Landfill gas and bitcoin mining: what has to be true

Landfill gas forms when buried organic waste decomposes without oxygen. EPA's Landfill Methane Outreach Program (LMOP) describes it as roughly 50% methane and 50% carbon dioxide (EPA LMOP, page updated 1 September 2026). Chapter 1 of EPA's project development handbook gives 50 to 55% methane and 45 to 50% carbon dioxide (ch. 1, July 2021); a 2001 federal primer gives 45 to 60% methane (ATSDR).

Only the methane burns, so the measure that matters is energy, not volume. The handbook puts landfill gas at about 500 Btu per standard cubic foot (ch. 1). Every figure below uses a stated version of that: 1,012 Btu per cubic foot of methane at 50% methane, or 506 Btu per standard cubic foot, the constants in EPA's LFG Energy Benefits Calculator spreadsheet (December 2024). The same spreadsheet uses 1,050 Btu per cubic foot for natural gas. A rule of thumb or calculator set up for pipeline gas will roughly double what your gas can do unless you change the heating value.

A generator's heat rate is the fuel energy it needs per kilowatt-hour; its efficiency is 3,412 Btu divided by the heat rate (EIA). EPA's benefits calculator assumes 11,700 Btu per kWh, a weighted average for engines, gas turbines and boiler/steam turbines, or an efficiency of about 29%. The handbook puts engine efficiency at 30 to 40% (ch. 3, January 2024), so this is the cautious end.

Worked example, 500 scfm at 50% methane, in our arithmetic on EPA's constants:

1. Fuel: 500 scfm × 60 minutes × 506 Btu = 15,180,000 Btu per hour.
2. Generation: 15,180,000 ÷ 11,700 = 1,297 kW gross, about 1.3 MW.
3. A year: EPA's calculator applies a net capacity factor of 0.85 for availability, operating load and parasitic losses. 1,297 kW × 0.85 × 8,760 hours ≈ 9,660 MWh, about 1.1 MW on average.

That matches the handbook's own rule of thumb, which turns 300 cfm into about 0.78 MW (ch. 1), and sits close to its engine table, which pairs a 1.2 MW engine with 500 cfm (ch. 3). At 40% efficiency the same flow would support about 1.8 MW: a ceiling, not a plan.

The shortcut: each scfm of methane supports about 5.2 kW at this heat rate, so multiply measured flow by measured methane fraction first. At 45% methane the example falls to about 1,170 kW; at 60% it rises to about 1,560 kW.

As of September 2024, 488 municipal solid waste landfills supplied 542 energy projects in operation, and EPA estimated that 444 more "candidate" landfills could cost-effectively turn their methane into energy (LMOP database). A candidate is open or closed for five years or less, holds at least a million tons of waste and has no operating, under-construction or planned project, though a site that shows interest can also be designated (LMOP, page updated 1 September 2026), so most smaller and older sites are outside that count.

• The flare is how the landfill complies. Federal rules (40 CFR part 60, subparts XXX and Cf) require landfills with a design capacity of at least 2.5 million megagrams and 2.5 million cubic meters, and non-methane organic compound emissions of at least 34 megagrams a year, to collect and control their gas (40 CFR 60.762), by energy generation, treatment for sale, or flaring (ch. 5, July 2021). A flare meets the rule without a buyer, and energy projects keep one anyway, for gas the engines cannot take while starting up, while down, or beyond their capacity (ch. 1).
• The flow is too small, or falling. Engines have generally been used where the gas supports 800 kW to 3 MW, about 300 to 1,100 cfm at 50% methane, and pipeline-quality gas projects are most cost-effective from about 1,000 cfm. Smaller flows can run small engines or 30 to 250 kW microturbines, at $2,900 and $3,400 per kW of capital against $2,000 for engines above 800 kW, in 2020 dollars. At California's All Purpose Landfill, declining flows closed an engine project in the mid-1990s; a microturbine project (three 250 kW units) started there in late 2009 (ch. 3).
• The grid connection. The handbook calls interconnection potentially "the most important issue" in a project's feasibility (ch. 5), and notes that electricity projects can be marginal where power prices are low (ch. 3).
• Gas quality. Siloxanes burn to silicon dioxide that collects inside engines and can cut performance and raise maintenance costs, and removing them can be costly. Hydrogen sulfide is corrosive with moisture and more likely to need treatment where construction and demolition waste is accepted (ch. 3). Most engines need only dewatering, filtration and compression; some engines and many turbines also need siloxane and hydrogen sulfide removal (ch. 1).

The landfill example on our energy page shows a route that takes gas after your blower, treats it, burns it in engines sized to the gas, and feeds a mining load in containers beside them, with the flare down to a pilot and still available. If the engines and the load are kept separate from the landfill's utility service, nothing is exported and no export interconnection is needed. Any remaining tie to the utility, for the blower or for backup, is a design question.

A mining load is built from individual machines, so it can be sized to the gas you have and reduced as flows decline. That makes it a candidate for flows below the thresholds above, not a way to make those flows worth more.

What the load earns per MWh is its energy hashprice, explained in our note on energy hashprice. On 28 September 2026, Hashrate Index, published by Luxor Technology, reported $52/MWh for fleets of 25 to 38 J/TH, up to $138 for fleets under 14 J/TH, and $75 for 19 to 25 J/TH, at a hashprice of $39.87 per PH/s per day (Hashrate Index). On 8 June 2026 that band read $54/MWh, at a hashprice of $28.94 (Hashrate Index).

Applied to the example's 9,660 MWh, that one band is about $522,000 of gross revenue a year at June's reading and about $725,000 at September's: the same gas and machines, sixteen weeks apart. Both are before pool fees, cooling loads and every other cost, and neither is a forecast.

Then the cost of making the electricity. The handbook's typical figures for engines above 800 kW, basic gas treatment included, are $2,000 per kW of capital and $300 per kW a year of operation and maintenance, in 2020 dollars from LFGcost-Web version 3.5 (ch. 3), since replaced by version 3.6 (EPA). For about 1.3 MW that is roughly $2.6 million installed and $390,000 a year, or about $40 per net MWh before any capital is repaid. EPA's defaults are typical designs, not a quote, but the order of magnitude shows why who funds and owns the engines matters as much as the price; who carries which risk covers that.

1. Measured gas, not only modelled gas. Collection efficiency at landfills with comprehensive systems typically ranges from 50 to 95%, with 75% most commonly assumed (ch. 2, July 2021), so a metered record carries more weight than a model. Landfills that accepted waste on or after 1 January 1980 and generate methane equal to 25,000 tonnes of CO2e or more a year report under subpart HH of EPA's Greenhouse Gas Reporting Program (EPA, page updated 21 September 2026). Where a collection system exists, those reports include the gas collected, its average methane concentration, the destruction device and the hours the system ran normally (40 CFR 98.346(j)). That reporting may end: in September 2025 EPA proposed that subpart HH and 45 other source categories stop reporting after reporting year 2024 (EPA fact sheet), and as of 11 September 2026 the proposal had not been finalized (Congressional Research Service). A site's past filings are still a record of collected gas; whether new ones follow is not settled.
2. A collection system that stays up, tuned for methane. The handbook recommends more frequent wellfield monitoring for energy projects, to maximize methane flow rather than gas flow. A typical landfill tuned for 48 to 52% methane already draws in some air, with 10 to 15% balance gas, and pulling harder for volume dilutes the gas further and can push oxygen into the waste (ch. 8, July 2021).
3. A decline curve longer than the payback. After closure, EPA's LandGEM model has generation falling exponentially at a rate k; the handbook's example uses 0.02 a year for arid conditions and 0.065 for wet (ch. 2). By our arithmetic that is about 2% a year against about 6%, halving in roughly 35 years against 11. ATSDR's general rule is faster: peak production 5 to 7 years after burial, almost all gas within 20 years and small quantities for 50 years or more, with moisture and warmth raising the rate (ATSDR). The two disagree: by the same arithmetic, a tonne of waste gives up only about a third of its gas in 20 years at the arid rate and about three-quarters at the wet one. The site's own measured decline, not either rule, should set the payback.
4. Permits for the engines. Burning landfill gas emits carbon monoxide, nitrogen oxides and particulate matter. A new project may need a New Source Review construction permit, ozone nonattainment can mean stringent nitrogen oxide controls, and engines are covered by federal engine standards (ch. 5). Permitting can take 6 to 18 months or longer (ch. 1). State and provincial rules add to these and change: amendments to California's Landfill Methane Regulation take effect on 1 January 2027 (CARB), and Canada's Landfill Methane Regulations, registered on 12 December 2025, phase in control requirements from 1 January 2028 and list internal combustion engines alongside flares as destinations for recovered gas (Canada Gazette).
5. A written answer on the gas and its attributes. The development contract should say who owns the gas rights and the environmental attributes (ch. 1), and which attributes exist depends on how the gas is used (ch. 5). Three come up most often.

• Transport fuel credits. Renewable Identification Numbers under the federal Renewable Fuel Standard, and credits under state clean-fuel programs, come from landfill gas made into vehicle fuel (ch. 5). The handbook's 2021 list of states is California, Oregon and Washington; New Mexico's program, which lists biomethane among its fuels, began its first compliance period on 1 April 2026 (NMED). A mining load makes none.
• Renewable energy certificates. The handbook describes a typical certificate as 1 MWh of generation delivered to the grid (ch. 5). Check your state program and registry before counting on any for power used on site.
• Methane destruction credits. These generally require that the landfill is not already obliged by regulation to collect and control its gas (ch. 5). If you flare for compliance, the methane is already being destroyed; generation changes what the heat is used for.

• Pipeline-quality gas (RNG) can earn the transport fuel credits a mining load cannot, when it is sold as vehicle fuel, though the handbook notes that fixed-price sales of those credits are often deeply discounted for their high risk and market variability (ch. 5). It needs the most gas and capital. The handbook puts processing equipment at $6,200 to $8,300 per scfm of landfill gas in 2020 dollars, finds pipeline injection most cost-effective from about 1,000 cfm, and notes the cost of the tight wellfield management needed to keep oxygen and nitrogen out (ch. 3). At 500 scfm, that range puts the processing equipment alone at $3.1 million to $4.2 million.
• A power sale keeps renewable certificates in play and gives a lender what it prefers: the handbook says financiers are most comfortable with power purchase agreements because of their predictable revenue (ch. 5). It needs the interconnection.
• A mining load needs no export connection and can follow a small or declining flow. In exchange, its revenue moves with hashprice, which fell from $43.33 on 3 November 2025 (Hashrate Index) to $28.94 on 8 June 2026 and rose 38% from there by 28 September 2026. It also rests on the credit of a counterparty whose only business may be mining.

Where a pipeline is close and the flow is large, RNG is the obvious candidate. Where a utility will connect on workable terms, a power sale is easier to finance. Mining is worth examining where neither is available and the facts above hold.

These are screening numbers, not a design: EPA's constants and 2020-dollar costs are defaults, and the hashprice readings are single dates from one provider, not cross-checked against a second series. Your gas analysis, decline curve and air permit decide the real figures. And Proton sits on the other side of this table: landfill and stranded gas lead our sourcing, so read a note from us about putting a mining load on your gas with that in mind.

Gather the average flow in scfm and its trend, the methane concentration, a recent hydrogen sulfide and siloxane analysis, collection system uptime, the closure date, current air permits, and any existing gas-rights or attribute agreements. The site-screening checklist is one place to record them. When you have them, you can submit the site on our energy page. We reply to every submission by email. If you need an NDA before sharing details, tell us and we'll arrange one.

Before that, put the flow through the calculator. It takes gas in Mcf per day, so 500 scfm is 720, and its default heating value is a pipeline-gas figure: enter your gas's heating value and heat rate first.