Microsoft is expanding its partnership with solar manufacturer and clean energy company Qcells to explore a new way of powering the growing (artificial intelligence) AI infrastructure boom.

The companies announced that they will work on ways to pair Microsoft’s expanding data center footprint with new energy generation and flexible energy resources. The goal is to add power capacity alongside AI infrastructure instead of simply placing more demand on existing local grids.

Andy Park, CEO of Qcells, remarked:

“Our relationship with Microsoft began with American-made solar manufacturing and construction. Now we’re exploring how we can build the energy capacity needed for AI while creating lasting value for the communities that share the grid.” 

The partnership comes as AI pushes electricity demand higher. The International Energy Agency (IEA) expects global data center electricity use to more than double to about 945 terawatt-hours (TWh) by 2030. AI is the main driver of that growth.

For Microsoft, the deal also fits into a wider effort to expand AI while meeting its climate goals.

BYOC: New Power Model Could Take Pressure Off Local Grids

Microsoft and Qcells teamed up in 2023. Their alliance includes over 2.5 gigawatts (GW) of solar panels. It also covers engineering, procurement, and construction services for solar projects.

The new agreement goes beyond solar equipment. The companies now want to explore a model that links AI data centers with new energy capacity.

Instead of simply adding AI-related electricity demand to the grid, the companies want to develop new generation and flexible energy resources at the same time. They say this could support grid reliability while allowing AI infrastructure to grow.

The companies are exploring a “bring-your-own-capacity” (BYOC) model. Under the plan, Qcells could develop and build new energy capacity near Microsoft’s data centers. The power could go directly to Microsoft or to the local utility, with Microsoft funding the electricity needed for its operations.

The partnership will also explore virtual power plants (VPPs) that connect thousands of residential and commercial batteries into one flexible grid resource. The batteries could support the grid during peak demand while customers continue using them normally at other times. Participants could also receive lower electricity bills or payments for supporting the grid.

Qcells plans to prioritize income-qualified households in the VPP program. The companies say this could help spread some of the economic benefits of AI infrastructure to the communities where data centers are built.

Qcells says the approach could include new generation and flexible energy resources that support Microsoft’s growing data center network across the United States. Moreover, paired with flexible connection, the BYOC model could significantly help reduce the time needed for power generation.

The companies have not announced a specific amount of new generation capacity under the expanded agreement. This is an important point. The partnership is currently an effort to develop and test a new approach. It is not yet a commitment to build a specific number of gigawatts of new power plants.

AI Is Creating a New Power Challenge

The need for new energy is growing with AI. The IEA estimates that data centers consumed about 415 TWh of electricity in 2024. Under its base case, that figure could reach around 945 TWh by 2030. Data center electricity use would then account for just under 3% of global electricity consumption.

The United States faces an even larger challenge. The IEA expects U.S. data centers to account for nearly half of the country’s electricity demand growth through 2030.

AI data centers can also have very high power needs at individual sites. This can put pressure on transmission networks, local distribution systems and available generation.

That makes Microsoft’s new approach important. The companies want to see data center growth as a chance to add energy resources, not just a demand for the existing grid to handle.

Microsoft Has Already Expanded Renewable Energy

The Qcells deal builds on Microsoft’s broader renewable energy strategy. Microsoft says it matched 100% of its global electricity consumption with renewable energy in 2025. The company uses power purchase agreements and other long-term contracts to support renewable projects.

A power purchase agreement, or PPA, is a long-term contract to buy electricity from an energy project. Microsoft says these agreements can help developers secure financing for new wind, solar, and other carbon-free energy projects.

The company has also set a goal of becoming carbon negative by 2030. That means Microsoft aims to remove more carbon from the atmosphere than it emits. Its other 2030 goals include becoming water positive, reaching zero waste, and protecting ecosystems.

These targets are becoming harder to achieve as Microsoft builds more AI infrastructure.

AI Growth Is Making Microsoft’s Emissions Challenge Harder

Microsoft’s sustainability data show the challenge. The company’s latest Environmental Sustainability Report covers fiscal year 2025 and measures progress against its 2020 baseline. Microsoft says the rapid growth of AI is changing the environmental impact of its infrastructure.

• SEE MORE: Microsoft’s Emissions Rise 25% in 2025 as AI Expansion Tests Its Net-Zero Goals

The company’s supply chain is also a major source of emissions. Microsoft says about 70% of its emissions come from purchased goods, services, and capital goods, according to its 2026 sustainability report. That includes the materials and equipment needed to build data centers and AI infrastructure.

This creates a difficult balance.

Microsoft needs to build more data centers to meet demand for AI services. At the same time, the company must reduce the emissions linked to construction, electricity use, equipment, and its wider supply chain.

Adding new renewable energy alongside that infrastructure could help address part of the problem.

Qcells Builds the Solar Supply Chain Behind the Deal

Qcells also brings a growing U.S. manufacturing base to the partnership. The company has been building a vertically integrated solar supply chain in Georgia. Its Cartersville facility is designed to bring Qcells’ annual module production capacity to 8.4 GW. The company says that it is enough to produce nearly 46,000 panels per day and power about 1.3 million homes annually.

The expansion supports a broader effort to build more solar manufacturing capacity in the United States. For Microsoft, working with a domestic solar manufacturer could help connect its data center growth with new U.S. energy supply.

Still, the partnership’s new phase is broader than solar panels alone. The companies are looking at how generation and flexible resources can work together with AI infrastructure.

Could Microsoft’s Model Help Build Power as Fast as AI?

Microsoft and Qcells are testing a model that could build new energy supply alongside AI data centers, rather than placing all new demand on existing grids. The approach could combine solar generation, batteries and other flexible resources to support grid reliability as data center demand grows.

The need is significant. The IEA expects electricity for data centers to grow from 460 TWh in 2024 to over 1,000 TWh by 2030. It might even hit 1,300 TWh by 2035. That growth will require closer coordination between data center developers, utilities and energy companies.

Microsoft has already matched 100% of its electricity consumption with renewable energy and aims to become carbon negative by 2030. The Qcells partnership could take that strategy further by linking new clean energy capacity directly with new AI demand.

The companies have not disclosed how much generation or storage the partnership could ultimately add. Its success will depend on whether the model can scale while supporting communities, strengthening local grids and meeting the growing power needs of AI.

• READ MORE: Microsoft Cuts Carbon Removal Buying 80% as AI Emissions Put Climate Goals Under Pressure

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Lithium’s recovery is giving Australia’s largest independent lithium producer a reason to become more aggressive about growth. PLS Group, formerly Pilbara Minerals, expects the lithium market to tighten in the coming years and is preparing to expand its flagship Pilgangoora operation in Western Australia.

The company also returned cash to shareholders for the first time since 2023 after higher lithium prices helped drive a sharp recovery in FY2026 earnings. PLS reported an A$526 million net profit for the year ended June 30, compared with an A$196 million net loss a year earlier.

Revenue reached A$1.934 billion, while underlying EBITDA, a measure of operating earnings, climbed to A$1.137 billion.

The stronger results reflect both higher lithium prices and record production. They also show how quickly lithium miners can recover when prices turn after a prolonged downturn.

Lithium Price Rebound Puts PLS Back on the Front Foot

Lithium prices have staged a major recovery in 2026 after several years of weak conditions. It reached about CNY 157,000 per tonne on August 26, down 2.18% from the previous day but still 92% higher than a year earlier. The price had also gained about 7.2% over the previous month.

The recovery has changed the outlook for producers such as PLS.

The company’s FY2026 results clearly show the effect. PLS increased spodumene production by 17% to 879,500 tonnes and sales by 17% to 891,600 tonnes. Higher realized prices and tighter cost control helped push revenue to almost A$1.93 billion.

The company also ended FY2026 with A$2.29 billion in cash, giving it more room to invest in new capacity.

PLS Sees a Stronger Lithium Cycle Ahead

PLS CEO Dale Henderson has taken a bullish view of the market. He said the company believes lithium has entered a new part of its cycle, supported by strong demand and limited supply growth. He specifically noted:

“Lithium is a volatile market, and our strategy is designed to use that cycle to our advantage rather than as a limitation.”

PLS expects a supply shortfall to develop in the coming years, according to Bloomberg’s report on the company’s results. That view contrasts with the oversupply that weighed on lithium prices through much of 2024 and 2025.

The recent improvement has come as battery demand strengthens, while some producers remain cautious about bringing capacity back online after the price downturn.

PLS has already responded by restarting idled capacity and moving growth projects forward. The company said it entered FY2027 “larger, lower-cost, and financially stronger” than a year earlier.

Still, lithium remains a highly cyclical commodity. A new wave of supply could again pressure prices if production grows faster than battery demand. 

The Australian miner estimates that there would be around 1.6 Mt potential supply gap to meet the 2040 demand, growing from 1.5 million tonnes of lithium in 2025 to 5.1 million tonnes by 2040.

PLS Plans to Double Pilgangoora Capacity

The biggest growth opportunity is P2000, a proposed expansion of the Pilgangoora operation. PLS is studying a brownfield expansion that could lift spodumene concentrate capacity to about 2 million tonnes per year. The company expects to complete its feasibility study in the December quarter of 2026.

PLS has already approved about A$175 million in pre-final investment decision spending to keep the project moving. The spending covers engineering, long-lead equipment, early site work, and infrastructure.

A final investment decision could follow the feasibility study, subject to the results, funding capacity, and market conditions. If approved, P2000 could produce its first ore in mid-2029.

The lithium miner estimates the project may need over A$1.2 billion in investment. It could create more than 1,000 construction jobs and support around 500 ongoing operational roles. The expansion would give PLS substantially more exposure to a stronger lithium market.

The Company Is Bringing Capacity Back Online

PLS is not relying only on P2000. During FY2026, the company restarted the Ngungaju processing plant, which had been placed on care and maintenance during the lithium downturn. It is also progressing the Colina lithium project in Brazil and other growth initiatives.

This marks a clear change from the defensive strategy PLS used when lithium prices were weak.

During the downturn, producers focused on reducing costs, preserving cash, and cutting production where needed. As prices recovered, PLS began bringing capacity back and preparing for longer-term growth.

The company’s financial position now gives it more flexibility to do so. Its FY2026 cash balance reached A$2.29 billion, while it also completed its first US$600 million bond offering during the year.

That combination of stronger prices, higher production, and a larger cash position puts PLS in a stronger position to fund expansion.

First Dividend Since 2023

The lithium recovery is also flowing back to shareholders. PLS declared a fully franked final dividend of 5 Australian cents per share, representing a distribution of about A$161 million. It is the company’s first dividend since 2023.

The full-year dividend suggests the board now has greater confidence in cash generation. However, PLS still needs to balance shareholder returns against the large capital requirements of P2,000 and its other growth projects.

• RELATED: Lithium Prices Stay Strong as Albemarle (ALB) Earnings Surge on Market Recovery, and RBC Sees Demand Resilience

EVs, Batteries and the Next Wave of Lithium Demand

The long-term case for lithium rests heavily on demand from electric vehicles and energy storage. PLS has also pointed to growing demand from stationary batteries and emerging electric mobility markets, including electric trucks.

In April, CEO Henderson said customer discussions in China showed a broader recovery in lithium demand.

Energy storage is becoming particularly important. As grids add more solar and wind power, batteries can store electricity and supply it when renewable generation falls. That creates another source of lithium demand beyond electric cars.

The market, however, remains exposed to changes in battery chemistry, technology, and regional EV demand.

China’s growing use of sodium-ion batteries also creates a longer-term competitive risk for lithium in some applications, particularly lower-cost energy storage.

The Supply Crunch That Could Keep Lithium Prices Rising

PLS’s bullish outlook depends on supply failing to keep pace with demand. That is possible, but it is not guaranteed.

The lithium market has shown how quickly new supply can change prices. When prices surged in 2022 and 2023, producers and developers rushed to expand. The resulting supply growth helped push prices sharply lower.

Now, years of weak prices have forced some projects to slow, suspend, or delay development. That creates the potential for a tighter market if demand rises faster than producers can respond.

PLS is positioning itself for that possibility. Its P2000 project could eventually double Pilgangoora’s capacity to about 2 million tonnes a year, but the company will make the final investment decision only after completing its feasibility work.

This gives PLS some flexibility if market conditions weaken again.

PLS Shares Ride the New Lithium Bull Case

Investors have also responded to the stronger lithium outlook. PLS shares rose as much as 8.1% in Sydney on August 24 after the company released its FY2026 results, reversing an early decline.

The move reflects renewed confidence in lithium prices, PLS’s stronger earnings and its expansion plans. The stock’s performance also shows how closely PLS remains tied to the lithium cycle.

Stronger prices can quickly lift revenue and margins, while another supply-driven downturn could have the opposite effect.

The Hard Part: Can Lithium Stay Tight?

PLS’s FY2026 results show how much the lithium market has changed in a year. Production reached a record 879,500 tonnes, revenue climbed to A$1.934 billion, net profit reached A$526 million, and the company restored its dividend.

At the same time, PLS is preparing for a potential supply shortage and considering a major expansion that could take Pilgangoora to about 2 million tonnes of annual capacity.

The key question now is whether lithium demand can stay ahead of new supply.

If it does, PLS could enter a stronger growth phase with the balance sheet and production base to benefit. If new supply returns faster than expected, the company could again face the price pressure that defined the previous downturn.

For the broader lithium market, PLS’s decision to expand is itself a sign of how quickly sentiment has shifted from oversupply and cost-cutting toward tighter supply and renewed investment.

• READ MORE: Lithium Prices Enter a New Era as China Expands Futures Market, Sodium Batteries Rise, and EnergyX Bets $225M on Supply

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Alberta’s industrial carbon price has had only a small effect on the cost of producing oil sands crude, according to a new study from the C.D. Howe Institute.

The report, published by economist G. Kent Fellows, finds that Alberta’s Technology Innovation and Emissions Reduction (TIER) system added an average of just C$0.70 per barrel to oil sands marginal production costs in 2023. On a production-weighted basis, the increase was even smaller at C$0.34 per barrel.

The findings come as Canada and Alberta prepare to raise the industrial carbon price over the next decade. Under their May 2026 agreement, Alberta’s headline TIER price will rise from C$95 per tonne in 2026 to C$115 in 2030, C$130 in 2035 and C$140 in 2040.

Despite those higher headline prices, the study finds that most oil sands projects should continue to face relatively modest carbon costs.

Carbon Price, Small Cost: Oil Sands Barely Feel the Heat

The C.D. Howe analysis uses project-level production and emissions data to estimate how TIER affects the marginal cost of producing oil sands crude.

In 2023, the system’s impact ranged from an effective C$1.09-per-barrel reduction in marginal costs at the low end to an additional C$4.05 per barrel at the high end. The negative figures represent an effective benefit under TIER because some facilities performed better than their emissions benchmarks and received more credits than they needed.

The average facility saw a C$0.70-per-barrel increase. But larger facilities generally performed better against their emissions targets, bringing the production-weighted average down to C$0.34 per barrel.

That is small compared with oil sands operating costs. The study says 99% of operators have operating costs between C$21 and C$65 per barrel.

Some major projects, including Horizon Mine, Jackpine Mine, Muskeg River Mine, Kearl and Peace River, actually received a net benefit from TIER on a per-barrel basis.

Why the Headline Carbon Price Is Misleading

The study highlights an important difference between Alberta’s headline carbon price and the actual cost many oil sands facilities face. Under TIER, large industrial emitters do not simply pay the full carbon price on every tonne of emissions. The system uses emissions benchmarks and performance credits.

Facilities must also use fund contributions to meet a minimum portion of their true-up obligation, reducing from 40% in 2023 to 10% in 2026 and beyond. Data from 2023 and 2024 show facilities met only the minimum requirement, opting for cheaper market credits over higher-cost TIER fund contributions.

Moreover, facilities that perform better than their benchmark can generate credits. Facilities that perform worse must acquire credits or otherwise meet their compliance obligations.

This means the headline price can rise substantially without creating the same increase in average production costs. That distinction becomes even more important under the new Canada-Alberta agreement.

The headline TIER price will reach C$140 per tonne by 2040, but Canada and Alberta have agreed to target an effective carbon price of C$130 per tonne. Alberta will also introduce a minimum transfer price for TIER credits beginning in 2030. That floor starts at C$60 per tonne in 2030 and rises to C$110 by 2040.

The government says the changes are designed to make Alberta’s industrial carbon market more stable and predictable.

• SEE MORE: Canada and Alberta Strike Major Pipeline Deal Under New Law, Minister Guilbeault Resigns

Costs Stay Below C$5 Per Barrel Through 2050

The most important finding for the oil sands is that higher future carbon prices do not translate into extremely high per-barrel costs under the new system.

Fellows projects that no oil sands facility analyzed would face carbon pricing costs above C$5 per barrel through 2050 under the updated Canada-Alberta pricing and emissions-intensity schedules.

The study also says the estimates intentionally use assumptions that overstate carbon pricing costs. The results should therefore be viewed as an upper bound rather than a forecast of what companies will actually pay.

• Under the new policy, most projects are expected to remain well below the C$5-per-barrel level.

That matters because oil sands producers sell into global markets. Their carbon costs may affect profitability, but individual producers generally cannot set the global price of crude.

Cheap to Pay, Harder to Decarbonize

The relatively small cost does not mean the oil sands have a small climate impact.

Canada’s oil and gas sector produced 208 million tonnes of pollution in 2024. This was the country’s top source of greenhouse gases, making up 30% of national emissions. These sector emissions were 1.8% higher than the year before and 76% higher than in 1990.

However, newer data shows that the industry is starting to break the link between rising oil production and rising pollution. According to a June 2026 report from S&P Global Energy, absolute greenhouse gas emissions from Canadian oil sands rose by only 2% between 2024 and 2025, reaching an estimated 89 million tonnes.

Despite these efficiency gains, oil sands operations still account for a huge chunk of Canada’s heaviest industrial footprints. In the latest federal registry, 63 individual facilities reported over 1 million tonnes of emissions each. Together, they accounted for 157 million tonnes (or 54%) of all emissions tracked under Canada’s federal reporting framework.

• Oil sands extraction sites alone made up 46% of those heavy industrial emissions. This creates a key policy question.

If carbon pricing adds only a small amount to production costs, will it be strong enough to push companies toward major emissions cuts? The answer depends partly on how companies respond to the financial signal.

Carbon Price Is Designed to Drive Investment

Carbon pricing is not intended only to increase operating costs. TIER also creates incentives for companies to invest in lower-emissions technologies and earn credits by improving their performance.

The new Canada-Alberta agreement reinforces that approach. The two governments plan to jointly support 75 million tonnes of emissions reductions through Carbon Contracts for Difference (CCfD), with costs shared equally. These contracts are designed to give companies more certainty about the future value of emissions reductions.

The agreement also sets annual tightening rates for oil sands emissions benchmarks. For large oil sands facilities, the rate is 2% annually from 2027 through 2040. Small oil sands facilities face a 1.5% rate from 2027 to 2030 and 1% from 2031 to 2040.

Those tightening rules could become more important than the headline carbon price itself. As benchmarks become stricter, companies may need to invest more in emissions reduction projects to avoid higher compliance costs.

Carbon Capture Could Change the Equation

The oil sands industry’s biggest proposed emissions reduction project is the Pathways Project, a carbon capture, utilization and storage network backed by major producers.

The May 2026 Canada-Alberta agreement sets a goal of 16 million tonnes per year of emissions reductions from Pathways projects. That includes at least 6 million tonnes per year of CCUS reductions by 2035, another 5 million tonnes by 2040 and a further 5 million tonnes by 2045.

The project is important because carbon capture could allow oil sands producers to reduce emissions without cutting production. Recent industry plans, however, remain under development.

Oil sands companies are targeting a final investment decision in late 2027 or early 2028 for the proposed first phase, according to the Oil Sands Alliance. The project’s cost and the structure of government support remain key issues.

The Real Test: Can a Small Cost Deliver Big Emissions Cuts?

Alberta’s experience shows why the headline carbon price alone does not tell the full story. The province will raise its TIER headline price from C$95 per tonne in 2026 to C$140 in 2040, yet the C.D. Howe study estimates that most oil sands facilities will continue to face carbon costs below C$5 per barrel.

That could make the system easier for producers to absorb. However, it also raises questions about whether the financial signal is strong enough to drive major emissions cuts. The answer will depend on what companies do with the policy incentives.

If producers use TIER credits and carbon contracts to fund carbon capture, efficiency improvements, and other lower-emissions technologies, the system could support both oil production and emissions reductions.

For Alberta, the bigger test is therefore not whether carbon pricing hurts oil sands profits. It is whether the system can turn a relatively modest cost into meaningful emissions cuts.

• READ MORE: Canada’s Oil Sands Alliance Gets Green Light for Multi-Billion-Dollar CCS Project to Cut 16 Million Tonnes of CO₂

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Oman is turning a major waste problem into a potential carbon market opportunity. Oman Environmental Services Holding Company (be’ah) is expanding its work to capture landfill gas and develop carbon credits from the resulting emissions reductions. The state-owned waste-management company is also moving beyond simply burning the gas and plans to use recovered methane to generate electricity.

The effort focuses on the Al Multaqa and Barka landfills, where be’ah has already registered landfill gas recovery projects under Verra’s Verified Carbon Standard (VCS). The strategy could give Oman another way to cut methane emissions while creating potential revenue from carbon markets.

Landfill Methane Is Oman’s Major Emissions Source

Landfills are central to be’ah’s climate strategy because they produce large amounts of methane as organic waste breaks down.

Methane is a powerful greenhouse gas. Capturing it before it reaches the atmosphere can therefore create significant emissions reductions.

be’ah’s 2024 GHG inventory shows how important this issue is. The company reported 1.285 million tonnes of CO2e in combined Scope 1 and Scope 2 emissions. Scope 1 accounted for 1.279 million tonnes, while Scope 2 emissions stood at 6,672 tonnes.

Solid waste disposal sites produced 91.9% of be’ah’s Scope 1 emissions. Mobile combustion, mainly from the municipal waste-collection fleet, contributed another 4.9%, while flaring accounted for 1.5%. That makes landfill methane the clearest target for emissions reductions.

Two Landfills Already Generate Carbon Credits

be’ah’s carbon credit program centers on the Al Multaqa and Barka landfill gas recovery projects. Moosa Al Aamri,
Landfill Operations Engineer at be’ah, remarked:

“The certification of carbon credits for Barka and Al Multaqa landfills marks a significant milestone in Oman’s waste management journey. Through landfill gas capture and greenhouse gas reduction, be’ah has transformed these sites into benchmarks of environmental responsibility and innovation. This achievement aligns with Oman Vision 2040’s goals of sustainability and economic diversification, underscoring the critical role of modern waste management in tackling global climate challenges.”

The projects were registered under Verra’s VCS in 2024 as Project #4544 for Al Multaqa and Project #4550 for Barka. Al Multaqa received credits for 2021 and 2022, while Barka received credits for 2022.

By May 2025, be’ah reported that the two projects had generated a combined 67,700 VCUs. Al Multaqa accounted for about 39,000 credits, while Barka generated about 28,700. One VCU represents one metric tonne of CO2e reduced or removed under the VCS.

The projects were developed with support from OQ Trading (OQT), which helps identify carbon credit opportunities and supports project development, certification, verification, and marketing.

This gives be’ah a potential new source of revenue while supporting its emissions reduction work.

Oman Wants to Turn Methane Into Power, Not Just Flare It

The next stage goes beyond carbon credits. be’ah is developing projects to capture landfill gas and turn it into electricity. The projects began in January 2025 and were scheduled for completion in July 2026. By the end of 2025, overall progress had reached about 55%, according to be’ah’s 2025 Annual Report.

At Al Multaqa, the existing flaring system has a capacity of 2,000 normal cubic meters per hour (Nm³/hr). The site has estimated recoverable landfill gas of about 430 Nm³/hr and potential electricity generation of around 460 kilowatts (kW).

At Barka, the flaring system has a capacity of 2,500 Nm³/hr. Estimated recoverable gas is about 530 Nm³/hr, with potential electricity generation of around 600 kW. Together, the two sites could therefore produce about 1.06 MW of electricity at the estimated recovery levels.

be’ah plans to use the electricity at the landfill sites. At full recovery capacity, it could also potentially export power.

• RELATED: Zefiro Methane’s First Carbon Offset Sale: Turning Orphan Wells Into Climate Assets

One Waste Stream, Three Climate Benefits

Using landfill gas for electricity can create more than one environmental benefit.

• First, capturing methane prevents some of it from escaping into the atmosphere.
• Second, using the gas for power can reduce the need for electricity from other sources.
• Third, the emissions reductions can support carbon credit generation when projects meet the required standards.

Oman’s own climate reporting also identifies landfill gas recovery as an important mitigation measure.

In its first Biennial Transparency Report submitted to the UN Framework Convention on Climate Change, Oman listed landfill methane recovery for direct use and electricity generation among its waste-sector mitigation initiatives. The report estimated average annual emissions reductions of 113,864 tonnes of CO2e for direct methane use at Al Multaqa and 303,542 tonnes of CO2e for electricity generation at Barka and Al Multaqa.

These are estimated mitigation potentials, not verified carbon credits. That distinction is important. Actual credits depend on project monitoring, verification, methodology requirements, and issuance under the relevant carbon standard.

be’ah Builds a Wider Carbon Management System

The landfill projects form part of a broader carbon management plan. be’ah has created a Carbon Management Framework covering five stages:

• Carbon accounting,
• Identifying emissions-reduction projects,
• Carbon credit registration and verification,
• Issuing and selling or retiring credits, and
• Integrating carbon activity into financial management.

This approach could help be’ah identify more carbon projects across its waste operations. The company has already said it is exploring other opportunities in waste management and waste-to-energy. Its earlier sustainability reporting also identified possible projects involving other landfill cells and the use of captured gas.

The strategy fits Oman’s wider Vision 2040 goals, which include economic diversification, environmental protection and more sustainable resource use.

More Waste Could Mean More Methane and More Carbon Projects

The need for better landfill management is also increasing as waste volumes rise. be’ah reported that Oman received 2.88 million tonnes of municipal solid waste in 2025, up from 2.57 million tonnes in 2024. Industrial waste intake also increased sharply to 43,216 tonnes, from 12,649 tonnes a year earlier.

• be’ah commissioned about 2.2 million tonnes of new engineered landfill capacity during 2025 and is developing another 3.4 million tonnes at Thumrait.

More waste means more landfill gas over time. That makes methane capture increasingly important if Oman wants to limit emissions from its waste sector. It also creates a larger potential base for future carbon projects.

Carbon Credits Could Turn Methane Cuts Into Revenue

The carbon credit opportunity is important because landfill gas projects can turn an emissions problem into a marketable environmental asset. be’ah’s partnership with OQ Trading gives the company support in developing, verifying, and marketing credits.

The projects’ registration under Verra also provides a recognized framework for measuring and issuing credits. But carbon credits are not guaranteed revenue.

Project developers must prove that emissions reductions occurred and meet monitoring and verification requirements. Credit volumes can also vary depending on how much gas a landfill produces and how much the project captures.

That means be’ah’s future carbon revenue will depend on actual gas recovery, project performance, and demand from carbon credit buyers.

Oman Tests a Waste-to-Carbon Model

Oman’s landfill strategy shows how carbon markets can support practical waste management projects. be’ah is targeting methane, which accounts for the vast majority of its measured emissions. It is also moving from simple gas flaring toward electricity generation at two major landfills.

The generated VCUs already provide an early example of how landfill emissions reductions can create tradable carbon assets. The next step will be scaling gas recovery and electricity generation while maintaining strong measurement and verification.

If be’ah can expand these projects across more landfills, Oman could develop a larger waste-based carbon market while reducing methane emissions and producing useful energy.

• READ MORE: A Record 3.5M Methane Credits Trade at Xpansiv CBL Signals New Era for Gas Markets

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