Carbon free hydrogen, a fuel, a carrier, and a store of energy, is topmost in the global green agenda. It is a substitute for today’s transition fuel—natural gas—which, whilst being cleaner than coal, diesel, or heavy fuel oil, is nevertheless incapable of delivering the sharp reductions envisaged in carbon intensity to limit global warming to between 1.5 to 2 degrees above pre-industrial levels.
India has a deferred strike date for turning Net Zero (2070 instead of 2050 for the advanced economies and 2060 for China). Our per capita carbon emission rates are low, so we have the carbon envelop to take a more measured view on the carbon transition than most advanced economies. But faced by ever tighter “green” conditionalities being imposed from above—a green tax on goods entering the EU and the linking of the flow and cost of international finance to green business credentials, an early adoption of Green Hydrogen (GH) demonstrates commitment to global sustainability.
A domestic substitute for natural gas
GH is not only a cleaner substitute for natural gas (which we mostly import) but is also fit for purpose as a store of energy, and, therefore, useful in balancing intermittent electricity supply from solar and wind. Presently, natural gas, our limited hydro power resources and coal generators fill the gap. GH can also substitute for coal in “hard to abate” industrial applications in steel and fertiliser manufacture. It is also a suitable fuel for shipping and other heavy road freight vehicles because its energy density is 3X of diesel and 3.5X of heavy fuel oil.
The Indian oil companies have been running pilot projects for the manufacture of grey hydrogen since 2007 though the emphasis was on converting biomass and methane to hydrogen.
Modular policy setting for green hydrogen
On August 15, 2021, Prime Minister Modi announced a “National Hydrogen Mission to make India a Global Hub for Green Hydrogen Production and Export”, boost “energy self-reliance” and “inspire” “Clean Energy Transition all over the world” through Green Growth” and “Green Jobs”.
In November 2021 at COP 26 in Glasgow, Prime Minister Modi made five commitments—achieve Net Zero by 2070, and by 2030, take cumulative non fossil fuel generation capacity to 500 GW, meet 50 percent of energy needs from renewable energy, reduce the energy intensity of the economy by 45 percent, and reduce carbon emissions by 1 billion tons.
The “report card”-conscious Modi government reiterated in the budget for FY 2022 (1 February 2022) that further action on GH was forthcoming albeit without committing any financial resources towards that end.
With just over a month to go for the fiscal year to end, the Ministry of Power announced on 17 February “phase one” of the policy, listing the initiatives it proposed to take for facilitating the manufacture of GH.
“Green hydrogen” has been defined as the product of electrolysis of water—using electricity to split water into its constituent components of hydrogen and oxygen—using renewable energy, or using hydrogen or ammonia produced from biomass.
No ISTC for green hydrogen producers
“Green hydrogen” producers are to be exempt for 25 years from paying inter-state transmission charge (ISTC) on the renewable energy bought by projects which are commissioned by 30 June 2025. This is not an entirely new fiscal incentive. DISCOMS (licensed distribution utilities) are already exempt from paying ISTC to POWERGRID (the national grid operator) on purchases of renewable energy (not including hydro power) and energy from battery or pumped storage. What is new is that even bulk consumers (like green hydrogen producers) will now also be exempted from paying ISTC till 2045.
There is a dual objective behind this long-term incentive. First, since the cost of electricity is between 45 to 60 percent of the cost of the green hydrogen, waiving the ISTC lowers the delivered cost of bulk RE supply by 25 percent—assuming RE generation cost at INR 2 per kWh and ISTS at INR 0.66 per kWh—thereby, widening the scope of engagement and creating potential competition beyond the major business houses (Ambani, Adani, and Vedanta) which have already expressed their interest in GH production and supply, including the setting up of integrated RE and GH giga watt scale complexes.
Second, waiving the ISTC also serves the near-term objective of developing a large enough domestic market for the sale of renewable energy. Presently, despite the mandatory Renewable Purchase Obligation, DISCOMs are unwilling to back down fossil fuel energy under pre-contracted “take or pay” arrangements. Since most DISCOMs are publicly owned, they prefer to buy from their in-state generators, rather than from out of state generators. Creating a larger domestic market for renewable energy is necessary to align with the aggressive target committed at Glasgow for RE to comprise 50 percent of electricity consumed by 2030—a five-fold increase over the actual of barely 11 percent in 2021
.Consider that the targeted expansion over the next eight years in non-fossil generating capacity (renewable plus hydro but excluding nuclear) seeks to add more than double the existing capacity of 152 GW in January 2022 by 2030. Quickly ramping up demand for RE from hydrogen producers presents a timely option together with continued R&D efforts towards giga watt scale battery storage for near-term grid balancing and eventually hydrogen-based stored energy for longer-term grid balancing.
Open access to RE as an incentive
Third, the MOP policy assures GH producers open access to RE generators anywhere in the national grid. The catch is whether the local state level electricity regulators (SERCs), where the GH producer is based, would be willing to allow open access on easy term. SERCs protect the near-term earnings of the DISCOMs they regulate. DISCOMs depend heavily on remunerative industrial load to cross subsidise the financial loss from supplying small residential and agricultural load. State government subsidy only partially offsets the loss.
Moving to a more rational system for the direct transfer of subsidy in the hands of selected consumer groups is the best option to preserve the contractual sanctity of paying cost-based utility bills. But we are far from that goal. As an interim measure cooperative federalism in action could streamline open access provisions across state regulators. For example, allowing non-discriminatory open access, whether to an owned or associated RE supplier or purchase from any other RE supplier in exchange for the DISCOM levying only a load commitment charge and the fee to finance the operations of the regional and state load dispatch centers.
It is likely that the bulk of hydrogen manufacture will happen in states on the eastern and western seaboard, given the potential for the use of GH in shipping as also for exports. The MOP policy makes port authorities liable for making land available for setting up GH or ammonia bunkers. The bulk of the incremental RE is also likely to be solar. This means the scope of consensus on open access could also be less than pan national, making it easier for workable open access policies to be collectively accepted within a few key stakeholders.
The MOP policy states that the RE supply consumed by a GH producer, in excess of its RPO obligation, will accrue to the credit of the local DISCOM. But an RPO for GH producers who consume only RE, is redundant or would be 100 percent. Therefore, no excess RECs would exist either. This needs to be clarified and RE supply to GH producers tracked through blockchain to ensure certification.
The Ministry of Power has done what it could to incentivise the production of GH. Other ministries are to yet to add their own incentives to the pot in this unique, modular style of policy formulation.
Revisit key objectives
We need a more granular definition of our objectives. Are we targeting the domestic production of GH, using excess, domestic, RE capacity coupled with the cheapest, fit-for-purpose electrolyser import—at least till 2030? Or are we looking to join the global technological race to manufacture electrolyser systems (modules, stacks and associated equipment which constitute 40 percent of the cost of hydrogen produced) domestically also from the start?
Fiscal prudence dictates that the government confines itself to mandating the demand for GH via blending with natural gas and for steel, oil refining, and fertiliser manufacture. Private companies, aspiring to be hydrogen producers, should be free to choose electrolyser technology, import of which should be at minimum rates of import duty and GH exports should be encouraged. Electrolyser costs will likely fall by 80 percent in the journey towards GH at US $1 per kg, including through 20 percent higher efficiency, 30 percent increase in load hours, and a doubling of lifetime.
The technological risk from bad investments is significant. Scaling up the module and stack size, choice of electrolyte, and system configurations have associated strategic, efficiency, and cost reduction tradeoffs, which need to be optimised against the evolving business case for hydrogen. Incentivising domestic electrolyser manufacture—a capital intensive, highly automated process at peak efficiency levels, delivering high capacity and volumes—should be a secondary priority.
