The DGH in its recommendation to the Oil Ministry has suggested $457 million of the ‘profit petroleum’ accruing to RIL in 2011-12 should be disallowed and another $778 million in 2012-13. Sources privy to the development said top officials of the ministry and DGH discussed the numbers at a meeting yesterday but there was no unanimity.

As per the 2006 field development plan, where capital expenditure in Dhirubhai-1 and 3 fields was hiked to $8.8 billion from $2.47 billion previously, RIL was to produce 61.88 million standard cubic metres per day (mmscmd) of gas from 22 wells by April this year and 80 mmscmd from 31 wells by 2012.

But the Mukesh Ambani-run firm drilled only 20 wells till now, of which it has not put two of the wells on production yet. D1 and D3 fields are currently producing just over 40 mmscmd. Sources said the Solicitor General of India (SGI) had opined that Section 3.2 of the Production Sharing Contract (PSC) that states, “… Amounts paid with respect to non-fulfilment of contractual obligations” can be disallowed for cost recovery.

“…The expenditure incurred which has resulted in excess capacity / underutilisation of asset created on account of failure of the contractor (RIL) to adhere to the field development plan would fall within the provisions of Section 3.2,” SGI had said.

RIL has built facilities at KG-D6 to handle 80 mmscmd of output. Sources said based on the SGI opinion the DGH was asked to carry out an exercise to calculate the amount of investment which should be disallowed for cost recovery.

Since most of the $5.7 billion investment RIL has made on D1 and D3 fields has already been recovered, the DGH has suggested that the investment disallowed should be deducted from its profit share for the current and the next fiscal. Anticipating such a move, RIL had on November 24 slapped an arbitration notice challenging the proposal.

PSC for KG-D6, where drop in pressure in the wells and an increased water ingress lead to lower per-well gas output and halt in drilling pending more studies, allows operators to recover 100% of expenditure on exploration and production before sharing profits from the field with the government. It does not link cost-recovery to output. RIL and its new partner BP Plc of UK say new wells in KG-D6 can come up not before 2014.
Agencies

Dhirubhai-1 and 3 (D1 and D3), the first two of the 18 gas discoveries in the Krishna Godavari basin KG-DWN-98/3 or KG-D6 block in the Bay of Bengal that have been put on production, and MA oilfield in the same area produced 40.35 mmscmd in the last week of November, according to the status report filed by the company with the oil ministry.

The output in the week ending November 27 comprised 33.47 mmscmd from D1&D3 gas fields and 6.88 mmscmd from MA oil field. The KG-D6 production is lower than 61.5 mmscmd rate achieved in March 2010 as drop in pressure in the wells and an increased water ingress lead to lower per-well gas out.

The report said of the 18 wells drilled, completed and put on production on D1&D3, four wells — A2, B1, B2 and B13 — had to be shut or closed due to high water cut/sanding issues.

The output from KG-D6 is short of the 70.39 mmscmd (61.88 mmcmd from D1&D3 and 8.5 mmcmd from MA field) level envisaged by now as per the field development plan approved in 2006. While Reliance holds 60% interest in KG-D6, UK’s BP Plc holds 30% and Niko Resources of Canada the remaining 10%.

Reliance started natural gas production from the KG-D6 fields in April 1, 2009. The MA oilfield currently produced about 12,624 barrels of crude oil per day.

The report said 14.47 mmscmd of the gas output is being sold to fertiliser plants and 22.86 mmscmd to power plants. The remaining 3.02 mmscmd is consumed by other sectors, including by the East-West pipeline that transports gas from the east coast to consumption centres in the west.

Reliance projected an output of 40 mmscmd of gas during December. As per the status report, out of the 22 wells planned in in Phase-I of D1 and D3 field development, 18 wells have been drilled and completed so far. Of these, 14 wells were put on production, while four wells were kept closed due to high water cut and sanding issues.
Agencies

RIL Senior Vice-President (Commercial) B Ganguly on November 18 wrote to the Oil Ministry and the Directorate General of Hydrocarbons (DGH) saying, “The price at which the condensate has been sold represented the best available price and there was no competing or even matching offer.”

Replying to the DGH’s concerns over the sale of gas condensate from KG-D6 to the Jamnagar refinery, the company wrote saying the sale was done following a transparent competitive bidding system, as envisaged under the Production Sharing Contract.

In response to a tender for June, 2011, to May, 2012, sale, the company’s Jamnagar refinery in an April 18 bid quoted a price of Brent crude oil price minus $20 per barrel. Hindustan Petroleum Corp Ltd (HPCL) submitted its bid on April 19 quoting a price of Brent minus $25 per barrel.

On RIL’s request to both bidders to review their price proposals, “HPCL revised its bid upward by a mere 5 cents per barrel,” the company said. “HPCL’s revised offer of Dated Brent minus $24.95 per barrel was still $4.95 per barrel lower than that offered by RIL’s Jamnagar Refinery,” he wrote.

“It may be noted that despite HPCL’s Visakhapatnam Refinery being located on the East Coast, it quoted a price which was much lower than the price quoted by a refinery (RIL Jamnagar) at the northern end of the West Coast. HPCL’s price was considered as not justified and against the interest of the parties to the PSC,” he added.

“The bid of RIL Jamnagar, was clearly the best available price at the delivery point… Clearly the sale of KG-DWN-98/3 gas condensate was finalised through a competitive bidding process involving all oil refining companies in India, (and) the requirements of Article 19.2 of the PSC on valuation have been met,” the company wrote.

RIL said no “positive response from any party (either from PSUs or private sector refineries)” was received against a tender for sale of condensate in 2010-11. “HPCL specifically mentioned in their regret email dated May 28, 2010, that due to logistics constraints, they would not be able to  participate in the tender,” the company said, adding that only its Jamnagar Refinery quoted a price of Brent minus $25.6 per barrel.

RIL informed the Oil Ministry of the results of the tender through a letter dated June 2, 2010, which was followed by a reminder on June 30, 2010.
Agencies

The Dhirubhai-1 and 3 (D1&D3) gas fields and the MA oilfield in the KG-DWN-98/3, or KG-D6, block in the Bay of Bengal produced 41.06 mmscmd of gas in the week ending November 13, according to a production report filed by the operator (RIL) with the Oil Ministry here.

Of the 18 wells drilled, completed and put on production on D1&D3, four wells — A2, B1, B2 and B13 — had to be shut or closed due to high water cut/sanding issues, the company told the ministry.

RIL had outperformed the targets when it crossed 54 mmscmd from D1&D3 gas fields in March, before fall in pressure, water ingress and thinner-than-expected reservoirs resulted in a drop in production. Together with 7-8 mmscmd of gas from MA oilfield in the same licence area, total KG-D6 output was 61.5 mmscmd in March 2010 as against the targeted 40 mmscmd in 2009-10 fiscal.

The production, as per the government-approved field development plan, was to rise to 61.88 mmscmd from D1& D3 this year but it has fallen to 34.11 mmscmd in the week ending November 13. MA oilfield is producing 6.92 mmscmd, the report said.

The MA oilfield currently produced 12,636 barrels of crude oil per day.

The report said 13.31 mmscmd of the gas output is being sold to fertiliser plants and 24.44 mmscmd to power plants. The remaining 3.31 mmscmd is consumed by other sectors, including by the East-West pipeline that transports gas from the east coast to consumption centres in the west.

RIL projected an output of 40.80 mmscmd of gas during the rest of November.

As per the status report, out of the 22 wells planned in in Phase-I of D-1 and D-field development, 18 wells have been drilled and completed so far. Of these, 14 wells were put on production, while four wells were kept closed due to high water cut and sanding issues.

Minister of State for Petroleum and Natural Gas RPN Singh had in August informed Parliament that output from KG-D6 was short of the 70.39 mmscmd (61.88 mmscmd from D1&D3 and 8.5 mmscmd from MA field) level envisaged by now as per the field development plan approved in 2006.

While RIL holds 60% interest in KG-D6, UK’s BP holds 30% and Niko Resources of Canada the remaining 10%.

RIL started natural gas production from the KG-D6 fields in April 1, 2009.
Agencies

The Dhirubhai-34 discovery, known as the R-Series field, has gross in-place gas reserves of 1.64 trillion cubic feet, which, according to Reliance, can be brought into production in 4-5 years, sources privy to the development said.

The proposal to declare the field commercially viable — a prerequisite before investments can be made to bring it to production — is likely to come up before the KG-D6 block oversight committee this week.

The Management Committee for KG-D6 has one member each from Reliance and its two partners, BP Plc of the UK and Niko Resources of Canada, besides oil regulator DGH and the Petroleum Ministry.

Sources said the MC is likely to consider Declaration of Commerciality of four discoveries — Dhirubhai-29, 30, 31 and 34 — in the KG-DWN-98/3, or KG-D6, block. The DGH has raised objections on technical data for the D-29, 30 and 31 finds and has asked Reliance to withdraw the current proposal and resubmit it later. The MC will only consider the DoC for the D-34 field.

Reliance believes D-34 can produce 14.68 mmscmd of gas from 11 wells for eight years, they said, adding that the investment figures were only tentative, with a limited view of assessing commerciality of the find and a firm field development plan would be submitted after the DoC is approved.

It had previous submitted a FDP for four satellite fields surrounding the currently active Dhirubhai-1 and 3 (D1 and D3) fields in KG-D6 block. The proposal to invest US $1.529 billion for producing up to 10 mmscmd of gas from the Dhirubhai-2, 6, 19 and 22 (D-2, D-6, D-19 and D-22) fields in the KG-D6 block by 2016 is awaiting Oil Ministry approval.

Sources said Reliance believes D-29, 30, 31 and 34 hold gross in-place reserves of 2.2 trillion cubic feet and can produce a peak output of up to 20 mmscmd. But since the DGH has asked D-29, 30 and 31 to be disassociated, the D-34 reserves of 1.267 tcf are being considered.

The company has so far made 18 gas discoveries in the KG-D6 block. Of these, D-1 and D-3 — the largest among the lot — were brought into production from April, 2009.

It had in July, 2008, submitted a FDP for nine satellite gas discoveries (D-2, D-4, D-6, D-7, D-8, D-16, D-19, D-22 and D-23) with an estimated capex of US $5.6 billion and reserves of 1,708 billion cubic feet (bcf).

Reliance later submitted an optimised development plan for the four satellite gas fields at the end of year 2009.

Reliance estimated 1,733 bcf of in-place gas reserves in the four finds, of which 626 bcf can be produced. However, the DGH trimmed down the estimates to 1,342 bcf and 617 bcf, respectively.
Agencies

The DGH has faulted RIL for not drilling its committed 22 wells on Dhirubhai- 1 and 3 fields in KG-D6 block and also for gas output falling from 61 million cubic metres per day (mmscmd) in March, 2010, to 37.5 mmscmd, instead of rising to 61.88 mmscmd as had been planned.

DGH and the Oil Ministry want RIL to drill the two remaining wells of phase-I development of D1 and D3 fields and 9 more of phase-II by March 2012 as had been committed by the company in the US $8.8 billion field development plan it got approved in 2006.

BP Chief Executive Bob Dudley, on his first visit after the government approved his firm’s plans to invest US $7.2 billion in taking stake in 23 oil and gas blocks of Reliance including KG-D6, said drilling more wells will not solve the problem. “You think of reservoir out there that is producing today is like a coke can. People are advocating that we put more straws in it. But actually what is around it are a few more coke cans. What we need to do now is develop those satellite fields,” he said.
RIL has so far has drilled 20 wells on D1 and D3 field but is producing 36.5 mmscmd of gas from 16 of them. Two wells have been shut because of high water ingress and a similar number of wells drilled recently have so far not connected to the production system.

DGH and the Oil Ministry feel that since Reliance has not kept its commitment made in the 2006 development plan, its right to recover cost should be reduced in proportion to the deficit in gas production. RIL has so far spent US $5.694 billion on the two fields and has recovered US $5.258 billion from the sale of gas produced. However, the ministry wants US $1.85 billion of the cost to be reversed.

Dudley said there are more fields around the currently producing D1 and D3 fields which need to be quickly brought to production. “What we need to do now is develop those satellite fields… We are hopeful that the government will approve development of satellites and that is how you can bring gas production back up,” he said adding production can be raised by 2014.

RIL has submitted a plan to invest over US $1.5 billion in developing four satellite fields around D1 and D3 to produce up to 10 mmscmd of gas by 2016.
Agencies

The Directorate General of Hydrocarbons (DGH), forwarding a note to the ministry for approval of RIL’s investment plans for four satellite finds in the Krishna-Godavari basin block, stated that a Declaration of Commerciality for eight finds has been awaiting the approval of the Oil Ministry since November, 2007.

“Declaration of Commerciality (DoC) of eight satellite gas discoveries (D-4, D-6, D-7, D-8, D-16, D-19, D-22 and D-23) was reviewed in the Management Committee (MC) meeting on November 22, 2007,” the DGH note said.

“The MC resolution (declaring the eight finds as viable for commercial production of gas) had been signed by MC nominees of the joint venture (RIL) and its minority partner (Niko Resources of Canada) and the first government nominee (DGH). Ministry of Petroleum and Natural Gas’ consent is still awaited on MC resolution,” it said.

After a gas discovery is made, its potential is assessed to ascertain if it can be commercially produced. Once the DoC is approved by the MC, which oversees operations in the block, an investment plan is drawn up for bringing the gas to production. Unless, the Oil Ministry grants a DoC, RIL cannot begin work on the field development plan.

RIL has so far made 18 gas finds in block KG-DWN-98/3, or KG-D6, which lies off the Andhra coast. Of these, two — Dhirubhai-1 and 3, or D1 and D3 — have been put on production and nine others (D-2, D-4, D-6, D-7, D-8, D-16, D-19, D-22 and D-23) have been declared as commercially viable by DGH.

Of these nine finds, the Oil Ministry has sanctioned the DoC of only D-2, which was discovered in April, 2002, around the same time as the landmark D-1 and D3 discoveries. The DGH note said RIL submitted a field development plan for the nine satellite gas discoveries with an estimated capex of US $5.6 billion and reserves of 1,708 billion cubic feet (BCF) in July, 2008.

However, techno-economic feasibility studies carried by the DGH at the government-fixed gas price of US $4.2 per mmBtu found them unviable, yielding a negative Net Present Value of US $2.51 billion.

Subsequently, DGH asked RIL to optimise the plan. The firm submitted an optimised development plan for four gas fields (D-2, D-5, D-19 and D-22) in December, 2009, proposing to invest US $1.529 billion to produce up to 10 million standard cubic metres per day of gas in five years’ time. While D-6 was discovered in April, 2003, D-19 was struck in December, 2009, and D-22 in April, 2005, the note said.
Agencies

RIL produced 44.5 mmscmd of natural gas during the week ended September 5 as against 44.8 mmscmd production last month, according to the status report filed by the company with the Oil Ministry here. The output comprised 37.1 mmscmd from Dhirubhai-1 and 3 (D1 and D3) gas fields and 7.4 mmscmd from MA oil field in the KG-DWN-98/3 or KG-D6 block.

D1 and D3 gas fields produced 37.7 mmscmd of gas in August, while output from MA field was 7.1 mmscmd.  As per the status report, out of the 22 wells to be drilled in the Phase-I of Dhirubhai-1 and 3 field development plan, 18 wells have been drilled and completed so far. Of these, 16 wells were put on production as two wells (B2 and B13) were kept closed due to high water cut.

MA oilfield produced an average of 14,080 barrels of crude oil per day besides the 7.4 mmscmd of associated gas. Of the total 44.5 mmscmd, about 13.8 mmscmd of gas was sold to fertiliser plants and another 24.1 mmscmd to power plants. The remaining 6.6 mmscmd was consumed by other sectors like sponge iron plants, LPG, city gas distribution networks and petrochemical/refineries.

Minister of State for Petroleum and Natural Gas RPN Singh had last month informed Parliament that output from KG-D6 was short of 70.39 mmscmd envisaged by now as per the field development plan approved in 2006. “The contractor [Reliance] was advised by [oil regulator] DGH to expeditiously drill more development wells in D1 and D3 field as per FDP in order to enhance gas production in KG-DWN-98/3 block,” he had stated.

Reliance has so far drilled only 20 out of the committed 22 wells on D1 and D3 as reservoir has not performed on expected lines.  Of the 20 wells drilled, only 18 wells are under production. Further in the FDP approved in 2006, RIL had committed to drill 31 wells by the current fiscal-end.

RIL currently holds 90 per cent interest in KG-D6, while the rest is with Niko Resources of Canada. It is selling 30 per cent in the block and 22 others to UK’s BP Plc for US $7.2 billion. RIL started natural gas production from KG-D6 fields from April 1, 2009.

Its partner Niko had last month stated that “declines [in production] are expected to continue until work-overs are completed and/or additional wells are tied-in.” The present output is less than about 60 mmscmd production in the same period a year-ago.
Agencies

Responding to upstream oil and gas production regulator DGH reopening the issue, RIL Executive Director PMS Prasad on August 24 wrote to Oil Secretary GC Chaturvedi saying the US $0.135 per million British thermal units marketing margin is a cost levied beyond the gas delivery flange and as such, is not regulated by the Production Sharing Contract (PSC).

The PSC governs fixation of price of gas at the ‘delivery point’, the point at which an upstream operator transfers custody of gas to a marketing and transportation agency. That point for eastern offshore KG-D6 gas is Kakinada, in Andhra Pradesh, and the government had in 2007 approved a gas price of US  $4.205 per mmBtu at the delivery point.

But the DGH wants the US $0.135 per mmBtu levy added to the gas sale price and profits for RIL and the government to be calculated thereafter. Currently, profits are calculated by deducting capital and the operating cost from the gas sales price only.

Prasad, however, said the PSC does not provide for such a move, as the marketing and transportation cost cannot be recovered from revenues earned from sale of oil or gas.

Section 3.2 (iii) of the PSC states that “costs of marketing or transportation of petroleum beyond the delivery point are not cost-recoverable. Both marketing and transport costs are clearly recognised as being distinct from the sale price at the delivery point and kept outside the PSC for purposes of cost recovery,” he wrote.

He said any attempt to include the margin as part of the price of gas approved under the PSC “will have the effect of making all marketing costs as well as ensuing risks and liabilities cost-recoverable under the PSC.” Moreover, such inclusion can be done only after amendment of the present PSC.

The marketing margin is to cover for cost of employees involved in marketing and sales, related infrastructure and all legal and operational expenses that occur beyond the delivery point, as defined in the PSC. It also covers the credit risk of buyers, litigation costs and penalties such as ship-or-pay reimbursement to transporters and levies for supplying off-spec gas.
Agencies

Sources privy to the development said the Directorate General of Hydrocarbons (DGH) had been pressurising RIL to drill the committed 22 wells by March 2011, so that Dhirubhai-1 and 3 fields can produce projected 61.88 mmscmd and MA field (also in the same block) another 8.1 mmscmd.

But when RIL, which was not confident of the geology after pressure at current 18 wells fell and some showed water ingress, refused, DGH proposed to allow only proportionate recovery of cost. On DGH insistence, Oil Ministry sought a view from the second highest law officer of the country.
SGI Rohinton F Nariman on August 17 opined that “the cost/expenditure incurred in constructing production/ processing facilities and pipelines that are currently underutilised/have excess capacity cannot be recovered”. The Production Sharing Contract (PSC), however, does not envisage such a move and if oil ministry is to order such a thing, RIL is likely to challenge it and may initiate arbitration proceedings.

Sources said no field development plan by any company anywhere in the world, including 40-50 put by state-owned Oil and Natural Gas Corp (ONGC), have gone exactly as per the plans put on paper because of uncertainty involved in behaviour of what lies several thousand feet below the earth.

ONGC had on about a dozen occasions changed field development plan for its prime Mumbai High oil and gas fields. RIL is waiting for BP Plc, who has global expertise in deepsea exploration, to come on board before recommencing drilling at KG-D6. Nariman in his opinion states that the government has “an arguable case” to stop RIL from recovering expenditure which had “resulted in excess capacity / under-utilisation of the asset created” on account of its failure to adhere to the 2006 approved field development plan.

According to the 2006 plan, RIL was to drill a further 11 wells by March 2012 to raise output to 80 mmscmd and sustain it at those levels for 9 years. RIL has so far spent US $5.693 billion and has already recovered US $5.258 billion from sale of gas. Nariman advised that to the extent RIL has already recovered capital expenditure from sale of gas, “the cost entitlement of the contractor can be reversed”.

The Comptroller and Auditor General (CAG) in its report on KG-D6 field audit, which was tabled in Parliament earlier this month, had not commented on reasonability of RIL hiking the capital expenditure at the nation’s biggest gas field from US $2.4 billion proposed in 2004 to US $8.8 billion estimate in 2006. It, however, stated that with the gas output from KG-D6 falling to about 43 mmscmd, which is close to 40 mmscmd output level envisaged in the 2004 investment plan, raised “doubts if upgradation to 80 mmscmd with substantial increase in development cost (to US $8.8 billion) was justified”.

RIL submitted an initial development plan (IDP) for Dhirubhai-1 and 3 gas finds in May 2004 with capital expenditure of US $2.4 billion. This was followed up with an Addendum to the IDP (AIDP) in October 2006 proposing US $5.2 billion capex in Phase-1 and US $3.6 billion in Phase-II. “Most procurement activities were undertaken late in the line with the schedules of the IDP of May 2004. By contrast, activities in respect of items in the AIDP were initiated even before the submission/approval of the AIDP. Clearly, the development activities of the operator were guided by AIDP, rather than IDP,” CAG had said in the repor
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