LNG - Overhyped, Undervalued - or Misunderstood? Part 2 - Gas-Fired Power
In the first part of this series, we explored the implications of the absolute and relative size of the LNG market on growth and price scenarios. This week, we will address another aspect that is being hotly debated - LNG’s role in the power sector. Does surging power demand mean continuing strong LNG market growth? Will it replace coal-fired power in Asia, reducing emission levels? To what extent can natural gas enhance its share in power generation, particularly from its current modest base of ~3% in China? Or are renewable energy sources destined to capture this growth?
An important note up front - a singular focus on power generation can be a red herring. For instance, power generation represents only about 15% of NatGas use in China, and ~17% in India. Understanding the broader context of NatGas consumption is critical, as demand trends in other sectors could equally drive or constrain overall use. At the same time, these low percentages leave a lot of growth potential. In this article we will aim to understand the conditions required to unlock this growth, and the implications for market participants.
Let’s dive in!
[This article is not financial or investment advice, but provided for general information purposes only. All information is subject to change and should not be relied upon for any decision making. See Webpage Terms of Use.]
The Question
The question of which fuel source is cheapest for power plants sounds deceptively simple. Yet, it quickly expands: when do we factor in total system costs, and when can we narrow our focus to project costs alone? This echoes the familiar full-cycle versus half-cycle economics debate in unconventional oil and gas.
The blessings and trappings of levelized cost
For what many would consider a pretty nerdy topic, there has been an unusually lively public debate in recent months regarding the virtues and shortfalls of using Levelized Cost estimates to assess the competitiveness of various sources of electricity generation.
As a recap, Levelized Cost of Electricity (LCOE) is a metric used to compare the total cost of building and operating different power generation technologies over their entire lifespan. It expresses this cost as an average price per unit of electricity generated (e.g., dollars per megawatt-hour, $/MWh).
LCOE includes all significant costs, such as initial capital investment, operations and maintenance, fuel (if applicable), and decommissioning, all discounted back to a present value. In theory, this allows for an "apples-to-apples" comparison of various technologies, regardless of their different upfront costs, operating expenses, or lifespans, providing a useful snapshot for investment planning and policy decisions. In practice, boiling so many variables down to a single number can be problematic.
The main criticism towards using LCOE is that it is a project-level metric that does not account for the broader system costs and value an energy source provides to the grid.
In other words - the sun doesn’t always shine and the wind doesn’t always blow, thus this lower “quality” of power should be taken into account, and all kinds of other metrics have been proposed to overcome this challenge.
We will try not to add to the (usually not very constructive) philosophical debate, but rather add another metric that is very helpful for understanding market dynamics - heat rates.
Heat Rates to the rescue
A power plant's heat rate is a key indicator of its efficiency in converting fuel into electricity. It essentially tells us how much energy a plant needs to burn to generate one unit of electricity. This is typically measured in million British Thermal Units (MMBtu) per Megawatt-hour (MWh).
Simply put, a lower heat rate means a more efficient power plant. It requires less fuel to produce the same amount of electricity. For instance, a Combined Cycle Gas Turbine (CCGT) plant might boast a heat rate of around 6.8 MMBtu/MWh, while a Single Cycle Gas Turbine (SCGT), often called a "gas peaker," might be closer to 9 MMBtu/MWh. This demonstrates the CCGT's superior efficiency, needing nearly 25% less gas, on average, than the SCGT to produce a single MWh of electricity. While CCGTs are generally more expensive to build (higher capital expenditure or "Capex"), their significantly lower fuel consumption often leads to substantial operational savings.
Once a power plant is built, its capital costs are "sunk." This means that short- and medium-term operational decisions, like when to dispatch a plant or how much to utilize it, primarily hinge on fuel costs. If multiple power plants have available capacity, the one with the lowest fuel cost will generally be chosen to generate electricity (assuming other operational factors like ramp rates aren't a concern).
When natural gas is the marginal fuel, Liquefied Natural Gas (LNG) prices become a crucial driver for dispatch decisions. Even if the LNG was initially procured under a long-term contract linked to crude oil prices, the LNG spot price often dictates whether the gas is burned for electricity or resold on the global market. This flexibility is increasingly common due to the absence of destination restrictions in many modern long-term supply agreements. If LNG spot prices are high, it becomes more profitable to resell the LNG cargo and dispatch plants that run on lower-cost fuels, like coal, if available. For example, in its Q3 Gas Market Report, the IEA outlines how high LNG spot prices have contributed to a 20% LNG import reduction to China in H1 2025. Conversely, as LNG spot prices fall, the economic incentive shifts, and gas-fired plants will be dispatched more frequently.
The economics of renewables
How about Renewables? With zero fuel costs, they are generally dispatched first when available. And the most significant economic shift occurs when the total cost (LCOE) of new renewable projects falls below just the fuel cost of existing gas-fired generation. This is not a theoretical scenario; it is rapidly becoming the reality in numerous countries.
Let’s take the above example of the very efficient CCGT, and assume a natural gas price of USD 12/MMBtu. The fuel cost of each MWh of electricity would be 6.8 MMBtu/MWh * USD 12/MMBtu = USD 81.6/MWh. This is very expensive by North American standards, but USD 12/MMBtu is roughly where LNG spot prices hover at the moment (excluding regas and onshore transportation cost) - in other words, it’s on the cheaper end of what gas-fired generation currently costs for most LNG customers. For an older, less efficient gas-fired steam plant with a 12 MMBtu/MWh heat rate, that fuel cost jumps to a staggering $144/MWh.
Now, let's compare this to the full lifecycle costs of renewables. According to Investment Bank Lazard's 2025 LCOE+ report (based on U.S. renewable projects without IRA Investment Tax Credits), utility-scale solar ranges from $38-78/MWh, and onshore wind from $37-86/MWh. It's important to note that project costs, particularly in China, can often fall at the lower end or even below these ranges, as highlighted by Wood Mackenzie's cost comparisons for power generation in Asia.
This means that the entire estimated full-cycle cost of intermittent solar can be lower than just the fuel cost for even an efficient CCGT. Consequently, it can be economically advantageous to build new renewable assets even when an existing gas-fired power plant is available, especially if that gas is purchased at volatile spot LNG prices. And, as previously discussed, LNG purchases under long-term SPAs can often be resold on the spot market at a profit, rather than being burned for electricity generation. The buildout of renewables, solar in particular, is thus poised to continue - on economic grounds. For more details, Goldman Sachs’ recent article titled “The Structural Solar Surge” is very worth reading.
The Dark Horse - Storage
And then, add storage. Historically, the inherent intermittency of renewables limited their growth. However, this is rapidly changing with the advent of Battery Electric Storage Systems (BESS). Battery system costs are frequently reported below $100/kWh of capacity in China, signaling that adding storage to renewables is becoming increasingly affordable. When factoring in these costs, the combined 'firm' renewable energy, delivered with time-shift capabilities, remains less expensive than the fuel cost of less efficient, older gas-fired steam plants. While it may currently be higher than the fuel cost of an efficient CCGT, batteries offer significant additional benefits, including enhanced grid reliability, peak demand shaving, and ancillary services. Beyond grid-scale firming, emerging technologies like electro-thermal energy storage (ETES) are also opening new pathways for industrial process electrification, by efficiently converting excess renewable electricity into industrial steam.
Implications for LNG contracts
We could go on for a while exploring further details, but this is a rather long and data-heavy article already - where does it leave us?
Natural gas faces a paradox in Asia: While offering substantial growth potential especially in power generation, current high LNG spot prices significantly impede its expansion.
Coal-to-Gas switching could generate substantially higher LNG demand, but in most places this also would require substantially lower LNG spot prices. This somewhat constrains spot price upward potential, while also generating substantial demand growth as those prices come down.
As renewables continue down their cost curves, their deployment will continue to boom, though growth rates may fluctuate depending on LNG prices.
Regardless of price fluctuations, energy storage solutions—both battery-electric and electro-thermal—are strategically positioned to thrive.
As the unprecedented LNG liquefaction capacity buildout continues, market players need to carefully manage their spot market exposures. While the spot market will remain vital and continue to offer attractive economic opportunities, the days of “easy money” are likely over, at least for a while. Operating at the lower end of the cost curve, and possessing the resilience to withstand market downturns, is critical for capitalizing on future price spikes.
And this will be the topic of our forthcoming third part of this series. Stay tuned!
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