Jubilant cannot enter Phase-II work programme in Tripura block: Sources

Sept 2: Jubilant Oil and Gas Pvt Ltd (JOGPL) looks set for a face-off with the government over its unfinished work programme at the Tripura block AA-ONN-2002/1. Top petroleum ministry sources, familiar with the the project, revealed to Indian Petro News on Thursday (September 2, 2010) that Jubilant cannot enter Phase-II of the work programme in the onland block because it has been unable to complete the minimum work programme (MWP) for Phase-I, despite repeated extensions. After the deadline for Phase-I exploration ended in July 2010, Jubilant had expressed its intent to enter Phase-II of the work programme.
 8Moreover Jubilant had not been able to reach the specified target depth in its Ambassa-North well in the block, drilling to a depth of only 3,493 metres as against the target of 4,000 metres. The upstream regulator -- Directorate General of Hydrocarbons (DGH) -- which examined the geological reports submitted by the operator recently briefed the ministry on the issue. JOGPL's request that the well be treated as completed -- due to geological difficulties in further drilling -- may not be entertained, a recent DGH note states.
 8The DGH has also shot down the operator's claim that the third extension in the exploration phase should be redundant since the work would be completed within the period of the 251-day extensions granted under 'excusable delays'. Apparently, the period of the third extension (13-18 months) shall, therefore, still be taken out of the specified duration for Phase-II. By Sadiq Shaban   Details

ONGC's shale gas project: DGH recommends duty exemption

Sept 2: The Directorate General of Hydrocarbons (DGH) has requested the petroleum ministry to consider granting custom duty concession for conducting research and development (R&D) studies for assessment of shale gas potential in the CBM blocks awarded to ONGC in Raniganj and North Karanpura coalfield areas.
  8Despite the fact that the government has undertaken several initiatives to fast-track shale gas exploration activity, the road is still not clear ahead.
  8Pertinently, the DGH has pointed out that the existing notifications in this regard are not adequate to extend custom duty exemption benefit to shale gas operations.
  8Presently, custom exemption is available to institutes registered with the Department of Science and Industrial Research, Government of India. ONGC, being a publicly traded company ,will not be allowed to avail of the benefit.
  8To further add to ONGC’s woes, the list of equipment eligible for exemption is limited and is not suitable for shale oil exploration purposes.
  8Besides, custom duty exemption is already applicable for goods specified for petroleum and CBM operations. However, similar notification is available only for for operations undertaken under the PEL/ML areas, and not for shale gas operations.
  8The DGH, on it’s part, has stated, that since this project is the  first of its kind related to exploratory activity being conducted in India and ONGC having invested in it, it is advisable that custom duty concession be granted by amendment in the existing laws, by the petroleum ministry. The DGH has further added that if it is approved by the petroleum ministry then the finance ministry may be advised to amend the existing notification for CBM to include exemption of custom duty for R&D studies of shale gas.
  (Click on details for more information)   Details   Details

Shale gas: US to assist India

Sept 2: A draft memorandum of understanding (MoU) has been prepared between the petroleum ministry and the U.S Geological Survey to pursue cooperation in shale gas exploration and production in India. The purpose of the MoU is to provide a framework wherein both the associated parties can exchange their knowledge and expertise. The MoU will also encourage participation and cooperation from other organizations, including universities, research centres, institutions, exploration and production companies, whenever necessary. In light of the above, both US and India, will individually agreed to maintain a certain set of commitments which are given as follows:
 8US commitments:
 --Assistance in assessment of India’s shale gas resource potential in mutually agreed areas and on mutually agreed terms.
 --Identification of exploration and production technologies suitable for Indian sedimentary basins, including environmental risk mitigation measures and estimate investment potential.
 --Technical studies to ascertain the production capability; economics; environmental aspects etc.
 --Provision of assistance in developing suitable policy and contractual framework including fiscal regime, regulatory aspects and possibilities of conducting simultaneous operations within existing oil/gas leased areas.
 --Exchange of experience, study tours and seminars.
 --Training Indian nationals in shale gas resource assessment methodology and characterization of shale gas quality in order to better understand it’s production potential. the US will cover the costs of arranging and holding such training.
 8Indian commitments:
 --Sharing non-sensitive and non-proprietary geo scientific data and other information of relevant basins of India with USGS relevant to assessment of shale gas resources and identifying suitable exploitation technologies.
 --Extending necessary help and facilitate activity to be undertaken jointly.
 --Participation of Indian personnel in training, workshops and seminars organized by US government entities. India would provide funding for technical experts to attend such events.
 (Click on details for more information)    Details

Draft Access code for CGD network-I: BG's comments

Sept 2: British Gas (BG), India, recently submitted its comments to PNGRB on the draft guidelines on "Acess Code for City or Local Gas Distribution network." The following are some of the important points raised by the company: 
 8Only the authorized entity should have the right to lay pipelines -- and not the shipper -- in case the entity is not able to provide connectivity to out of turn connections. Furthermore, the cost of such connectivity should be borne by the shipper or shall be adjusted in the tariff as mutually agreed between the shipper and the authorized entity. 
 8A consumer or shipper who is getting gas through the authorized entity during the exclusivity period shall have the right to reserve such capacity after the exclusivity period. In case the shipper is willing to relinquish the capacity, then the same has to be informed 60 days in advance. 
 8The sum of the requested entry point`s Maximum Daily Quantity (MDQ) should be greater than or equal to 10,000 SCMD and not 5,000 SCMD as proposed by PNGRB. 
 8The company has proposed that the network tariff charges for each day should be equal to the product of the network tariff and the sum of the relevant exit point`s MDQ or allocated quantity, whichever is greater, as against PNGRB`s insistence on sum of relevant exit point`s delivered quantity only.
 8The current guidelines stipulate that at no point of time the available capacity in a CGD network or cumulative available capacity at all entry points shall be less than 25% of the capacity of the CGD network or the quantity of gas flowing in the network, whichever is higher. However, this, according to BG, implies that 25% of the CGD capacity will always remain idle, thereby leading to wasteful investments. Instead, the company has suggested that the available capacity of entry, exit and CNG exit points at all the predetermined relevant entry points and exit points on its CGD network should be declared before the end of the exclusivity of the authorized entity from the purview of common carrier or contract carrier. 
 (Click on our "Reports" section for more information)

Draft Access code for CGD network-II: RIL's comments

Sept 2: The website carries here, comments of Reliance Industries Limited (RIL) on the draft guidelines on "Access Code for City or Local Gas Distribution network." Pertinently, the private major has sought clarifications on various issues, such as access arrangement, available CNG exit point capacity, CNG exit point, out of turn connections, scheduled quantity and definition of shipper, so as to remove any ambiguities. Besides, the company has suggested the following modifications: 
 8These regulations shall apply to an entity authorized to operate a city or local natural gas distribution network in a geographic area under the PNGRB Act, 2006, "immediately upon" the expiry of its exclusivity period and not "after the end of exclusivity period" as stipulated in the guideline. 
 8The "metering point" means where gas measurement is carried out which will include metering device and equipment -- and not just the gas measurement as indicated in the guidelines -- and pressure reduction up to desired pressure by the consumer, at exit point. 
 8The authorized entity shall declare the available capacity with regard to available entry and exit points, CNG exit points and all entry and exit points on its city or local natural gas distribution network atleast 365 days prior to the expiry of its exclusivity period and not "before the end of its exclusivity period" as stipulated in the guideline. 
 8It is desirable to broadly specify the timing triggers required to be followed by authorized entities post exclusivity period to avoid vesting of complete discretionary authority with the authorized entity to decide the implementation of capacity booking provisions on a continuous basis.
 8All shippers including existing end consumers are required to book the capacity in accordance with the capacity booking regulations provided in the access code to ensure that all capacity booking transactions are carried out with complete transparency and on arms length principles.
 8All the facilities, including metering, at City Gate Stations (CGS) should be provided by authorized entities -- and not shippers -- to avoid duplication of metering facilities. However for entry points other than CGS, responsibility of providing metering, pressure reduction and odorization facilities should be as may be agreed in the access arrangements between the shipper and the authorized entity. 
 8In line with the access code applicable for natural gas pipe line, overrun charges should be applicable only in case of unauthorized usage of CGD network.
  (Click on our "Reports" section for more information)

Draft Access code for CGD network-III: GAIL Gas' comments

Sept 2: In response to the comments sought by the PNGRB on the draft guidelines on Access Code for CGD network, GAIL Gas Limited -- a wholly owned subsidiary of GAIL -- has suggested that operational limitations of CGD network and gas drawl behavior by the customers in CGD project need to be studied profoundly before finalizing the code. As per the company, some of the key issues which are required to be examined in this respect include: 
 8PNGRB should deliberate the draft access code with lead players in the CGD business in one to one hearing, along with GAIL Gas, before the access code is discussed in the open house. 
 8Before coming out with such elaborate Access Code regulations, there should be a proper structure for operation methodologies for monitoring of entry and exit points, material reconciliation and surveillance, especially given the fact that there are plans to roll out CGD networks in more than 200 cities in the future. 
 8The implementation of access code provisions require additional capex and opex for metering facilities and operating and surveillance expenditure which were not considered while calculating the tariffs submitted to PNGRB. Such additional expenditure would demand revision in network tariffs after the exclusivity period.
 8Sufficient exclusivity period should be granted to companies to ensure the development of network and market for ensuring returns on investments.
 8One of the pre-requisite for implementing the Access Code is determination of network capacity. This, the company feels, is an arduous task since the same is dependent on various factors.  
 8With no social obligation to the shipper for serving PNG consumers, it is likely that entrants or pure shippers shall exclusively target high volume segments with lower prices, while the authorized entities, with the obligation to serve all the segments, may have to balance out all the segments and thus may not be in a position to offer such lower prices.
(Click on our "Reports" section for more information)   

Draft Access code for CGD network-IV: GSPC seeks clarifications

Sept 2: GSPC has sought clarifications on the draft guidelines on Access Code for CGD network which is in the process of being finalised by the PNGRB. These clarifications pertain to the following areas:
  8Access arrangement: The company feels that it is not necessary that all the entry and exit points should be made available to the shipper by the authorized entity.
  8Available CNG exit point capacity: According to PNGRB, authorized entity can spare only 25% of its network capacity. However, it is not clear if it pertains to 25% of total pipeline capacity for CNG or 25% of total open access capacity.
  8CNG exit point: The company has sought clarification on whether the exit point is for LCV filling. The company has also sought clarification with regard to the location of metering measurement equipment.
  8Declaration of available capacity: According to the company, the available capacity with regard to available entry and exit points, CNG exit points and all entry and exit points on city or local natural gas distribution network should be declared by the authorized entity atleast 180 days prior to the expiry of its exclusivity period and not "before the end of its exclusivity period" as stipulated in the guideline.
  (Click on our "Reports" section for more information)

Draft Access code for CGD network-V: No need to rush up, says IGL

Sept 2: Indraprastha Gas Limited (IGL) -- a joint venture between GAIL and BPCL -- has submitted the following comments to PNGRB on the draft guidelines on Access Code for CGD network:
 8PNGRB should engage and closely interact with IGL and Mahanagar Gas Limited (MGL) to form a better understanding of the business in the Indian context based on the actual experience of these two companies. It is strongly suggested, a one to one interaction between PNGRB and IGL and MGL individually or together be undertaken.
 8There is no need for rushing the process for the finalization of Access Code at this stage considering that IGL will be the first one to be affected by the code as its exclusivity period is scheduled to end in January 2012. Exclusivity in case of other companies will not be over before 2014.
 8There is an urgent need to revisit the issue of exclusivity period in view of a number of factors.
 8A preliminary examination of the draft regulations suggests that the draft code is heavily loaded in favour of shippers and totally detrimental to the interests of the authorized entity. Framing the regulations in such fashion may be demotivating and discouraging for entities to participate in the future bidding and that holds for oil and gas companies already in this business.
 (Click on our "Reports" section for more information)

Simultaneous coal and CBM operations: DGH asks for re-drafting of co-development agreement, says present draft skewed towards coal ministry's interests

Sept 2: It seems that the tangle over simultaneous exploitation of coal and CBM gas will take quite a long time to be resolved. The Directorate General of Hydrocarbons (DGH) has recently asked for several modifications in the co-development agreement drafted by the ministry of coal. The upstream regulator alleged that the draft agreement was skewed in favour of the coal ministry, without due attention being paid to safeguard the interests of the petroleum ministry and the operators of CBM blocks.
 8Pertinently, the DGH said that Clause 2 of the agreement conferred unfair authority upon the coal ministry and the coal mining company operating simultaneously with an oil and gas company at a CBM block.
 8Specifically, clause 2.1(c) looks to "provide for rights of each party to CBM within co-development area". This was not acceptable to the DGH since it felt that it should be the company which was seeking to extract CBM gas from the area which should have complete control over the area demarcated for CBM operations.
 8Similarly, clause 2(b) stipulates that coordination arrangements for operations on the overlapping area will have to be approved by the coal ministry, which is detrimental to the interests of the oil and gas companies.
 8Moreover, clause 2(c) stipulates that even for obtaining a lease for extracting CBM gas, a company would have to get the approval of the ministry of coal.
 8Other clauses in the agreement, such as clauses 3.3, 3.5 and 5.4 have been touted by the DGH as "unilateral" since they put certain obligations on the CBM lease holder without corresponding obligations on the coal lease holder.
 8Schedule III of the draft co-development agreement stipulates that the coal ministry will control the regulatory framework for simultaneous coal mining and recovery of CBM gas. The DGH pointed out that this unequal division of power would not be acceptable to the petroleum ministry.
 (Click on Details for more information)   Details

RIL unhappy with Jacobs' methods for valuation of crude-I: Tapis crude price too volatile to be used as base for pricing of KG-D6 crude, says RIL

Sept 2: Reliance Industries Limited (RIL) has expressed its discontent regarding the methods used by consultancy firm Jacobs for valuation of crude produced at the prolific KG-D6 field as well as the Mangla field. As regards the pricing of KG-D6 crude, the private sector E&P major said that the price of Tapis crude -- which was used by Jacobs as the marker for calculating the price of KG-D6 crude -- is too volatile to be acceptable to prospective buyers. Instead of Tapis crude, RIL has proposed that Bonny Light crude should be used as a base to value KG-D6 crude.
 8RIL said that Tapis crude was not actively and freely traded in the market, with most of it being sold on OSP (official selling price) basis to customers. Thus, using this grade of crude as the base for valuation of KG-D6 crude would not be in line with the Terms of Reference for valuation of KG-D6 crude specified by the PPAC (Petroleum Planning and Analysis Cell). Moreover, Platt's assessment of the price of Tapis crude is based on netback calculations and is not the same as the price charged to buyers.
 8To validate their claim, RIL said that even according to Platt's estimates, price of Tapis crude ranged between as low as (-)$6.41 to $8.53 per barrel between January, 2008 and March, 2010. This would be too volatile a price to set as the base for calculating the price of KG-D6 crude.
 8RIL pointed out that all prospective buyers -- including CPCL and HPCL -- had said that Tapis crude was not acceptable to them as the base price for KG-D6 crude. Rather than using Tapis grade, the buyers were willing to bid for KG-D6 crude if its price was based on a differential with Bonny Light crude, which is more freely traded. Moreover, the Platt's assessment for Bonny Light crude price is much more transparent than that for Tapis crude.
 8Reiterating that even though a seller can propose a marker for its crude, RIL said that the potential buyers of the crude should also consider the marker to be acceptable. Hence, the operator has asked Jacobs to change their valuation method in order to make KG-D6 crude price acceptable to potential buyers.
 8Pertinently, Jacobs had suggested two alternative grades of crude, namely Cossack and Gippsland, as possible markers for KG-D6 crude. However, RIL shot down both these options, saying that trade in Cossack crude is linked to Brent (dated) crude, while Gippsland crude prices are rarely reported.
 (Click on Details for more information)   Details

RIL unhappy with Jacobs' methods for valuation of crude-II: Mangla crude price too high for refineries

Sept 2: RIL has alleged that the price proposed by Jacobs for valuation of crude produced from the Mangla field, is too high to be considered feasible by refineries. The private E&P company felt that refineries would not opt for this crude at such prices, instead choosing cheaper grades of crude, which would be detrimental to RIL's interests.
 8Criticising the complex refinery model used by consultancy firm Jacobs to value Mangla crude, RIL said that this method gave the maximum derivable price for crude of a particular configuration. Though a theoretical possibility, such high prices were not feasible for potential buyers, least of all the Indian refineries, which were already reeling under the burden of their huge under-recoveries.
 8To strengthen its argument RIL, has provided comparable data on the proposed Mangla crude price and the prices for the Castilla and Dar Blend grades of crude (which are widely traded on the international market). Both these grades of crude had consistently registered lower average prices (from 2008 to 2010) than that of Mangla crude, even though these grades had very similar physical characteristics.
 8Specifically, in the period between January, 2010 to March, 2010, Mangla crude had an average price of $74.7 per barrel, while both Castilla and Dar Blend crude had lower average prices, at $70.1 and $68.8 per barrel, respectively. In fact, Mangla crude has a 32% higher residue yield than Castilla crude, which should put its price well below that of Castilla crude.
 8RIL has also pointed out that Jacobs has not taken into account the "non-yield" properties of Mangla crude during the valuation exercise. Mangla crude has high pour point (HPP), wax precipitation issues and very high nickel content. These physical disadvantages necessitate additional handling facilities and have operational cost implications. Such factors should also be taken into account while putting a price on crude oil.
 8All in all, RIL has said that at the price arrived at by Jacobs, no refineries would choose Mangla crude, instead preferring to buy cheaper grades of crude which have similar, or even better physical characteristics. Thus the price used to value Mangla crude should take into account the relative competitiveness of such a price with respect to the prices of alternative grades of crude available to refineries.
 (Click on Details for more information)   Details

RGTIL's Vijaywada-Nellore-Chennai Pipeline Project: RoU acquired for 16 villages in Andhra Pradesh

Sept 2: 8RGTIL's plans to lay a gas pipeline from Vijaywada to Chennai have received a shot in the arm after the company recently acquired the Right of User (RoU) in land for laying the pipeline in the state of Andhra Pradesh.
 8The RoU notification was recently forwarded by the petroleum ministry to be published in the Official Gazette of India under Section 6(1) and Section 6 (4) of the Petroleum and Minerals Pipelines (Acquisition of Right of User in Land) Act, 1962.
 The RoU has been obtained for a total of 16 villages in Sri Potti Sriamulu Nellore district of Andhra Pradesh. These villages are: Kothavangallu, Iskapalem, Vavveru, kavetipalem, Panchedu, Penuballi, Minagallu, Zonnavad, Duvvru, Mannavarappadu, Amancherla, Kusumur, Kuricharlapadu, Vadlapudi, Akkamapeta and Madamanuru.
 8The 445-km pipeline is likely to be completed by December, 2011.
 8The pipeline will enable RGTIL to supply natural gas from on-shore gas processing terminal at Kakinada on the East coast of Andhra Pradesh to consumers in various parts of the country.
 8The pipeline project is a part of new trunk pipelines spanning a total length of 5,523 km and authorised by the ministry of petroleum and natural gas to expand the natural gas transportation infrastructure. While GAIL is laying seven new pipelines, RGTIL will be laying two pipelines.
 (Click on Details for more information)   Details

Block RJ-ONN-2003/2: Focus Energy still to record complete wireline logs

Sept 2: Focus Energy Ltd -- the operator of the RJ-ONN-2003/2 block -- has still not completed recording of wireline logs at eight of the ten wells in the block. Notably, the wireline logs for the deepest portions of these wells have been left unrecorded. Without complete wireline logs, the eight wells may not be considered as fulfilling the operator's minimum work programme (MWP) commitments for the block and this would mean that all of Focus' efforts on the block may ultimately be in vain, with the operator having to pay damages for wells which it has already drilled.
 8Pertinently, the operator had recorded wireline logs in only two out of the ten wells by the end of the first extension of phase-I of explorations which was on November 21, 2009. Hence, though Focus had finished drilling 10 wells in the block, it was only these two wells which were considered towards the completion of the minimum work programme (MWP) for the first phase of explorations.
 8It was only during the proposed second extension of phase-I of explorations (up to May 21, 2010) that the operator began recording wireline logs for the remaining eight wells. Notably, the petroleum ministry has still not provided its approval for this second extension.
 8However, the wireline logs for these eight wells are still incomplete, with the logs on the deepest portions of the wells remaining unrecorded. Moreover, as reported previously, the operator has not drilled the wells up to the respective target depths agreed to in the PSC (production sharing contract) for the block.
 8The website carries here details on the intervals in which logs have not been recorded as well as the committed versus actual well depth for each of the ten wells in the block. A few highlights on the incomplete wireline logs are as follows:
 --In the A-1 well wireline logs were not recorded for the entire 448m to 1,166m interval. The well has been drilled to a depth of 1,166m which is 344m less than the committed depth of 1,500m.
 --The Brahma-1 (STC-1) well has not had wireline logs recorded in the 815m to 1,290m interval. The well is also 210m less deep than the depth of 1,500m committed to in the PSC.
 --The JBB well does not have wireline logs recorded in the 851m to 1,150m interval. The well has been drilled to a depth which is 350m less than the committed depth of 1,500m.
 (Click on Details for more information)   Details

Failure of SPM system at Panna oilfield-I: A shocking lack of adherence to safety norms

Sept 2: The committee -- consisting of members from OISD, DGH, ONGC and IOC -- constituted to enquire into the probable causes of failure of the single point mooring (SPM) system located at the Panna Oilfield in the western offshore has been able to identify the deficiencies which resulted in the incident. The SPM system was operated by the PMT JV comprising of ONGC, Reliance Industries Limited (RIL) and BG Exploration and Production India Ltd (BGEPIL). The committee members, after reviewing the inspection and maintenance policies relating to the SPM system, attributed the failure to the following reasons:
 8Non-adherence to proper periodic inspection of the SPM system and its associated facilities:
 --Anchor chains: The committee pointed out that, out of the six anchor chains holding the SPM, three were found to be in vertical position, indicating probability of breakage of these chains. The committee further pointed out that the periodic inspection of anchor chains as required under OISD-STD-139 and OCIMF (The Oil Companies' International Marine Forum) guidelines was not carried out.
 --Sub-sea hoses: After snapping of the anchor chains, the entire load came on to the floating subsea hose string of the SPM system. As a result, the flange joints of the hose string, parted from the PLEM (Pipeline End Manifold). The committee further pointed out that periodic inspection of subsea hose joints with PLEM was also not carried out as required under the guidelines.
 --SPM buoy: Since the installation of this SPM system in 2001, it has not been taken for dry-docking. The dry-dock of the SPM was scheduled in 2006, but it could not be carried out due to operational requirements.
 8In a normal SPM system, the weakest link is supposed to be the mooring ropes. However, in this case it was pointed that the combined strength of the mooring ropes might have exceeded the residual breaking load of each anchor chain. This might have resulted in snapping of anchor chain links instead of the mooring ropes.
 8There was no facility available to monitor the relative position of the SPM system. As such, on breaking of the chain, the SPM drifted apart which could not be noticed either by platform or tanker personnel.
 (Click on Details for more information)   Details

Failure of SPM system at Panna oilfield-II: Committee makes a series of recommendations

Sept 2: The committee members -- consisting of members from OISD, DGH, ONGC and IOC -- after identifying and studying the deficiencies which resulted in the failure of SPM system at Panna oilfield, has recommended as under:
 8Dry-docking of the existing SPM should be taken up at the earliest opportunity.
 8Proper diving vessels should be deployed for carrying out underwater inspection of all facilities attached to the SPM system -- like anchor chains, sub-sea hoses, flange joints, buoyancy tanks and PLEM -- as per the laid down requirements and frequency.
 8The platform and the tanker should be equipped with suitable gadgets to monitor the position of the SPM on a continuous basis.
 8A safety inter-lock, at a preset pressure, has to be provided at the platform end.
 8An anchor chain with sufficient slack and a dead weight anchor to be fixed with the sub-sea buoyancy tank to prevent the buoyancy tank to come up in an uncontrolled manner to preempt the possibility of hitting the SPM buoy / tanker in case of hose parting.
 8The PMT JV should explore the possibility of installing an alternate/stand-by cargo discharge system.
 8Testing of all attachments and equipment associated with the SPM system should be carried out before putting it back in operation.
 (Click on Details for more information)   Details

ONGC's NELP Offshore Insurance Policy for 2010-11: Alarmed after BP oil spill, insurance company attach riders

Sept 2: In light of the BP oil spill, United India Insurance Company Ltd (UIIC) has attached some riders to the NELP offshore insurance policy which it had recently signed up with ONGC.
 8Readers will recall that the E&P major's NELP offshore insurance policy package for 2010-11, covering all NELP offshore wells, was recently renewed for a period of one year (from June 23, 2010, up to June 22, 2011) with UIIC. However, when the insurance company approached the reinsurance markets, it was informed by its broker Marsh that reinsurance companies where finding the placement quite challenging in light of the BP oil spill in the Gulf of Mexico. Marsh informed that the BP incident was a deepwater loss which involved a Transocean rig (dubbed Deepwater Horizon). It pointed out that ONGC's NELP program too has a heavy dominance of deepwater activities -- with 10 of the 19 wells being either deep water or ultra-deep water -- which would also be carried out by rigs owned by Transocean.
 8In light of this, the insurance company attached the following conditions:
 --Re-insurers would carry out a review of all HP, HT wells as well as wells having an AFE cost higher than $60 million. The re-insurers would appoint NRG Well Management Limited or any other competent body for the review.
 --The drilling plans of wells will have to be submitted to re-insurers -- a minimum of 10 working days prior to spudding -- to enable timely review by NRG or third party surveyors appointed by re-insurers and their recommendations (if any) would need to be implemented/complied with prior to spudding of the well.
 8Keeping in mind that well review warranty had become a standard underwriting guideline for insurance companies after the BP incident, the E&P major had no better alternative available, under the prevailing market conditions, then to accept the inception of the policy with the attached riders.
 (Click on Details for more information)   Details

ONGC Briefs

Sept 2: The following is a wrap-up of ONGC briefs:
  8ONGC notified two discoveries to the DGH during the month of July, 2010. These are: exploratory well, GS-21#3 in Vainateyam PML block in Krishna Godavari basin and Well Karannagar-1 in CB-ONN-2004/1 block in Western Onshore basin. The two wells were drilled for a depth of 2,240 metre and 2,019 metre, respectively.
  8ONGC subsidiary, MRPL, signed an agreement with State Trading Corporation, Mauritius, on July 1, 2010, for supply of liquid petroleum products amounting to 1.1 MMT per annum for a period of three years.
  8The 9th ONGC Conclave was organised at Goa during July 10-11, 2010. The meet was attended by 27 former board members, including five former chairmen, along with current directors of ONGC and OVL. The conclave focused on SWOT analysis of ONGC and its future growth strategy.
  8ONGC`s chairman, R. S. Sharma, was part of a high-level government delegation that visited Vietnam for participating in the East Asia Energy Ministers meeting. During the visit, India expressed its interest in participating in the divestment of BP`s stake in the Nam Con Son project -- the largest gas project in Vietnam -- which comprises of two offshore gas fields, a pipeline and power project. At present, OVL has 45% stake in the offshore gas fields, while BP has 35% stake and the balance stake is held by PetroVietnam.
  8The website also carries here production highlights of ONGC for Q1, 2010-11, with regard to crude oil, natural gas, gas sales and VAP production.
  (Click on Details for more information)   Details

BPCL's Mumbai Refinery: Production, sales and inventory data (July, 2010)

Sept 2: 8BPCL processed a total of 1,121,824 MT of crude at its Mumbai refinery during the month of July, 2010. Out of this, 740,767 MT of crude processed was imported while 381,057 MT of crude was sourced indigenously from the Mumbai High.
 8The total amount of imported high sulphur crude processed at the Mumbai refinery during July, 2010, stood at 283,776 MT. This comprised of 253,842 MT of Arab mix crude, 139,693 MT of Murban Crude, 58,422 MT of Upper Zakum crude, 4,503 MT of Kuwait Export crude and 531 MT of Arab Extra Light crude.
 8The refinery also processed 283,776 MT of imported low sulphur crude during the month. This included 205,105 MT of Saharan Blend crude, 65,086 MT of Miri Light crude and 13,585 MT of Champion crude.
 8BPCL had a stock of 239,768 MT of finished petroleum products at its Mumbai Refinery at the beginning of July 2010, and another 1,090,656 MT was produced during the month. This output consisted of 5,973 MT of LPG, 55,689 MT of superior kerosene, 18,794 MT of high aromatic naphtha, 128,503 MT of low aromatic naphtha and 144,884 MT of furnace oil, among other products. 
 8The company dispatched a total of 1,078,110 MT of finished products during the month.
 8The website also carries here analytical data on crude processed at the Mumbai refinery in May, 2010.
 (Click on Details for more information)   Details

Investments made by BPRL in E&P projects abroad: An Update (as on June 30, 2010)

Sept 2: The website carries here, for reference purposes, details on investment made by BharatPetro Resources Limited (BPRL) -- a 100% subsidiary of BPCL -- in overseas projects as on June 30, 2010. The details are provided in a tabular format outlining the name of the country as well as the project, participating interest (PI) of each company, BPRL's commitment in the project and the actual investment made by BPRL in these projects. As on June, 2010, BPRL has invested in E&P projects in a total of seven countries. These projects include:
 8Brazil: Acquisition of Encana Brasil and blocks in Espirito Santo, Campos, Sergipie and Potiguar basins
 8Oman: Block 56
 8Australia: AC/P 32 and WA-388-P
 8East Timor: Joint Petroleum Development Area (JPDA)
 8UK: North Sea 2 blocks
 8Mozambique: Area-1
 8Indonesia: Nunukan block
 (Click on Details for more information)   Details

OIL's crude and natural gas production during July, 2010: Output below target

Sept 2: The website carries here information on the targeted and actual production of crude oil and natural gas and sale of natural gas from Oil India Ltd`s (OIL) fields in Assam, Arunachal Pradesh and Rajasthan during the month of July, 2010, and in the April-July, 2010-11 period.
 8OIL's crude output in July, 2010, was at 0.306 MMT against a target of 0.313 MMT, while the April-July figure was at 1.10 MMT, down from the target of 1.223 MMT. The loss in production was due to ullage arising from a shutdown in the Numaligarh refinery.
 8As with crude, natural gas output fell 17% below the target of 231.63 MMSCM, at 192.16 MMSCM for July, 2010. The production of natural gas during the April-July, 2010, period stood at 744.84 MMSCM against the target of 853.69 MMSCM. This was due to lower offtake by consumers based in the North East.
 8Total OIL+OEG production during July, 2010, stood at 0.495 MMT against a target of 0.529 MMT. The April-July, 2010, figure for the same stood at 1.813 MMT against a target of 2.041 MMT.
 8The company sold 146.77 MMSCM of gas during July, 2010, as against a target of 188.38 MMSCM. Gas sales during the April-July, 2010-11, period, was 569.56 MMSCM as against the target of 685.03 MMSCM.
 8The website also carries here corresponding figures for July, 2009 and the April-July, 2009-10 period, to aid comparison.
  (Click on Details for more information)   Details

Archive