In what virtually deprives Reliance Infrastructure Ltd of two gas discoveries D 39 & D 41 located in the KG-DWN-2003/1 block the Director General of Hydrocarbons (DGH) has insisted that the commerciality of the fields would be assessed on the basis of current gas price of $4.2/million metric British thermal units (mmBtu).
Assessing the commerciality of D 39 and D 41 fields based on the current gas price would render them unviable. Production from D 39 and D 41, incidentally, are scheduled to begin at a much later date.
Even though the Cabinet in July approved a new gas-pricing formula starting next financial year, the DGH, in a letter to the oil ministry dated December 10, insisted on assessing the two RIL Nelp 5 discoveries at the current gas price.
The DGHs stand is despite the fact that in a meeting held by the Planning Commission (power and energy division) in September to assess the half yearly performance of the sector, it was observed that Nelp blocks previously deemed unviable at $4.2/mmBtu must be re-examined. Some of the Nelp fields, which were not viable at $4.2/mmBtu, maybe viable with the recently announced price by the Centre, as per minutes from the meeting.
A third well D 52 in the same 2003/1 block was earlier left stranded as RIL did not undertake drill stem tests (DST) in the well, thus DGH finding them non-compliant of the production-sharing contract (PSC). The 2003/1 block sits next to RILs flagging KG-D6 fields.
As the D 52 well was found non-compliant in late 2011, RIL submitted a revised field development plan (FDP) in April 2012 to develop only D 39 and D 41 with a capex of $650 million.
The discoveries lie at depths ranging between 1,500-2,300 metres. D 39 and D 41 hold around 400 billion cubic feet (BCF) of in place gas reserves that can produce for 7 years. The DGH on December 10 wrote to the oil ministry that it has already communicated its views on the issue through a letter on January 23, according to which the two discoveries 39 and D 41 are unviable at $ 4.2/mmBtu, and D 52 was not accepted as the DST was not done. Both letters were accessed by FE. The DGH in its January letter said D-39 and 41 generated negative NPV of $520 million.
As a result RIL cannot produce from these deep water discoveries D 39, D 41 and D 52 in the 2003/1 block holding total in place gas reserves of 500 billion cubic feet (bcf).
Sources said that RIL had sought a relook at the discoveries after the gas price revision was approved by the Cabinet in July. But with the DGH not giving the required DOC approval, the natural gas reserves in 2003/1 will remain untapped in the ground till it is re-auctioned.
The C. Rangarajan formula-based price regime, which will kick off from April 2014, and under which it works out to around $7/mmBtu now, comes to an end in FY17 after which the pricing will be determined by the Kelkar committee recommendations.
The Kelkar panel appointed by Moily last year will suggest a road map for freeing natural gas prices after FY 17. If the RIL was to start production as per schedule on 2017-18, it would have to be ideally priced under the Kelkar pricing regime.
According to a report by global consulting firm IHS Cera, deep water gas production is not viable at under $10 per mmBtu.
Oil ministry officials said the issue of whether DST is mandatory for the approval of the DOCs in future could hinge on what the Cabinet decides over a similar situation in the KG-D6 block where DSTs were not undertaken by RIL. This could set precedence for other fields stuck owing to lack of DSTs, said the official. Oil minister Veerappa Moily in October allowed RIL to retain three gas discoveries in the KG-D6 despite the operator not having done DSTs on them, but nevertheless referred the matter to the CCEA for final approval.
RIL is the operator of the 2003/1 block with 60%, Hardy holds 10% interest while the remaining 30% is held by BP. Situated in the KG basin, the NELP 5 block encompasses an area of 3,288 sq km and is located approximately 45 km off the coast in the Bay of Bengal.
RILs currently has two domestic producing blocks. The mainstay in production, KG-D6, averaged at 14 MMSCMD of gas and 6,160 BOPD of oil/condensate at the end of the July-September quarter. The other producing block are the Panna-Mukta Tapti fields, which it holds with joint venture partners Oil & Natural Gas Corp (ONGC) and BG.