[OPINION] The problem with DOE’s Mid-Merit Natural Gas Capacity Auction Program

The first-ever centralized “Mid-Merit Natural Gas Capacity Auction Program” of the Department of Energy (DOE) has a catch. While it sounds highly beneficial on paper as laid out under Department Circular No. DC2026-06-0013, it overlooks the hidden complications and risks resulting from its strict condition of limiting the power source exclusively from natural gas only, which in effect largely passes over the economics of the current structural architecture of the energy systems in the areas involved.  

The “mid-merit” term in the energy market refers to power sources that operate between constant baseload generation and short-term peaking units (as in power plants that only run during times of peak electricity demand) to supply variable electricity demand during daytime and evening hours. Hence, they are the power sources that bridge the difference between minimum round-the-clock demand and high daytime surges. 

These energy sources are flexible in schedule of use, as they can be easily turned on and off quickly to handle supply gaps anytime when daily activity starts in the morning and scales down at night. Technically, it operates at a moderate capacity level, higher than “peakers” but lower than baseload. 

In the case of the present mid-market capacity auction program, the DOE specifically designated natural gas capacities only as the bridge to maintain grid stability.  

Auction program and issues

The DOE plans to auction off a total of 3,840 megawatts (MW) of mid-merit capacity covering existing and upcoming generation capacity in Luzon and Visayas. And, instead of letting individual power utilities negotiate separate, fractured contracts, the DOE is implementing a centralized, transparent auction mechanism.

For existing capacities in Luzon, the DOE is targeting the immediate delivery of 1,400 MW from existing gas facilities in 2026, followed by an additional 500 MW in 2027. For new builds in both Luzon and Visayas, this begins in 2028 with 440 MW of liquefied natural gas (LNG) mid-merit plants deployed specifically to Cebu and Panay in the Visayas. By 2031, newly built plants are expected to deliver another 1,000 MW to Luzon and a further 500 MW to Cebu. 

Luzon may have weak gas capacity but it has enough power supply. As reflected in the August 2026 billing period, the Independent Electricity Market Operator of the Philippines (IEMOP) reported that Luzon maintained sufficient generation despite outages. Its supply margin increased by 632 MW, while its average Wholesale Electricity Spot Market (WESM) price declined from P7.30 per kWh to P4.80 per kWh.  

Obviously, while the figures show that Luzon may need more flexibility, they do show that the DOE should not equate a flexibility requirement with an immediate requirement for additional gas capacity, according to market players. 

Under the new rules, too, the DOE decides how much power capacity to auction based on the entire country’s grid needs, rather than looking at what individual electric cooperatives and power companies say they need. Once a power company’s share is included in the auction and a contract is awarded, they cannot back out. The agreement becomes legally binding for the entire delivery period.

This strict approach creates a major risk: if the DOE overestimates how much power is needed, consumers will be forced to pay for unnecessary electricity through a long-term financial obligation.

Moreover, auction-backed gas in Luzon would compete against existing generation, new renewable energy, storage, and other flexible resources. If the gas plant’s all-in price exceeds the value of the energy it displaces, the framework can raise rather than lower system cost. Additional gas for Luzon should, therefore, have to prove that it can reduce total electricity cost, not merely that it can provide electricity.

The Visayas presents a materially different case. During the August 2026 billing period, available supply declined while demand increased slightly, reducing the regional supply margin to only 62 MW. IEMOP recorded 86 hours of Yellow Alert and 53 hours of Red Alert. Prior to the implementation of the regional secondary price cap by the Energy Regulatory Commission (ERC), the average WESM price reached P18.59 per kWh in the region, compared with P4.80 per kWh in Luzon.

Transmission constraints also limited access to lower-cost Luzon generation. IEMOP reported that the Luzon-Visayas interconnection was constrained to exchange power for about 86 percent of the August billing period. The resulting regional shortage increased reliance on higher-cost local oil-based plants and battery resources. The ERC’s September 2026 action to implement a regional secondary price cap further confirms that the Visayas faced an exceptional price and supply problem distinct from Luzon.

In this setting, gas can have a credible economic role if it is located where the grid needs it and displaces diesel or other oil-based generation at the margin. The relevant comparison is the all-in cost of gas against the high-cost generation and reliability interventions it would replace. The case still depends on transmission access, plant availability, fuel contracting, and delivered price, but the underlying capacity and flexibility need is clearer.

More auction policy complications

The auction only forces companies to compete on their building and operating fees (the Gas Auction Price). The actual cost of the imported Liquefied Natural Gas (LNG) is treated as a “pass-through” cost.  Even if the government double-checks that the fuel wasn’t artificially overpriced, consumers still have to pay the full global market price for that gas. The auction cannot stop a completely legal and necessary purchase of LNG from becoming brutally expensive when global prices spike.

Global events directly dictate local electricity rates. For example, due to Middle Eastern supply disruptions in September 2026, Asian LNG prices skyrocketed to US$26.00 per MMBtu. When combined with a weak exchange rate of P62.67 to $1, just the fuel alone costs a gas plant P11.40 to P13.00 per kilowatt-hour (kWh). This does not even include the company’s profit or building fees. When global fuel shocks happen, the electricity bills immediately soar. This already happened in March 2026, when emergency measures were triggered as market electricity prices jumped from P5.00 to over P9.00 per kWh.

If a winning gas plant produces electricity but the daily market (WESM) has plenty of cheaper power available (like solar or coal), the gas plant will lose money in the open market. Under the auction rules, consumers are forced to pay the difference. If the market value of the energy drops below what the government guaranteed the gas plant, the shortfall is collected directly from your monthly electricity bill. Therefore, a “low winning bid” in the auction does not guarantee cheap electricity for the public.

Likewise, four features of the bidding framework create upward pricing pressure or leave major risks with consumers. The fuel component is passed through separately from the Gas Auction Price, leaving consumers exposed to LNG and foreign exchange volatility. The settlement mechanism compensates winning bidders based on the auction formula rather than the WESM energy value, with shortfalls collected from customers. A system-wide capacity determination can exceed the requirements identified by individual utilities if the underlying need assessment is too broad or outdated. Binding participation limits a utility’s ability to withdraw after award even if demand, technology costs, or market conditions change.

It could leave consumers to bear the financial risk of expensive imported gas. Imported LNG creates a continuing exposure to global commodity prices and foreign exchange movements.

A competitive auction can discipline the non-fuel portion of a bid, but it cannot make imported LNG cheap or stable. The government should first establish the service the grid requires, the location and duration of that requirement, and the cost of competing solutions. If the objective is flexibility, the auction should test the full range of technologies that can provide it rather than presume that the fuel has already been chosen.

The circular separates the “gas auction price” from the fuel component. Winning bidders are compensated for energy delivered using the gas auction price plus a fuel cost determined under the ERC-approved gas price benchmarking methodology. The fuel component is a pass-through, subject to verification of whether the cost is actual, reasonable, and prudent.

This structure limits the effect of competition. Bidders compete on the Gas Auction Price, while consumers remain exposed to the cost of LNG used to produce the electricity. The Circular encourages least-cost fuel procurement and preferably long-term supply agreements, but it does not remove the underlying commodity and foreign exchange risk. Verification can prevent unreasonable charges; it cannot prevent an otherwise prudent LNG purchase from becoming expensive when global prices rise.

This exposure is material. The ERC reported that the weighted-average landed cost of LNG in the Philippines increased from $14.90 per MMBtu in the first quarter of 2024 to $17.30 per MMBtu in the first quarter of 2025, even as international benchmark prices declined. The risk became more pronounced in 2026: Asian spot LNG prices reached approximately $26.00 per MMBtu in September – around 150% higher than in February – amid severe disruptions to Middle Eastern supply. 

At $26.00 per MMBtu and an exchange rate of P62.67 to $1, a combined-cycle gas plant with an illustrative heat rate of 7 to 8 MMBtu per MWh would incur approximately P11.40 to P13.00 per kWh in fuel cost alone. This excludes the Gas Auction Price and other applicable costs. The calculation is illustrative, but it demonstrates how imported LNG prices and their exposure to global supply disruptions and foreign-exchange movements can dominate the all-in cost of gas-fired power and ultimately translate into higher electricity rates.

The risk is not theoretical. In March 2026, the DOE imposed emergency measures as international fuel prices rose and supply risks intensified. IEMOP simulations cited by the DOE indicated that average WESM prices could exceed P9.00 per kWh from a pre-crisis level of P5.00 per kWh or less. The episode demonstrated how quickly imported-fuel shocks can affect Philippine electricity prices.

The settlement design adds another concern. If the WESM value of the winning plant’s output is below the auction settlement amount, the shortfall is collected from customers. In a grid with adequate lower-cost supply, this can socialize the difference between the market value of the energy and the amount guaranteed under the auction. A low winning bid on the Gas Auction Price does not establish that the total charge to consumers will be low.

These features may be justified where the auction secures a needed resource at a lower total cost than the alternatives. They are difficult to justify where capacity is already adequate and the new resource is likely to be more expensive than the energy it displaces.

Lastly, several commercially available resources can provide all or part of the flexibility attributed to gas. They differ in duration, location, construction time, and system function, so no single technology is a universal substitute. That is precisely why the comparison should be technology-neutral and based on the service required.  

Level playing field

Natural gas can provide useful mid-merit and balancing services. That capability does not justify a uniform gas procurement across grids with different supply conditions and cost structures.

The Visayas has a demonstrated regional supply and flexibility problem. Gas may lower costs if it displaces diesel and other oil-based generation, is located where the grid can use it, and is procured at a competitive all-in price. Luzon is different. Recent data show adequate margins and materially lower market prices. Procuring additional auction-backed gas without proving the need could add a fuel-indexed resource whose settlement cost exceeds the value of the energy it replaces.

Therefore, instead of choosing natural gas in advance, the government should let all technologies compete on a level playing field. The grid’s need for flexibility should be opened to competing technologies, like solar or wind paired with Battery Energy Storage System or BESS, hydro, and geothermal. And the technology option that provides the lowest total cost and lower risk should win. 

For safety measures, treat Luzon and Visayas separately. The Visayas is facing severe power shortages and genuinely needs localized plants to replace costly diesel. Luzon already has an oversupply of cheap energy and does not need extra gas. Stop letting gas companies pass 100% of fuel price hikes to consumers. Force them to absorb some of the global market shocks. And ban any new gas projects in Luzon unless the government can mathematically prove it will lower total consumer electricity rates. – Rappler.com

A veteran stocks columnist, Den Somera is a licensed stockbroker. You may reach the writer at densomera@yahoo.com

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