WITH gas shortfalls at 50 per cent of total supplies of 4.2 billion cubic feet per day this winter, the luxury of cheap gas availability and consumption seems to be coming to an end.

Major gas reservoirs like Sui, Qadirpur and Zamzama are depleting and fresh discoveries are nowhere in sight yet. The last four years’ freeze on auction of new exploration licences following the ‘landmark’ 18th Constitution Amendment, and consequent lack of institutional arrangements, is set to create a major lag affect on replenishment of hydrocarbon reserves over the next five to eight years.

The inter-corporate circular debt has contributed to the inability of the state-run exploration and production companies to undertake sizable development plans. Backed by high international oil and gas prices, they have posted robust profits in the recent years. However, their declining production levels pose serious challenges going forward.

Policymakers concede that even if current supply levels were maintained in the short to medium- term period, these would not be able to keep pace with the growing needs of the economy that is limping at negligible growth rates of three per cent compared with 7-8 per cent required for absorbing a growing middle class entering the labour market.

Keeping in mind declining trend in conventional gas production and rising demand, official studies have put the gas shortfall at 5.2bcfd by 2021 and eight bcfd by 2025. And most of this shortfall would need to be bridged through imported oil and gas involving more than four times higher delivery costs than prevailing prices at home — whether it is in the shape of Iranian or Turkmen natural gas or liquefied natural gas or furnace oil.

Even the domestic resources — much smaller in size and difficult to augment — are unlikely to be available at less than $15 per mmbtu (million metric British Thermal Units) against current prices of about $4 per mmbtu. The conventional discoveries have now been offered producer prices between $6-8 per mmbtu under the 2012 exploration and production policy.

It is in this background that the recent focus has been on policies designed to bring into use marginal, tight and Shale Gas fields. The marginal fields have recently been offered a special incentive of $0.25 per mmbtu higher price than the producer price for conventional larger fields.

The policy framework for production of Shale Gas structures will help tap five trillion cubic feet recoverable reserve.

A recent study jointly conducted by the state-owned Pakistan Petroleum Limited (PPL) and ENI of Italy has estimated that three pilot projects for producing about four-five trillion cubic feet (tcf) of ‘un-risked and quite attractive’ Shale Gas reserve can supply of 926 million cubic feet per day (mmcfd) for about 40 years.

The study is based on estimation by the US Energy Information Administration (EIA) which suggested that two formations — Sember and Ranikot — possessed about 206tcf of Shale Gas, of which 51tcf was technically recoverable. The Sember formation estimates Shale Gas at about 80tcf, with 20tcf as technically recoverable. The Ranikot formation estimates Shale Gas in-place of 126tcf, with 31tcf as technically recoverable.

This means that Shale Gas can contain shortfall by almost half at present stage, although the production of Shale Gas can materialise in no less than four years. The incentive package has been offered for three pilot projects for Shale Gas production, starting with four exploration and appraisal wells, to be followed up with about 360 development wells.

Although the final price would be determined through competitive bidding, it is estimated to hover around 70-80 per cent of Brent Crude price. The policy envisages carrying forward of tax losses for 15 years (as allowed in the case of tight gas), corporation tax reduction by 10 and royalty holiday for 10 years.

The discovery of 1tcf of conventional gas requires an expenditure of about $530 million, compared to $3.8 billion of Shale Gas. The initial well cost for conventional gas comes to about $12 million, compared to $17.5 million for Shale Gas and hence the production cost of Shale Gas will come to about $16 per unit against the current price of about $4 per unit.

The current oil and gas average daily production of the country is 70,000 barrels per day (bpd) and 4.280 billion cubic feet per day (bcfd), respectively. On the other hand, the consumption of oil is such that 85 per cent of it is met through imports costing a heavy burden of nearly $15 billion annually or 36 per cent of country's import bill. The demand for gas is six bcfd; thus local supplies are sufficient to meet only 50 per cent of the demand which is projected to increase by seven bcfd by the year 2022.

The USEIA estimates the reserves for Low BTU Gas at two tcf and that of Tight Gas 40tcf. Currently, no Shale Gas is being produced and significant work is required to kick-start this high potential energy source; whereas, the conventional gas reserves of the country have been estimated as 58tcf.

Shale Gas is extracted directly from Shale (a sedimentary source rock). Since this has low permeability as compared to conventional reservoirs, it does not release gas easily. To overcome this difficulty, the rock is stimulated (fractured) to yield commercial volumes of gas. Hence to produce gas at a level to make the Shale Gas production economically viable, exponentially large numbers of wells are required as compared to a conventional reservoir.

For the first phase, the lowest producer price with the largest work programme and expenditure would be declared as successful for award of exploration licences. Free area, which is currently not held by any company, and special concession for Shale Gas to be awarded through an open bidding process to companies for pilot projects has been selected in upper Sindh and lower Punjab.

Interested companies having pioneering experience on Shale Gas would be allowed to apply for grant of rights in any Licence Area. The director general of petroleum concessions (DGPC) will notify the area for bid from all interested parties including the existing licence holder.

The existing license or lease holders shall have preferential rights to match the best offered gas price provided they commit the minimum work programme and expenditure requirement and qualify the evaluation criteria.

In case of discovery, lease life shall be for 20 years, and extendable for another 20 years. Each bidder shall be required to submit the bid with a bank guarantee equivalent to 25 per cent of phase-I minimum expenditure commitment or a parent company guarantee or any other guarantee as provided in Petroleum Policy 2012.

The companies where the government has a majority shareholding will not be required to submit the guarantee.