GAS WARS: CRONY CAPITALISM AND THE AMBANIS

by Paranjoy Guha Thakurta

  By the time the contracts were sealed, a number of retired ONGC officials had already taken up employment with Reliance while a few others joined later. Prominent among them was S. L. Khosla, former chairman and managing director of ONGC. Others included officials from the exploration branch of ONGC: R. B. Mehrotra, director; Dr R. Baslia, deputy general manager and J. S. Misra, group general manager.

  In December 1996, the CAG had criticised the arbitrary manner in which the contracts were awarded and the way in which the government had flouted rules at will to favour particular private companies. For every tonne of production in the Panna-Mukta oilfields, the government lost Rs 1,423 to Reliance-Enron. The report was critical of other anomalies as well in the bidding process. There were no records to indicate that all bids had been received by the government on the closing date, that is, on 31 March 1993, and that all bids were opened on the same date.

  The CAG also alleged that the bids were not openly read out in the presence of all the bidders as was supposed to be the norm. The names of the officials present during the time of the opening of the bids were not recorded. The comparative statements of the bids were not authenticated and dated. The rationale of the Petroleum Ministry to lease out the oilfields was basically faulty as it was claimed that the Panna-Mukta oilfields were uneconomical. The fact was that ONGC had been producing oil from these oilfields. A report by the Ministry had shown a 13.44 per cent post-tax internal rate of return to the private companies on their investments after they took over the fields.

  The CAG report was in fact a damning document on the privatisation of oilfields by the government of India. According to the report, the Reliance- Enron consortium operated the Panna-Mukta oilfield at costs that were higher than their bid projections and the costs that were earlier incurred by the ONGC. The contracts relating to the Panna-Mukta and Mid and South Tapti oilfields did not indicate detailed abandonment procedures.

  The contracts did not provide for a level playing field for public sector oil companies as far as pricing of crude oil and gas, royalty and cess and customs duty are concerned. The comparative economics and alternative financial returns of developing oilfields through joint ventures and only through national oil companies were not submitted to the government before awarding the contracts, the CAG noted, adding that there were inadequacies in even the tender invitation and evaluation procedures. Bid evaluation criteria in the notice inviting bids were not clear. The ministry did not disclose facts regarding post-bid costs of ONGC in the information docket supplied to the bidders. Signature and production bonuses paid to ONGC were not based on well-defined rationale. There were infirmities like unguaranteed production and undefined operating expenditure levels. Information relating to concessions given to the joint ventures in the form of frozen royalty and cess were not specifically provided.

  ONGC had incurred an expenditure of Rs 351.05 crore for exploration and development of the Ravva oilfield, but the consortium with Videocon Petroleum as one of the partners which won the contract for the lease of this oilfield, paid only Rs 173.25 crore as past-cost reimbursement. On the other hand, the contract signed between ONGC and Reliance-Enron contained no provision that would entail the consortium paying past-cost reimbursement to ONGC. The total loss to ONGC on account of this, including half the money it did not get from the Videocon consortium, amounted to Rs 954.32 crore.

  The CAG report also highlighted the fact that the Planning Commission had cautioned the Petroleum Ministry in March 1994 that it should take note of the substantial expenditures incurred by ONGC on the oilfields and make efforts to recover the investments made. The Petroleum Ministry’s reply to the Planning Commission on this issue was unusual to put it mildly. The Ministry said that ‘it may not be possible to fully reimburse ONGC for all past cost incurred’ because international oil prices were fairly low. In fact, while ONGC had been paying Rs 1,428 per tonne as cess and royalty, the private companies were asked to pay only Rs 1,381 per tonne. Again while these rates were to remain fixed for the private companies throughout the 25-year lease period, the rates for ONGC were liable to go up. In yet another instance of favouritism, the government agreed to pay Enron in US dollars in exchange for the oil it bought from it, while Enron paid its share of royalty and cess in Indian rupees – this was a period when the Indian government was not exactly flush with foreign currency.

  Long before the oilfields were offered to the private sector, ONGC had conducted a 3,600 line-km three-dimensional seismic survey of the Ravva field in 1990. Curiously, this valuable data was not interpreted for two years. While its estimates for the Ravva reserves kept varying, the Petroleum Ministry finalised the contract for lease. It was suspected that this data could have reached private companies bidding for the oilfields. As former ONGC chairman and managing director Subir Raha himself pointed out, key files and documents were missing from the archives of the ONGC and were not made available to him when he called for these.

  Though India’s premier police investigating agency, the Central Bureau of Investigation (CBI) had registered a preliminary inquiry in this case in June 1996, six months after Superintendent of Police Y. P. Singh conducted a probe into allegations of nepotism in the manner in which contracts for the Panna-Mukta and Tapti oilfields were awarded and submitted a detailed report in this regard, his superior in the agency, the then CBI Director, K. Vijaya Rama Rao, refused to place the file on record. Subsequently, all information pertaining to Panna-Mukta was blacked out of the public domain. The gist of Y.P. Singh’s case was as follows:

  A negotiating committee comprising the Secretary, Petroleum and Natural Gas, the Finance Secretary and other senior government officials evaluated the responses to the tenders floated by ONGC on developing the Panna-Mukta oilfields in April-May 1993. Further negotiations were held between June and September that year. The CAG report says the contracts were awarded between October and December 1994 for five medium-sized fields and 13 small fields. According to CBI documents, between April 1993 and May 1994, when the bids were being processed, representatives of many industrial houses had approached the then Petroleum Minister Captain Satish Sharma.

  An incriminating statement was made by Capt. Satish Sharma’s additional private secretary Brijnath Safaya that was recorded by Inspector Harish Sharma of the CBI. Safaya had alleged that representatives of several industrial groups sent cash-stuffed suitcases to the then Petroleum Minister during this period. Safaya had alleged that representatives of five industrial groups had routed approximately Rs 13 crore to Capt. Sharma through him. Among the frequent visitors to the Sharma household at that time were Prithviraj Jindal, head of Jindal Saw Pipes; Venugopal Nandlal Dhoot, head of the Videocon group; Shashi Ruia of the Essar group of companies; Mukesh Ambani of Reliance Industries and Abhey Oswal of Bindal Agro. Five industrial houses, including three groups (Reliance, Videocon and Essar) bagged the contracts to extract crude oil from the Panna-Mukta oilfields.

  According to Safaya, the Aurangabad-based Videocon company sent Rs one crore to Capt. Sharma through a person with the surname Wadhwa in July 1993 and again despatched Rs one crore in October later that year. The Essar group dished out Rs three crore in November 1993 using one person surnamed Aggarwal as a conduit and then sent another Rs two crore in February through one Sandeep Bhargava. Similarly, Dhirubhai Ambani and Mukesh Ambani of Reliance Industries gifted Rs one crore through one S. Raman in June 1993, then sent Rs one crore in October 1993 and again, Rs two crore in December 1993. The criminal case against Capt. Sharma did not lead to his prosecution because of an important reason: Safaya retracted his statement.

  APPENDIX 6

  Extracts from the report of the Comptroller & Auditor General of India tabled in Parliament on 12 September 2011

  KG-DWN-98/3 (Operator: RIL)

  The KG-DWN-98/3 block, which is operated by RIL, was awarded in the first NELP round in the year 2000. It has India’s largest gas discoveries (Dhirubai-1 and Dhirubai-3 gas fields) and also has a large oilfie
ld discovery (MA oilfield). Our main findings and recommendations relating to the KG-DWN-98/3 block are as follows:

  Non-relinquishment of area and declaration of entire contract area as discovery area

  We found that the contractor was allowed to enter the second and third exploration phases without relinquishing 25 per cent each of the total contract area at the end of Phase-I and Phase-Il as against Articles 4.1 & 4.2 of PSC. Subsequently, in February 2009, GOI also conveyed approval to treat the entire contract area of 7645 sq.km. as ‘Discovery Area’, thus enabling the operator to completely avoid relinquishment of area.

  ‘Discovery Area’ is defined in Article 1.39 of the PSC as ‘that part of the contract area about which, based on discoveryand results obtained from a well or wells drilled in such part, the contractor is of the opinion that petroleum exists and is likely to be produced in commercial quantities’.

  (Discovery Area is defined in Article 1.38 as ‘the finding, during petroleum operations, of a deposit of petroleum not previously known to have existed, which can be recovered at the surface in a flow measurable by conventional petroleum Industry testing methods’.)

  The delineation of ‘discovery area’ is inextricably linked to results obtained from wells drilled and finding of petroleum deposits recoverable at the surface (which can be discovered only through drilling of successful wells). At the end of the Exploration Phase-I, the operator had drilled all wells – in the north-west part of the block only. The sequence of events between April 2004 and February 2009 clearly demonstrates that:

  Originally DGH did not agree (May 2004) to RIL’s proposal (while preparing to proceed from Exploratory Phase-I to Phase-Il) for not relinquishing any part of the contract area (at the end of Exploration Phase-I) and reiterated the PSC contractual provisions for relinquishment of 25 per cent at the end of Phase-I (even identifying least priority areas for consideration for relinquishment). DGH, further, stated that none of the existing discoveries extended beyond ‘priority area-I’, and no well had been drilled in ‘priority area’, and hence it was not possible to consider the total block area as the discovery area.

  However, by April/May 2005, DGH capitulated. While noting that there were ‘no two different interpretations possible as far as the definition of discovery provided in the PSC’, DGH felt it would be ‘prudent to acquire and interpret the 3D seismic data in the remaining part of the block on a fast track basis’. Subsequently, ‘the relinquishment area could also be worked out in a proper manner’. In the meanwhile, RIL had already moved from Phase-I to Phase-Il without any area relinquishment, and was notifying its intent to move from Phase-II to Phase-III, again without any relinquishment. In August 2006, DGH informed MoPNG that the Management Committee (MC) (chaired by DGH representative) had, in July 2006, permitted the contractor to enter the next phase without relinquishing any area, since data showed ‘continuity of discovery’ in the block area (on the basis of RIL’s presentation based on the results of seismic data acquired).

  Thereafter, there was extensive correspondence between MoPNG and DGH from August 2006. MoPNG raised pertinent questions as to whether the coverage of wells was over the entire block for DGH to reach the conclusion of discovery extension, but failed to pursue this aspect further.

  By April 2007, MoPNG felt that the proposal might be considered on getting a certification from DISH that the whole area had been covered by a reasonable number of wells/ 3D seismic to substantiate continuity of channels and the extent of discovery area. DGH gave a certificate in May 2007 to MoPNG.

  Even in May 2007, internal notes of MoPNG indicated their awareness that the whole of the block had been provided as a discovery area on the basis of 3D seismic and not on drilling of wells, which were mainly confined to the NW part of the block. However, MoPNG now proposed that on the basis of the proposed discovery area, the operator should be asked to appraise the area as per appraisal-related PSC provisions. After concerns expressed by the then Minister, PNG as to whether the decision sought to be ratified was consistent with the PSC provisions, the case was referred to a committee under the chairmanship of Additional Secretary, MoPNG. The Committee accepted the contractor’s claim (February 2008) and decided (April 2008) that the timeline for appraisal of discoveries would commence from 1.1 July 2006 (viz. MC’s acceptance of the contractor’s claim). This was finally approved by the Minister in July 2008, but communicated to DISH only in February 2009.

  RIL’s views at different points of time (that the contractor was ‘of the opinion that petroleum was likely to exist’, ‘the contract area was having hydrocarbon potential’, ‘ultimately additional exploratory wells needed to be drilled to establish the additional hydrocarbon potential in the deeper water area of the block for which they were making efforts to hire ultra deep water rigs’ clearly attempted to confuse potential/ prospectively with actual discovery of hydrocarbons. Their difficulties in hiring ultra-deepwater rigs for the deep water area of the block (essentially the SW part, where no discoveries had been made) had no linkage with the contractual provisions for discovery area and relinquishment.

  Thus, RIL’s proposal of April 2004 to not relinquish any area and retain the whole contract area as ‘discovery area’ was submerged in a sea of correspondence between RIL and DGH, without relinquishment action being taken in terms of the PSC provisions, while RIL was allowed to proceed from phase to phase. By April/ May 2005, DGH had ‘waived’ its earlier objections, and now advised/ directed the operator to complete 3D seismic data. By July 2006, DISH completed its about-turn and agreed (through the MC) to the contractor’s proposal. MoPNG was aware of the flaws in the Mc’s decision for retention of the entire area, but instead of reversing the same (in line with PSC provisions), it chose to accept DGH’s certification for such retention.

  MoPNG gave a detailed reply (July 2011) regarding acceptance of operator’s opinion by DGH and MoPNG. We, however, do not agree with the reply as allowing the contractor to retain entire block area as discovery area was not in compliance with PSC provisions. The reply of MoPNG and our rebuttal thereof are given in detail in Chapter 4.

  We recommend that MoPNG should review the determination of the entire contract area as ‘discovery area’ strictly in terms of the PSC provisions. Further, it should delineate the stipulated 25 per cent relinquishment area at the time of the conclusion of the 1 and 2, exploratory phases, and then correctly delineate the ‘discovery area’ strictly based on the PSC definition, linked to well or wells drilled In that part, without considering any subsequent discoveries (which would be invalid on account of non-compliance with PSC provisions).

  (Para 4.2.1)

  Discovery related issue

  In violation of PSC provisions, in the case of 13 out of 19 discoveries between October 2002 and July 2008, the operator had, without first furnishing the initial particulars of the discoveries in writing to the MC and Government, directly given written notifications regarding potential commerciality of the discoveries.

  MoPNG replied (July 2011) that in the beginning, systems and processes were not fully established, however, over a period of time, the procedures had now been strengthened, and were being strictly followed for subsequent discoveries as per PSC requirement.

  (Para 4.2.4)

  D1-D3 gas discovery

  The operator submitted an ‘Initial’ Development Plan (IDP) in May 2004 (with estimated capital expenditure (capex) of $2.4 billion). The IDP was followed up with an Addendum to the IDP (AIDP) in October 2006 (estimated capex of $5.2 billion for Phase-I and $3.6 billion for Phase-Il). We found that: Most procurement activities were undertaken late in 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.

  As indicated by the operator, advance action was taken to tie up vendors for timely development of D1/D3 fields in anticipatio
n of the MC approval of the AIDP. While a view could, perhaps, be taken that such pre-approval action is at the risk and cost of the contractor, in reality, this increases the probability of such approvals becoming a fait accompli.

  Since approval of estimates does not constitute acceptance of the cost projections of the operator, validating the cost incurred by him can be done only after audit of the actual cost through proper norms. Part of the expenditure in respect of individual items under AIDP incurred during 2006- 07 and 2007-08 has been audited. Remaining expenditure incurred from 2008-09 onwards will be covered in future audits.

  (Para 4.3.1)

  Procurement-related activities

  We found that payments during 2006-07 and 2007-08 revealed instances of huge procurement contracts where we could not derive assurance as to the reasonableness of costs incurred, primarily due to lack of adequate competition – award on single financial bids; major revisions in scope/ quantities/specifications; post-price bid opening; substantial variation orders – with consequential adverse implications for cost recovery and GOI’s financial take.

  In particular, regarding the MA oil field, we found that well before submission, let alone approval, of the Field Development Plan (FDP) and Mining Lease (ML) application, the operator had placed orders for various critical items required for development activities/ production facilities from 2006 itself. We also found serious deficiencies in the award, on a single financial bid, of a 10 year hiring contract for $1.1 billion for a Floating Production, Storage and Offloading (FPSO) vessel from Aker Floating Production (AFP).