalty that shows up in lifecycle emissions. With US LNG exports, the upstream methane issue is likely larger. Data from independent satellite surveys and academic work on the Permian and other basins demonstrates that leakage is not well controlled. When methane leaks, the climate impact grows fast. LNG might deliver a 20% to 40% lifecycle reduction compared to residual fuel oil in a best case supply chain. It might deliver much less in a realistic case. The gap depends on upstream practice and not on anything Hawaii controls.

Local air pollution is one area where LNG delivers clear and measurable improvements. Residual fuel oil produces sulfur dioxide at levels that no modern grid should accept. It also produces particulates and metals that create real health impacts. Natural gas contains very little sulfur and burns more completely. Switching a significant share of Oahu’s generation from oil to gas would cut sulfur dioxide by orders of magnitude. It would reduce particulates and eliminate heavy metal pollution related to fuel chemistry. The health benefit is real. The same benefit also appears when oil generation is displaced by wind, solar, and battery storage, because clean generation does not produce any stack emissions at all. The local pollution case for LNG is about replacing an old fossil fuel with a cleaner one. The renewable case is about replacing combustion entirely.

Nitrogen oxides from gas plants deserve as much attention as the more visible sulfur and particulate emissions from oil. Gas combustion produces NOx through high temperature reactions in the turbine, and while levels are far lower than those from oil or diesel units, they are not zero. NOx is a precursor to ground level ozone, which means gas generation still contributes to local smog formation when the atmosphere is warm and stagnant. In my assessment of Duke Energy’s gas fleet, the data showed that NOx emissions from combined cycle plants were materially lower than from coal, but remained a nontrivial contributor to regional ozone alerts. The same chemistry would apply in Hawaii. Replacing oil with gas would reduce local NOx, but it would not eliminate it, and any future LNG system on Oahu would lock in a source of smog-forming emissions that wind, solar, and batteries would avoid entirely.

An important part of the system picture is how dispatch decisions interact with new fossil assets. When a utility builds a new thermal plant, it has a strong financial incentive to run it at higher capacity factors. Regulators end up negotiating capacity payments and fixed cost recovery mechanisms to ensure the utility remains solvent. This dynamic often crowds out renewable energy that could have been built in the same period. Thermal plants create inertia in planning and scheduling. In Hawaii, this could restrain the buildout of solar, wind, and storage at exactly the moment when the state needs to accelerate construction. A new LNG system would be framed as a bridge today, but the financial logic behind it would try to extend its life well into the 2040s.

If I apply megaproject expert Professor Bent Flyvbjerg’s reference class forecasting to Hawaii’s LNG idea and compare it to actual timelines for LNG terminals elsewhere, the picture is much slower than current political talk suggests. European and Asian import terminals built around floating storage and regasification units often target 3- to 5-year construction windows from FID, but many have encountered delays from contractor disputes, supply chain constraints, or local opposition, which pushes real commissioning dates to the back end of that range or beyond.

None of that includes the front-end years required for permitting, impact assessment, public consultation, contract negotiations, and regulatory approval, which commonly add another 3 to 7 years before anyone takes FID. Hawaii today is still at the stage of studies, conceptual resource decks, and a framework agreement with JERA, with the Civil Beat reporting in October 2025 that any LNG project would have to navigate Public Utilities Commission proceedings and full environmental reviews, and local commentary like Ililani Media questioning how realistic LNG imports are under existing law. If you line Hawaii up beside the global reference class of LNG import infrastructure, a credible window from today to an operating LNG facility plus the required retrofits and gas pipelines is closer to 8 to 12 years than the 5 or fewer sometimes implied in public discussion, which means any LNG bridge would likely arrive in the mid to late 2030s rather than in time to influence decisions over the next few planning cycles.

If an LNG facility in Hawaii cannot come online until the mid to late 2030s, the basic economics of the project shift into uncomfortable territory. The state’s 100% renewable electricity mandate locks in 2045 as the end of large-scale fossil generation, which means a plant entering service around 2036 or 2037 would have only eight or nine years of full fossil operation before being forced into early retirement or expensive conversion to a low carbon fuel that does not yet have a viable supply chain on the islands. No thermal project of this scale pays itself off in under a decade without very high capacity factors and very high tariffs, and neither of those are politically durable in Hawaii’s regulatory environment. The result is a stranded-asset risk that is built in from the first engineering study. A project of this size normally expects a 30-year financial life, not a single-digit one. If the LNG system runs only a fraction of that period before being constrained by law or outcompeted by cheaper solar and storage, the remaining capital would be recovered either from ratepayers through accelerated depreciation or written off as a loss, both of which weaken the original argument that LNG lowers long run costs. The timing makes the bridge metaphor inaccurate because the bridge itself would not last long enough to justify the investment.

The last time LNG was on the table in Hawaii, the proposal collapsed under a combination of politics, timing and shifting expectations. The Hawaiian Electric Company’s (HECO) 2015–2016 LNG import plan was tied to the proposed merger with NextEra and depended on a streamlined regulatory path. When the merger fell apart, the LNG plan lost its strategic anchor. Governor Ige publicly opposed LNG on the grounds that it would stall the push toward local renewables. The Public Utilities Commission refused to accept the fast-track procedural approach HECO had hoped for. Without clear political support, and with the governor’s office calling LNG a distraction, HECO withdrew the application and the idea never made it past early filings and conceptual engineering. That episode established a pattern. LNG in Hawaii is viable only when the political leadership is willing to prioritize it over wind, solar, and storage, and the last time that choice was presented the state rejected LNG outright.

The politics today point in the same direction. Hawaii has built a durable consensus around renewable energy that cuts across factions inside the dominant Democratic party. The 100% Renewable Portfolio Standard law passed with broad support. The coal retirement went ahead without significant opposition. Solar and storage power purchase agreements (PPA) win approval because they cut costs and align with public expectations. There is no strong political constituency for gas on the islands. The current administration frames LNG as a temporary option rather than a strategic shift and is still sending signals that renewables remain the primary path. Opposition parties are not better positioned to champion LNG, and the electorate has not demanded a gas pivot. That political environment creates an unstable foundation for any project that needs more than a decade of predictable policy support to reach operation and payback.

Flyvbjerg would point to these conditions and see classic long-tail risks that gather strength as timelines stretch. A project that takes 8 to 12 years to reach operation must survive several election cycles, potential regulatory changes, evolving public expectations, and competition from falling cost renewables. In Hawaii, every one of those factors tilts toward more wind, solar, and storage and away from fossil import infrastructure. The longer the approval and development period, the greater the chance that political leadership tightens renewable requirements, that the PUC recalibrates system needs, or that the economics of solar and batteries improve to the point where LNG becomes harder to justify. Long duration exposes LNG to a wide range of risks that cannot be mitigated by engineering or contracting, and in a state with a strong renewable identity those risks compound. This is exactly the kind of vulnerability Flyvbjerg highlights: a megaproject that must assume a stable world for a long period while the world keeps changing in ways that undermine the project’s reason for existing.

A more aggressive wind, solar, and battery pathway is already well defined. PPAs for solar plus 4- or 8-hour storage on the islands have settled in the 8 to 12 cent per kWh range. These prices are already below the cost of oil generation. They are stable and predictable for decades. Kauai has already shown that these projects can displace oil and reduce customer bills. If Oahu were to accelerate procurement of similar projects while strengthening transmission, demand response and grid operations, it could retire most oil generation without building new fossil infrastructure. Batteries meet evening peaks. Demand response reduces the ramp. Longer duration storage options, including flow batteries and pumped storage, address extended cloudy periods. A renewables-first system is feasible with coordinated planning and steady procurement.

There is also an overlooked local resource that could supply firm capacity when needed without committing to LNG. Hawaii has waste biomass from agriculture, green waste, sewage treatment, and organic refuse. Anaerobic digestion of these materials can produce biomethane. The gas volumes would not match the continuous output of a large gas plant, but they could support peaker units and provide resilience during grid disturbances. Storing biomethane on Oahu would require tanks or caverns. A couple of years ago, I assessed the old WWII era fuel silos at Pearl Harbor as a potential pumped hydro battery, finding that option wasn’t particularly viable. They have now been decommissioned and de-fueled. These silos or similar structures could be repurposed for biomethane storage. Local biomethane would reduce reliance on imported fuels and avoid the lifecycle emissions of LNG. It would also use waste streams that already exist. I did a little napkin math and it looks like two of the 20 tanks, if converted to store biomethane, could provide 10 days of energy storage at Oahu’s peak power demand. Yes, the Red Hill fuel reserves are that big.

For those concerned about removing nutrients from the soil, biodigesters do not strip fields of what crops need to grow. When organic waste is digested for biomethane, the methane is removed but the nitrogen, phosphorus, and potassium remain in the digestate. These nutrients can be separated, stabilized, and spread back onto fields as a fertilizer that replaces synthetic inputs. The energy is extracted without exporting the fertility, so the agricultural cycle stays intact while the islands gain a local renewable fuel for peaker plants. Building industrial-scale biodigesters near the Pearl Harbor fuel tanks is likely a much less expensive, much more local, and much more circular option to provide key thermal firming to a renewables-heavy grid than building an LNG terminal that ties the islands to a volatile external energy market. This was a key wedge we included in 2050 energy modeling for the Netherlands when I assisted them this year with a pragmatic energy scenario for 2050 as part of TenneT’s Target Grid strategic planning process.

This is also an opportunity that has not been explored by Hawaii’s energy community in a unified way. Studies from HNEI and the Hawaii State Energy Office have assessed the potential for locally produced biomethane from landfills, wastewater plants, and agricultural residues, but they treat RNG as a fuel substitute rather than as a form of long duration energy storage for the grid. In parallel, the Navy, independent consultants and several analysts, including me at a request from a local, have examined the decommissioned Red Hill tanks as potential pumped hydro reservoirs, water storage assets or renewable integration sites, yet none of these assessments consider the tanks as a buffer for renewable gas. The ingredients exist but remain siloed. Hawaiian energy modelers, strategists, and policymakers may want to examine a merged concept where local biomethane provides peaking fuel and resilience while the Red Hill tanks or similar structures serve as secure storage. This would couple waste management with firm capacity and reduce the need to import fossil molecules, and it would give the islands a homegrown alternative to LNG that aligns with their long term renewable law.

The emissions outcome of the accelerated renewables path is very different from the LNG path. LNG reduces emissions by substituting one fossil fuel for another. Renewable energy reduces emissions by removing fossil fuel generation from the system entirely. If Hawaii were to push renewables hard, the power sector emissions could fall by 60% to 80% over time rather than the 20% to 30% reduction from LNG. Local air pollution would drop much further because combustion hours would fall sharply. Costs would likely fall more as well because solar plus storage PPAs remain cheaper than LNG once capital recovery is fully counted. The renewable path is aligned with the 2045 mandate. The LNG path is an expensive detour that must be abandoned early.

Hawaii’s strategic choice is between two stories about the next twenty years. One story says that oil dependence is difficult to manage, so LNG is a safer bridge toward a cleaner future. The other story says that building LNG infrastructure locks in a fossil pathway that conflicts with the state’s legal requirements and technical potential. When the full lifecycle emissions of LNG are placed next to residual fuel oil, the difference looks modest once methane leakage is accounted for. When local solar, wind, and storage prices are placed next to LNG cost forecasts, the renewable options look cheaper and lower risk. When local air quality needs are placed next to the renewable buildout, combustion-free generation delivers the best outcome. LNG still looks tempting because it feels familiar and it promises reliability. The deeper analysis shows that it solves fewer problems than it creates.

Hawaii has been a proving ground for energy transitions for decades. If it builds LNG now, it will demonstrate how hard it is to escape fossil lock-in even when the strategic objective is clear. If it accelerates renewables and leverages local biomethane for peakers, it will show islanded grids around the world that fossil bridges are not required. The choice is not only about fuels and prices. It is about what the islands want their energy system to look like in the decades ahead.