Conversion Factors: Natural Gas
We covered the basic geometric volume conversions for natural gas in the Volume section.
This section focuses on more involved and assumption-dependent conversions, including volume-to-energy relationships and conversions between annual and daily gas flows.
The table below captures commonly used natural gas volume, energy, and flow conversions.
We now explain some of the more important and frequently encountered conversions.
One of the most common gas-related conversions is between billion cubic metres per year (BCM/year) and million standard cubic metres per day (MMSCMD).
Using a 365-day year:
1 BCM/year = 1000 / 365 ≈ 2.74 MMSCMD
Conversely, 10 MMSCMD = 10 × 365 / 1000 ≈ 3.65 BCM/year
In the United States, annual and daily gas flows are commonly expressed as TCF/year and Bcf/d, respectively.
Since 1 TCF equals 1,000 Bcf:
1 TCF/year = 1000 / 365 ≈ 2.74 Bcf/d
For example, US gas consumption of approximately 33 TCF/year corresponds to:
33 × 1000 / 365 ≈ 90 Bcf/d.
Conversely, US gas production of about 110 Bcf/d translates into:
110 × 365 / 1000 ≈ 40.2 TCF/year.
Converting gas volumes into energy units (and vice versa) requires an explicit assumption regarding the calorific value of gas.
In the Indian context, for ease of reference, the gross calorific value (GCV) of natural gas is often taken as 10,000 kcal per standard cubic metre (SCM).
Referring to the Primary Energy conversion section, 1 MMBtu ≈ 252,000 kcal.
Accordingly:
1 MMBtu = 252,000 / 10,000 ≈ 25.2 SCM of natural gas.
Gas requirement for a 100 MW power plant
A 100 MW plant operating continuously at full load generates:
100 MW × 24 × 365 = 876 million kWh per year.
The corresponding annual heat input requirement is:
876 million kWh × 1,720 kcal/kWh ≈ 1.51 × 1012 kcal.
Dividing by the calorific value of natural gas gives the annual gas requirement:
1.51 × 1012 ÷ 10,000 ≈ 151 million SCM per year.
This is equivalent to:
≈ 151 MCM per year, or
≈ 0.41 MMSCMD.
Power generation from 1 MMSCMD of gas
The same relationship can be viewed in reverse by starting with a fixed gas supply.
One MMSCMD of gas corresponds to an annual volume of:
1 × 365 = 365 million SCM per year.
The annual heat input available from this gas volume is:
365 million SCM × 10,000 kcal/SCM = 3.65 × 1012 kcal.
At a station heat rate of 1,720 kcal/kWh, the electricity that can be generated is:
3.65 × 1012 ÷ 1,720 ≈ 2,122 million kWh per year.
Dividing by the number of hours in a year gives the equivalent continuous power capacity:
2,122 million kWh ÷ 8,760 ≈ 242 MW.
Thus, under the stated assumptions, a gas supply of 1 MMSCMD can support approximately 240 MW of gas-based generation operating at full load.
These calculations are intended as representative illustrations. Actual gas consumption and power output will vary with plant load factor, auxiliary consumption, ambient conditions, and gas composition.
Nevertheless, the results provide a useful rule-of-thumb:
• A 100 MW gas plant typically requires about 0.4 MMSCMD of gas
• Conversely, 1 MMSCMD of gas can support roughly 240 MW of capacity, assuming modern heat rates and continuous operation
This section illustrates how natural gas prices translate into the variable cost of electricity generation in a gas-fired power plant.
The calculation focuses on the fuel component alone and therefore represents the gross variable cost of generation. Other costs such as fixed O&M, capital recovery, and transmission charges are excluded.
The following representative assumptions are used:
Natural gas price: $10 per MMBtu
Station heat rate (SHR): 1,720 kcal/kWh
Exchange rate: $1 = Rs 90
Auxiliary consumption (combined cycle plant): 3%
From the Primary Energy conversion section, 1 MMBtu ≈ 252,000 kcal.
Accordingly, a station heat rate of 1,720 kcal/kWh corresponds to:
1,720 / 252,000 ≈ 0.00683 MMBtu per kWh.
At a gas price of $10 per MMBtu, the gross fuel cost per unit of electricity generated is:
0.00683 × $10 ≈ $0.068 per kWh.
This corresponds to a gross variable cost of approximately:
6.8 cents per kWh, or
Rs 6.1 per kWh (at an exchange rate of Rs 90 per dollar).
Combined cycle gas power plants typically have auxiliary consumption of around 3%, meaning that only about 97% of the gross generated electricity is available for export.
Adjusting for auxiliary consumption, the net variable cost of delivered electricity becomes:
6.8 / 0.97 ≈ 7.0 cents per kWh.
In Indian currency terms, this corresponds to approximately:
Rs 6.3 per kWh.
The figures above represent the fuel-driven variable cost of gas-based power generation under the stated assumptions.
Actual realised costs will vary with plant efficiency, gas composition, contract pricing, exchange rates, and operating conditions. Nevertheless, the example provides a useful benchmark for understanding the sensitivity of power generation costs to natural gas prices.
Once power plants are constructed, fixed costs such as capital recovery and fixed O&M become largely sunk. In the short run, what matters for system operation is the variable cost of generation.
Accordingly, the order in which power plants are dispatched is determined by Merit Order Dispatch (MOD), under which plants with lower variable costs are utilised before higher-cost plants.
For this reason, comparing the variable cost of coal-based generation with that of gas-based generation is critical for understanding dispatch outcomes.
Below, we first present a standalone (“forward”) calculation of coal-based generation costs. We then perform a “backward” calculation to derive the coal price that makes coal-based power generation economically equivalent to gas-based generation under the assumptions used earlier.
The following representative assumptions are used for coal-based power generation:
Station heat rate (SHR): 2,400 kcal/kWh
Coal calorific value: 4,800 kcal/kg
Auxiliary consumption: 6%
Coal price: $100 per tonne
Exchange rate: $1 = Rs 90
With a heat rate of 2,400 kcal/kWh and coal calorific value of 4,800 kcal/kg, coal consumption works out to a convenient rule of thumb:
0.5 kg of coal per kWh of gross generation.
Forward calculation: variable cost of coal-based generation
At a coal price of $100 per tonne, the fuel cost per kilogram of coal is:
$100 / 1,000 = $0.10 per kg.
With coal consumption of 0.5 kg per kWh, the gross fuel cost of generation is:
0.5 × $0.10 = $0.05 per kWh, or 5.0 cents per kWh.
Adjusting for auxiliary consumption of 6%, the net variable cost of delivered electricity becomes:
5.0 / 0.94 ≈ 5.3 cents per kWh.
In Indian currency terms, this corresponds to approximately:
Rs 4.8 per kWh.
Backward calculation: coal price equivalent to gas-based generation
From the gas-based generation example presented earlier, the net variable cost of gas-based power generation was approximately:
7.0 cents per kWh, or Rs 6.3 per kWh.
We now ask: what coal price would make coal-based generation equally expensive on a variable-cost basis?
Let the coal price be P dollars per tonne. The gross fuel cost per kWh is then:
0.5 × (P / 1,000) = 0.0005P dollars per kWh.
Adjusting for auxiliary consumption of 6%:
Net cost = 0.0005P / 0.94.
Setting this equal to the gas-based variable cost of $0.07 per kWh:
0.0005P / 0.94 = 0.07.
Solving for P gives:
P ≈ $132 per tonne.
Thus, under the stated assumptions, coal-based generation becomes economically equivalent to gas-based generation (at $10/MMBtu gas price) when the delivered coal price is approximately $130 per tonne.
Below this coal price, coal-based plants are likely to be dispatched ahead of gas-based plants in a merit order framework. Above this level, gas-based generation becomes more competitive on a variable-cost basis.
Actual dispatch decisions also depend on operational constraints, emissions norms, and contractual arrangements; the above comparison isolates fuel-driven variable costs, which typically constitute the dominant component of short-run generation costs
In power systems subject to carbon pricing or emissions trading mechanisms, the variable cost of generation is further affected by the cost of carbon dioxide (CO2) emissions.
To illustrate the impact of CO2 pricing on merit order dispatch, this section isolates the incremental variable cost arising purely from CO2 emissions for gas- and coal-based power generation.
The analysis focuses only on the CO2 cost adder, independent of fuel costs or other operating considerations.
The following representative assumptions are used:
Gas-based generation CO2 intensity: 0.40 tCO2 per MWh
Coal-based generation CO2 intensity: 0.90 tCO2 per MWh
Exchange rate: $1 = Rs 90
We begin with a CO2 price of $10 per tonne to build intuition.
At this CO2 price, the incremental CO2 cost for gas-based power generation is:
0.40 × $10 = $4 per MWh, or 0.4 cents per kWh.
For coal-based power generation, the corresponding CO2 cost is:
0.90 × $10 = $9 per MWh, or 0.9 cents per kWh.
This leads to a simple and useful rule of thumb:
For every $10 per tonne of CO₂:
• Gas-based generation incurs an additional cost of approximately 0.4 cents per kWh
• Coal-based generation incurs an additional cost of approximately 0.9 cents per kWh
Using the above relationship, the CO₂ cost adder can be scaled linearly to higher carbon prices.
For example, at a CO2 price of $50 per tonne, the incremental CO₂ cost becomes:
Gas-based generation: 2.0 cents per kWh
Coal-based generation: 4.5 cents per kWh
At CO2 prices of this magnitude, carbon costs are no longer marginal and can materially alter the relative variable costs of gas- and coal-based power generation.
As a result, CO2 pricing can significantly influence merit order dispatch decisions by disproportionately increasing the variable cost of more carbon-intensive generation.
LNG represents natural gas in liquefied form, primarily for transportation and storage. The table below captures From / To conversions relevant for LNG, covering billion cubic metres (BCM), billion cubic feet (BCF), million tonnes of oil equivalent (MTOE), trillion British thermal units (TBTU), and million barrels of oil equivalent (MBOE).
Many of these conversions are identical to natural gas conversions already discussed above. Accordingly, we focus below on LNG-specific, real-life applications.
LNG ship cargo size is commonly expressed in cubic metres, tonnes, or energy units such as trillion British thermal units.
We illustrate this using a modern LNG carrier with a cargo capacity of approximately 170,000 cubic metres. While LNG vessels of this size typically load to about 98–99% of capacity to allow for boil-off, we assume full volume for simplicity.
The density of LNG varies with composition and temperature, typically ranging from 0.43 to 0.48 tonnes per cubic metre. A commonly used average value is approximately 0.45 tonnes per cubic metre.
Accordingly, 170,000 cubic metres corresponds to:
170,000 × 0.45 ≈ 76,500 tonnes of LNG.
Referring to the From / To matrix, 1 million tonnes of LNG corresponds to approximately 48.028 Bcf of natural gas. On an energy basis, the same quantity corresponds to approximately 46.405 trillion British thermal units (TBTU).
Accordingly, a modern LNG cargo of 76,500 tonnes corresponds to:
≈ 3.67 Bcf
(= 76,500 / 106 × 48.028), or
≈ 3.55 TBTU
(= 76,500 / 106 × 46.405).
At a gas price of $10 per MMBtu, the energy value of such a cargo is:
3.55 TBTU ≈ 3.55 million MMBtu, implying a cargo value of approximately
$35–36 million.
US LNG exports from the Lower-48 began in 2016 with the commissioning of the Sabine Pass LNG Terminal, operated by Cheniere Energy. The facility has a nameplate capacity of approximately 30 MMTPA, spread across six trains of about 5 MMTPA each.
In US LNG market commentary, liquefaction plant capacity is often expressed in MMTPA, while the associated feedgas requirement is almost always stated in Bcf/d.
Using the same From / To matrix, 1 Bcf/d of feedgas corresponds to approximately 7.6 MMTPA of LNG capacity.
This follows directly from:
1 Bcf/d = 365 Bcf/year
365 / 48.028 ≈ 7.6 MMTPA