Why India’s Carbon Credit Trading Scheme is making electricity procurement a strategic decarbonisation decision for energy-intensive industries.
MaxZen Energy Advisory | Carbon Markets & Industrial Power Procurement | August 2026
For India’s energy-intensive industries, the Carbon Credit Trading Scheme (CCTS) is creating a new question for the power-procurement team:
Can the right electricity contract reduce the cost of carbon compliance?
The question is becoming relevant as India’s carbon market moves from policy design towards implementation. Under the CCTS compliance mechanism, obligated entities must meet notified greenhouse-gas emission-intensity targets. Entities that fall short will need to address the resulting shortfall through Carbon Credit Certificates (CCCs), while entities that outperform their targets may become eligible for certificate issuance.
For an industrial plant where purchased electricity is a significant part of the emissions footprint, this changes the way renewable power should be evaluated.
The decision is no longer only about whether renewable electricity is cheaper, greener or more reliable than conventional power. It also needs to be considered in terms of ₹/tCO₂e avoided.
That is where carbon compliance and power procurement begin to overlap.
CCTS has changed the power-procurement question
The CCTS compliance mechanism is based on greenhouse-gas emission intensity — essentially, emissions relative to the relevant unit of production. The framework is being introduced progressively across energy-intensive sectors, with nine sectors identified for gradual transition, including aluminium, chlor-alkali, cement, fertiliser, iron & steel, pulp & paper, petrochemicals, petroleum refining and textiles.
For an obligated entity, the first task is to understand its verified emissions performance and the size of any gap against its notified target.
There are several ways of reducing that gap:
- process efficiency;
- fuel switching;
- waste-heat recovery;
- operational improvements;
- renewable electricity;
- and, where required, purchase or surrender of carbon certificates.
The important point is that these options should not be evaluated independently.
An industrial company should ask a simpler commercial question:
What is the lowest-cost way of reducing one additional tonne of CO₂e, after considering energy cost, regulatory charges, operational risk and the future compliance trajectory?
For some plants, the answer will be process efficiency.
For others, it could be fuel switching or waste-heat recovery.
For highly electricity-intensive facilities, however, power procurement can become an important part of the answer.
Why electricity matters
Purchased electricity can represent a substantial part of the emissions associated with an industrial facility. Under the CCTS compliance procedure, indirect GHG emissions from purchased electricity are included in the emissions calculation. The procedure provides for the use of the applicable grid emission factor from the CEA’s CO₂ baseline database and also allows a supplier-specific emission factor in the case of a dedicated power purchase agreement, subject to supporting documentation and independent verification.
This is an important distinction.
CCTS accounting should not simply be equated with a company’s broader Scope 2 accounting methodology. The applicable CCTS procedure needs to be followed when assessing the actual compliance impact of a particular power arrangement.
For commercial decision-making, however, the basic economic relationship is still useful.
If one MWh of conventional grid electricity is displaced, the associated emissions can be estimated using the relevant emission factor.
For illustration, using the CEA’s FY2024-25 weighted-average grid emission factor of approximately 0.710 tCO₂/MWh, one MWh corresponds to about 0.710 tonnes of CO₂ under that illustrative calculation. CEA maintains the CO₂ baseline database for the Indian power sector, which is the reference source used in the CCTS compliance procedure.
This creates a useful bridge between two numbers that energy and sustainability teams normally analyse separately:
₹/kWh for electricity procurement
and
₹/tCO₂e for carbon compliance.
The economics: what is one tonne of avoided CO₂ worth?
Consider an illustrative carbon value of ₹900/tCO₂e.
Using the 0.710 tCO₂/MWh factor:
₹900 × 0.710 = ₹639/MWh
or approximately:
₹0.64/kWh
In other words, for this illustration, every MWh of electricity associated with the assumed emissions factor carries an emissions value of about 64 paise/kWh at a carbon value of ₹900/tCO₂e.
The same calculation can be performed across different assumed CCC values:
| Assumed carbon value | Illustrative carbon value per MWh | Equivalent value per kWh |
| ₹600/tCO₂e | ₹426/MWh | ₹0.43/kWh |
| ₹750/tCO₂e | ₹533/MWh | ₹0.53/kWh |
| ₹900/tCO₂e | ₹639/MWh | ₹0.64/kWh |
| ₹1,050/tCO₂e | ₹746/MWh | ₹0.75/kWh |
| ₹1,200/tCO₂e | ₹852/MWh | ₹0.85/kWh |
These numbers are illustrative economic values, not forecasts of CCC market prices.
The actual comparison for a C&I consumer must be more detailed. Renewable power should be evaluated against the incremental landed cost of the procurement option, including transmission, wheeling, cross-subsidy surcharge, additional surcharge, losses, banking, scheduling, balancing and other applicable charges.
So the relevant question is not:
“Is renewable power cheaper than a carbon certificate?”
It is:
“After accounting for its full landed cost and its actual compliance treatment, does the renewable procurement option deliver a lower overall cost of meeting the company’s energy and carbon objectives?”
That is a much more useful procurement question.
Where the opportunity is greatest
The importance of electricity procurement will vary considerably across sectors and even between plants within the same sector.
For an electricity-intensive aluminium smelter or chlor-alkali plant, electricity can be one of the largest components of the emissions profile.
For a refinery or an integrated cement plant, process and combustion emissions may dominate, limiting the extent to which renewable electricity alone can close the compliance gap.
The following is therefore an analytical view rather than a regulatory classification:
| Sector / application | Major emissions drivers | Potential relevance of power procurement |
| Aluminium | Electricity for smelting | High |
| Chlor-alkali | Electricity for electrolysis | High |
| Textiles | Electricity and process steam | High |
| Cement – grinding | Electricity for grinding | High |
| Pulp & paper | Electricity and process steam | Moderate–High |
| Alumina | Thermal energy and electricity | Moderate |
| Petrochemicals | Process and combustion | Lower |
| Petroleum refining | Process furnaces and combustion | Lower |
| Cement – integrated | Calcination and process emissions | Lower |
The actual opportunity will depend on plant configuration, captive generation, fuel mix, production levels and the applicable CCTS methodology.
That is why a sector-level assumption should never replace a plant-level analysis.
Renewable electricity is not the same as a renewable certificate
This distinction deserves particular attention from C&I consumers.
A company may purchase Renewable Energy Certificates (RECs) to meet an applicable renewable-energy obligation. But a certificate purchase and physical renewable electricity are not necessarily the same thing from an emissions-accounting perspective.
Buying a renewable attribute does not, by itself, mean that the plant has physically reduced the MWh it draws from the grid.
Physical renewable supply can come through:
- on-site renewable generation;
- captive renewable generation;
- eligible renewable power procured through open access;
- or other arrangements that meet the applicable regulatory and accounting requirements.
For C&I consumers, the question should therefore go beyond:
“How much renewable energy have we purchased?”
It should also ask:
“What electricity is actually being supplied to the plant, and how is that electricity treated under the applicable CCTS methodology?”
This distinction is particularly important when a company is simultaneously managing RCO compliance, sustainability targets and CCTS obligations.
RCO compliance and CCTS compliance should be analysed separately, even where both involve renewable energy.
A worked example: what does a 3% compliance gap mean?
Consider an illustrative electricity-intensive plant with:
- annual grid electricity consumption: 300,000 MWh
- direct emissions: 47,000 tCO₂e
- illustrative grid emission factor: 0.710 tCO₂/MWh
The illustrative emissions associated with purchased electricity would be:
300,000 × 0.710 = 213,000 tCO₂
Total emissions would therefore be approximately:
213,000 + 47,000 = 260,000 tCO₂e
Purchased electricity would account for roughly 82% of this illustrative total.
Now assume that the plant has a compliance gap of approximately 3%, equivalent in this simplified example to about 7,800 tCO₂e.
Option 1: Carbon certificates
At an assumed carbon value of ₹900/tCO₂e:
7,800 × ₹900 = ₹70.2 lakh
Option 2: Electricity displacement
Using the illustrative 0.710 tCO₂/MWh factor:
7,800 ÷ 0.710 = approximately 10,986 MWh
That represents around 3.7% of the plant’s annual grid electricity consumption.
At an illustrative solar CUF of 24%, the corresponding annual generation would require approximately 5.2 MW of notional solar capacity.
This is only a simplified illustration. Actual CCTS treatment will depend on the applicable compliance methodology and the characteristics of the renewable-power arrangement.
The commercial comparison is then straightforward in principle: compare the cost of the renewable procurement option with the alternative cost of addressing the compliance gap.
For example, if the renewable power is ₹0.30/kWh more expensive than the displaced grid electricity, the additional annual energy cost would be approximately:
10.986 million kWh × ₹0.30 = ₹33 lakh
Against an illustrative ₹70.2 lakh carbon cost, the combined economics could still favour renewable procurement.
At a ₹0.60/kWh premium, the additional energy cost would be approximately ₹65.9 lakh — leaving only a small economic advantage against the assumed carbon cost.
The conclusion is not that renewable power is automatically better.
The conclusion is that the carbon value can materially change the economics of a power-procurement decision.
Five variables that can change the answer
A serious CCTS procurement strategy should not rely on one carbon-price assumption.
1. The plant’s actual emissions profile
Start with the verified data.
If purchased electricity represents a large share of the plant’s emissions, power procurement deserves closer attention. If process or combustion emissions dominate, other abatement measures may provide better economics.
2. The applicable emission factor
Do not automatically use the latest CEA factor as though it were universally applicable to every CCTS calculation.
The CCTS compliance procedure specifies how emissions from purchased electricity are to be calculated, including the treatment of supplier-specific factors for qualifying dedicated PPAs. The applicable methodology should therefore be confirmed before assigning a compliance value to a renewable-power contract.
3. Future CCC economics
The actual CCC market price will ultimately determine the cost of the certificate-based compliance option.
Until sufficient market liquidity and price discovery develop, companies should model a range of scenarios rather than rely on a single price assumption.
4. Renewable-power landed cost
A renewable generation tariff is not the same as delivered renewable electricity cost.
The model should include:
- transmission and wheeling charges;
- CSS and additional surcharge, where applicable;
- losses;
- banking;
- scheduling and balancing;
- contract charges;
- curtailment and availability risk;
- and other state-specific provisions.
5. The future target trajectory
A renewable contract designed only around today’s compliance gap may not be sufficient as emission-intensity targets become more demanding.
The better approach is to evaluate the procurement strategy against the forward compliance trajectory, rather than optimise only for one financial year.
What C&I consumers should do now
The first priority is not to buy more renewable power or carbon certificates.
It is to build the right model.
Within 30 days
1. Establish the baseline.
Use the verified emissions data and determine the contribution of purchased electricity to the plant’s emissions intensity.
2. Map the current power portfolio.
Separate grid power, captive generation, renewable power, open-access supply and certificate-based renewable claims.
3. Calculate the actual landed power cost.
Use the plant’s real procurement cost rather than a headline renewable tariff.
4. Identify the potential compliance gap.
Model the gap under the applicable CCTS target and methodology.
Within 90 days
5. Build a carbon-abatement cost curve.
Compare process efficiency, fuel switching, waste-heat recovery, renewable procurement and certificate-based compliance in ₹/tCO₂e avoided.
6. Run multiple carbon-price scenarios.
For example, test low, base and high CCC-price assumptions rather than relying on a single number.
7. Evaluate different renewable structures.
Compare on-site, captive, open-access and other eligible procurement structures against the plant’s load profile and regulatory conditions.
Over the next 12 months
8. Bring energy and sustainability planning together.
The power-procurement team, sustainability/EHS team and finance team should work from a common model.
9. Size contracts against future requirements.
Avoid signing renewable contracts only to address the current year’s compliance position.
10. Maintain a regulatory watchlist.
Key developments to monitor include CCC pricing and trading architecture, detailed CCTS procedures, power-market arrangements, CEA emission factors, expansion of the obligated-entity pool, open-access economics and future emission-intensity targets.
MaxZen Perspective: The power contract may become part of the carbon strategy
CCTS is often described primarily as India’s emerging carbon market.
For electricity-intensive industry, there is another way to look at it.
CCTS is adding a carbon value to an operational decision that energy managers already make every day: how much electricity should the plant buy from the grid, and from where?
Historically, a renewable-power contract would be evaluated on parameters such as:
- ₹/kWh;
- reliability;
- tenure;
- renewable-energy attributes;
- contract flexibility;
- and risk allocation.
Under CCTS, another question becomes relevant:
What is the cost per tonne of CO₂e avoided through that procurement decision?
This does not mean that every industrial consumer should maximise renewable procurement.
Nor does it mean that carbon certificates should be viewed as a last resort.
The right answer will vary from plant to plant.
For one facility, a process-efficiency project may provide the lowest-cost abatement.
For another, a captive renewable project may make sense.
For a third, a well-structured open-access contract may provide both energy-cost and carbon benefits.
And in some cases, purchasing CCCs may remain the most practical compliance option.
The important change is that these decisions should no longer be evaluated in separate silos.
Energy procurement, carbon compliance and finance need to work from the same economic model.
That is where CCTS becomes strategically important for C&I consumers.
Key takeaways
- CCTS is making carbon compliance relevant to power-procurement strategy for electricity-intensive industries.
- The key economic bridge is between ₹/kWh of electricity and ₹/tCO₂e of emissions avoided.
- At an illustrative 0.710 tCO₂/MWh factor, a carbon value of ₹900/tCO₂e corresponds to approximately ₹0.64/kWh of emissions value.
- Physical renewable electricity and renewable certificates should not automatically be treated as equivalent for CCTS emissions calculations.
- Renewable procurement should be evaluated using actual landed cost, applicable CCTS treatment and the plant’s future compliance trajectory.
- The most effective strategy may sit at the intersection of energy procurement, sustainability and finance.
What to watch next
For C&I consumers, the following developments deserve close attention:
- CCC issuance, trading and price discovery;
- BEE’s evolving CCTS compliance procedures;
- treatment of emissions from different power-procurement structures;
- future CEA emission-factor updates;
- expansion of the obligated-entity pool;
- changes in green open-access charges and banking provisions;
- future emission-intensity target trajectories.
These are not simply regulatory developments.
For energy-intensive industry, they are inputs into the next power-procurement decision.
From reporting to procurement
The first phase of CCTS has been about measuring and reporting emissions.
The next phase will increasingly be about economics.
For an electricity-intensive industrial plant, one of the variables influencing both energy cost and carbon performance is the same:
MWh of electricity consumed and how that electricity is sourced.
That makes the power contract more than an energy-supply instrument.
It can become part of the company’s carbon-abatement strategy, energy-cost strategy and compliance strategy at the same time.
The companies that start modelling these three dimensions together will be better positioned to decide when physical renewable procurement makes sense, when efficiency measures should take priority, and when carbon certificates are the more economical option.
The CCTS question for C&I consumers may therefore not simply be:
“How many carbon credits will we need to buy?”
It may increasingly become:
“How should we structure our power portfolio so that we need to buy fewer of them?”
About MaxZen Energy Advisory LLP
MaxZen Energy Advisory LLP works with commercial and industrial energy consumers on power procurement strategy, renewable and open-access structuring, regulatory impact assessment and energy analytics.
We help energy-intensive businesses make better decisions at the intersection of power cost, renewable energy, reliability, regulatory compliance and market risk.
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Disclaimer: This article is intended for general information and strategic discussion only. It does not constitute regulatory, legal, tax or financial advice. Illustrative calculations are based on the assumptions stated in the article. Actual CCTS obligations, emissions calculations, renewable-power economics and regulatory treatment may vary by sector, state, consumer category, power-procurement structure and subsequent regulatory developments. Readers should independently verify applicable regulations and obtain appropriate professional advice before taking decisions.