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Jan 2016

To keep up with the operational needs of Mumbai Port, the Port has identified the need for construction of an additional Oil Berth.
 8The estimated project cost for the construction of an oil jetty came out to be Rs. 811 crore.
 8For construction of the proposed Oil Berth, it needs to obtain prior Environmental/Coastal Regulation Zone (CRZ) clearances after conducting an Environmental Impact Assessment (EIA).
 8Currently there are four marine oil terminal berths in operation for the purpose of handling crude traffic. 
 8The jetties/berths are known as JD1, JD2, JD3 and JD4.
 8Of the four berths, JD4 is the biggest in terms of a Design Draft of 14.30 m, Displacement Tonnage of 125,000 T and length of 300 m.
 8The crude oil and POL products are transferred out of Jawahar Dweep through submarine pipelines.
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The Fifth Oil Berth will come up in the Mumbai Harbour near the Jawahar Dweep Island.
 8Proposed location of JD5 is down stream of existing JD4 berth at a distance of approximately 600 m south west of JD4 along the main channel.
 8The crude traffic through the port is primarily to cater the requirement of HPCL and BPCL.
 8The oil companies have been insisting on Mumbai Port that a facility to handle fully laden Suez Max Tankers for crude import be created.
 8Both the oil companies have informed that due to lack of berthing facilities for handling Suez Max and VLCC vessels, they have been incurring cost of Rs. 150 to 170 Crores every year towards additional freights and demurrage to the vessels.
 8The new Oil Berth will cater to the fully laden Suez Max Vessels and Light Drafted VLCC, and the cost of construction will be shared by the two oil PSUs.
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8The proposed development plan has been divided as following:
 -- Unloading Platform
 -- Four berthing dolphins
 -- Six mooring dolphins
 -- Boat Landing and Helicopter Landing Platform including Control Tower Building
 -- Link Bridge to Existing JD4 Unloading Platform
 -- Link Bridge to Existing Pump House
 -- Link Walkways
 -- New Pump House
 -- Approach Bund
 -- Approach Trestle
 -- Submarine pipeline
 -- Capital Dredging for berth, channel, and anchorage
 -- Reclamation at Jawahar Dweep reef of 13 ha. for tankages and buffer stock to meet exigencies.
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The website also carries here year-wise, commodity-wise traffic handled by Mumbai port during last five years.
 8The list includes the import and export data of the following :
 -- Crude oil
 -- POL products
 -- Fertilisers
 -- Bulk Chemicals
 -- Containers (TEUs) Under Import
 -- Containers (TEUs) Under Export 
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The scope of the whole work is categorized into four packages.
 8The list containing the project cost and time period is as follows:
 --Construction of Jetty and Approach Trestle ( Rs. 301.50 crore rover a period of 30 months)
 --Mechanical, Electrical and Fire fighting works( Rs. 202.50 crore over 30 months)
 --Submarine pipeline ( Rs.200.90 crore over 16 months)
 --Dredging ( Rs.106.30 crore for 16 months)
 8The commissioning of the Fifth Oil Berth will be completed in 30 months.
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Bharat Petroleum Corporation Limited (BPCL), is planning to carry out an on-site statutory inspection check of its LPG pipelines at its bottling plant in Surat.
 8The LPG pipelines will be handed over to the agency in stages.
 8Comprehensive inspection of LPG pipelines shall be carried out as per OISD 144 and OISD 130.
 8The following tests will be covered under the inspection:
 -- Visual Inspection
 -- Hammer Test
 -- Ultrasonic Thickness Measurement
 -- Dye Penetration Test Or Magnetic Particle Test
 -- Hydro-Test
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The Supreme Court has directed the PNGRB to re-examine whether GAIL was correct in denying common carrier rights to GSPC for transportation of gas through GAIL-owned Dahej-Vijaypur and Dadri-Bawana-Nangal pipelines.
 8The PNGRB had earlier ruled against GAIL's decision to enforce a "Ship or Pay" agreement on GSPC to access the pipelines after the latter filed a complaint with the regulator. The PNGRB had ruled that GAIL's conduct amount to a discriminatory trade practice and imposed a fine of Rs one lakh on the public sector gas major.
 8GAIL then went to the Supreme Court after the Appellate Authority also ruled in favour of the PNGRB.
 8GAIL's contention was that it was always ready and willing to provide common carrier service to GSPC on a "Firm Capacity Tranche" or "Ship or Pay" basis while simultaneously contending that there was no statutory provision for booking of capacity in a pipeline on reasonable endeavour basis and such a demand for booking a particular amount of gas for 11 months was wasteful in the sense that the un-utilized  amount of gas capacity must be paid for by the user as this could not be diverted to any other shipper.
 8It looks like the Supreme Court saw merit in GAIL's argument and directed the PNGRB to re-examine whether the regulator's Affiliate Code of Conduct for Entities Engaged in Marketing of Natural Gas and Laying, Building, Operating or Expanding Natural Gas Pipeline) Regulations, 2008 is really applicable in this case or not.
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China's CNOOC is one of world's largest oil and gas companies and it has taken bold steps to face the crisis brought about by the fall in oil prices.
 8The company has cut its capex from a high of 107 billion RMB to 67 billion in 2015. In the current year, it is budgeting to bring its capex down to less than 60 billion RMB.
 8This is a massive cut in budget.
 8The capex cuts have been made across the board, impacting exploration, development and production segments. It has put together a strict investment matrix in all three segments.
 8While capex has been cut, CNOOC is trying hard to keep its production target intact for 2016 at around 470-485 mmboe.
 8More importantly, CNOOC has cut all-in costs and the curve which was pushing upwards has now begun to decline.
 8Opex had scaled a high of $12.22/boe in 2014 but was forced down to $9.60/boe by the first half of 2015.
 8The Chinese giant was able to fully leverage the deflation in supply chain, while continuing to lower cost and increase efficiency through technology and management innovation.
 8Three-year production rolling targets show output going up, albeit slowly.
 Comment: The petroleum ministry must conduct a review of the performance of ONGC and OIL keeping in mind the kind of cost cutting exercise that CNOOC has been able to conduct. It is difficult to compare ONGC with CNOOC as the dynamics are different, but are the Indian NOCs taking full advantage of the fall in the cost of equipment and services or are they taking cover under the guise that their contracts are fixed cost in nature and they are helpless to change them? CNOOC too will have similar contracts but it has reduced its opex drastically. Why shouldn't ONGC and OIL not bring about similar cuts.
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In these depressed times, there is one E&P company which still believes that the going is good. And that is HOEC.
 8Profit before tax has moved into the positive territory, growing 10 times, albeit on a very small base between Q2 and Q3 2015-16.
 8The company boasts a debt free balance sheet where operating revenues are capable of meeting opex and G&A expenses.
 8What is more, it is excited about the future, particularly on its Assam block, AAP-ON-94/1, where gas has been found, and where final environmental clearance is coming through shortly. The company led JV in the block spent $85 million in exploration and appraisal.
 8The GIIP figure in the block is 244 BCF while the recoverable reserves are at 134 BCF. The output is expected to be around 20 mmscfd, with a plateau of 15 years.
 8The block is expected to go on stream by Q4 2016-17.
 8Importantly, the company has a low production cost and it can make good money on government determined prices.
 8What has come as a boost is that the subsidy on gas price in the North East -- the company is signing a deal for sale of gas to the Brahmaputra Gas Cracker -- will be extended to the private sector and HOEC is going to be a big gainer of  this policy.
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The point to note is that those companies who hold low risk onshore assets have a low cost of production and are therefore able to withstand the crash in crude prices.
 8HOEC has such assets not just in Assam but also in Gujarat.
 8The company in fact has expertise in managing marginal fields. Its netbacks are attractive in its marginal fields of North Balol, Asjol and CB-ON-7.
 8More E&P work is expected to take place in these blocks given the positive netbacks.
 8HOEC also holds a 38% stake in CB-OS/1 in the ONGC operated block. The field is in the west of the prolific Gandhar field of ONGC. The expected field life is 10 years with a peak production of 8,000 barrels per day. The development plan is currently under revision given the fall in crude prices.
 8In the PY-1 field, HOEC has invested around $400 million Water cut caused a steep decline in production and current output is at 2 mmscfd, but Q 3 revenues were significantly positive in relation to opex..
 8The only block where there is trouble is the shutdown of the PY-3 field in 2011. HOEC Is now waiting for what it calls "an opportunity to develop the field with optimized cost and appropriate price regime".
 8What is next from HOEC? It is now waiting to participate in the auction for marginal field. It claims to have to expertise to handle these fields like no other operators. Expect HOEC to bid aggressively once the bids are out.
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GAIL's objection to GSPC's request for booking of capacity in its pipelines for 11 months on a "reasonable endeavour" basis and not on a "Firm Capacity Tranche" or "Ship or Pay" basis was that such a request would block other shippers who might be willing to book capacity on a firm CT or ship or pay basis even if GSPC did not utilize the booked capacity itself.
 8The gas major argued that this would set a dangerous precedent in the pipeline business wherein everyone will start booking common carrier capacities on "reasonable endeavour" basis and the actual user, who wants to book on a firm basis will be deprived of capacity on the rationale that it was blocked by the first come first serve booker.
 8GAIL went on to argue that such contracts would  reduce investments in pipelines as it would not be feasible financially if someone were to merely to book capacity without a commitment to use it.
 8On the other hand, GSPC had argued that regulations specifically mandate that the common carrier capacity should be provided in an open access format and that access cannot be restricted by take or pay provisions.
 8GAIL was accused of transporting its own gas to customers without paying ship or pay charges while imposing the penalty on GSPC.
 8Eventually the regulator held that GAIL was working in a discriminatory manner by insisting on ship or pay terms for a common carrier capacity when that capacity should be kept free for use by any third party.
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Crashing crude prices has not adversely impacted domestic crude production much with production in December 2015 standing at 3.07 MMT, which was just 1.38 percent lower than the planned monthly target.
 8Cumulatively, crude oil production during April-December, 2015 was 27952.376 TMT which was 1.07 percent higher than target for the period and 0.79 percent lower than the production during corresponding period last year.
 8ONGC was able to stick to target, with its production during the month of Decemberdown only 0.47 percent than the target for the month and just 0.06 percent higher than the production achieved in the corresponding month  last year.
 8The shortfall in ONGC’s production mainly came from Gujarat regions: in Mehsana, les air injection in the Santhal field, increasing water cut in the down dip wells of N Kadi field and an increase in sick wells caused production to stay low.
 8In Ahmedabad too, poor influx, from the Gamij Field and less than envisaged production from Nadiad and Vadatal in Cambay led to a decline in production.
 8Cumulatively, production during April-December, 2015 was 16883.815 TMT which was a marginal 0.30 percent lower than the cumulative target and 0.96 percent higher than the production registered during the corresponding period last year.
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OIL’s crude oil production during December, 2015 was 2.70MMT which is 12.41 percent lower than the target for the month.
 8The production was also 6.30 percent lower than what was achieved in the corresponding month of last year.
 8The rise in water cut in wells of Shalmari, Greater Chandmari and in Greater Hapjan fields contributed to lower production.
 8Cumulatively too, production during April-December, 2015 was at 2.450MMT which was 8.33 percent lower than the cumulative target.
 Private and JV output
 8Pvt. /JV crude oil output during the month of December stood at 0.913 MMT which was 0.45 percent higher than the target for the month.
 8Output couild have been higher but for the shutdown of Cairn's Mangla processing terminal and the natural decline in Ravva and Mangala fields leading to lower production volumes.
 8Less production from the Panna-Mukta fields, a JV of ONGC, BG and RIL due to a shutdown and under performance of wells in the KG D6 block caused a major shortfall in production.
 8Cumulatively, production during April-December, 2015 was 8617.949 TMT which iwas 7.08 percent higher than the cumulative target and 2.86 percent lower than the production during the corresponding period of last year
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Natural Gas production during the month of  December, 2015, at 2736.990 MMSCM, was 9.30 percent lower than the target for the month and 6.09 percent lower than the production during corresponding period of last year. 
 8ONGC’s output during the month was 1818.978 MMSCM which was 11.65 percent lower than the target for the month and 4.16 percent lower than the production achieved in the corresponding month of last year.
 8The lower production could be attributed to the closure of wells due to unplanned shut down of GAIL;s gas line from Ahmedabad/Kalol to Ramol.
 8Moreover, closure of 42 wells in Andhra Pradesh also contributed towards lesser production as the GAIL's pipelines in Tatipaka-Lanco  and Endamaru-Oduru sections are still under repair.
 8The decline in associated gas production from the South Kadi & Gamij fields in Gujarat and from Geleki & Lakwa fields in Assam led to the overall reduction.
 8ONGC’s cumulative natural gas production during April-December, 2015 was 16272.130 MMSCM which was 8.50 percent lower than the cumulative target and 1.96 percent lower than the production during the corresponding period of last year.
 8Overall the cumulative natural gas production during April-December, 2015 was 24697.304 MMSCM which was 6.32 percent lower than the target for the period and 2.76  percent lower than the production during corresponding period of last year.
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8Pvt. /JVs’ natural gas production during December, 2015 was 651.910 MMSCM which was 6.81 percent lower than the target for the month and 16.91 percent lower than the production achieved in the corresponding month of last year.
 8The underperformance of RIL's MA wells and less production in Panna Mukta of BGEPIL due to shut down PPA platform for a riser repair job coul dbe attributed to the decline in production.
 8Cairn's non-associated gas producing well LB-7 also watered out prematurely in the CB-OS2 block and this contributed to lower production.
 8Cumulatively, private and JV natural gas production during April-December, 2015 was 6305.113 MMSCM which was 0.05 percent lower than the cumulative target and 6.48 percent lower than the production during the corresponding period of last year.
 8On the other hand, Oil India Ltd's natural gas production was 2.65 percent higher than the target for the month and 14.66 percent higher than the production achieved in the corresponding month of last year.
 8Production could have been higher still but for line capacity constraints in supply of gas to the Lakwa power plant and the delay in the commissioning of the Assam Gas Cracker unit and lower offseaon offtake by tea gardens in Assam. 
 8Overall, natural gas production during April-December, 2015 was 2120.061 MMSCM which was 6.64 percent lower than the cumulative target and 3.00 percent higher than the production during the corresponding period of last year.
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Indian refineries posted a strong performance in December, 2015 with a throughput of 20.146 MMT which was 3.94 percent higher than the target for the month and 2.13 percent higher than the production during corresponding period of last year.
 8The production from the PSU refineries during the month of December was 10.84 MMT which was marginally highe r(0.91 percent) than the target for the month but 2.83 percent higher than the production achieved in the corresponding month of last year.
 8Lower crude availability in the regions of North Gujarat and Assam was the main reason which led to the  decreased throughput from the IOCL's Gujarat and Digboi refineries.
 8CPCL, Manali  refinery also recorded lower throughput on account of a shutdown due to unprecedented rain and floods during first week of December.
 8Similarly, CPCL[s Narimanam refinery fell short of its target as RCO/LSHS movement to Manali Refinery was affected due to floods and its CDU unit took a shutdown.
 8Cumulative production of PSU refineries during April-December, 2015 was 91.95MMT which was 0.71 percent higher than the cumulative target and 2.40 percent higher than the production during the corresponding period of last year.
 8The production of JV refineries during December, 2015 was 1.436 MMT which was 13.80 percent higher than the target for the month and 1.08 percent lower than the production achieved in the corresponding month of last year. 
 8Private refineries  also witnessed a growth rate of 6.67 percent which was higher than the target for the month and 1.77 percent higher than the production achieved in the corresponding month of last year.
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RIL's E&P business has posted an operating profit of Rs 90 crore in the third quarter of 2015-16 on revenues of a mere Rs 1,765 crore in comparison to a PBIT of Rs 242 crore on revenues of Rs 2,841 crore in the previous .
8Net margins are negative for RIL in the E&P segment
8The decline in revenue was led by lower upstream production in domestic blocks coupled with sharply lower oil and gas prices in both the domestic and US shale segments.
8Domestic gas prices for KG-D6 production was $ 3.82/MMBTU on GCV basis, while average US shale realization was down 50% Y-o-Y to $ 2.81/MCFe in the July-Sept 2015 period.
8The unfavourable upstream price environment impacted segment EBIT, which was 89.2% lower on Y-o-Y basis, at Rs 90 crore.
8Given such poor performance it remains a moot point whether Mukesh Ambani will be willing to pump in more money just yet in his KG Basin discoveries even if gas prices were freed and made market linked.
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The government of India had intervened in favour of the domestic shipping lobby to ensure indigenization of at least three LNG vessels of the nine that GAIL plans to order.
 8This fits in well with India's Made in India programme but the cost and benefit of such a plan needs to be taken into account.
 When the indigenization idea was first mooted to Japanese and Korean shipyards, they were horrified at the prospect of building a vessel in an Indian shipyard.
 8Cynics had put forward the following reasons why Indian shipyards may not be able to deliver:
 8Foreign ship builders who inspected the Indian shipyards were not confident of the quality of the ships to be manufactured in India and were therefore not ready to guarantee the performance of the ships for a 20 years contract period.
 8Since manufacturing an LNG ship is a capital intensive project and more than 80% of ship cost is financed through financiers with stretched repayment periods, the lenders would be averse to take such large exposures in India.
 8The foreign ship builders were also concerned that shipyards willing to build ships in India were mostly from private sector and would have no direct government control and guarantees. The question that was asked was whether the government would support ship owners in case of cost overrun and delay in delivery of ships built in India.
 8Plans to develop the Indian LNG shipbuilding industry should have been set in motion at least 5 years back.
 8The long-term agenda of developing the capabilities of Indian shipyards is sought to be mixed with the short-term agenda of acquisition of ships against GAIL`s tender.
 8Even if Indian shipyards secure foreign collaborations, there is no clarity with regard to the extent of support they would receive from a qualified foreign shipyard and whether the foreign shipyard would guarantee performance of these ships.
 8Indian shipyards should invest in acquiring technology and building infrastructure well in advance to demonstrate skill sets backed by technology transfer in totality from reputed overseas shipyards which have the requisite experience in building LNG ships.
 8Then again, the main question is whether just building one ship in an Indian shipyard will qualify that shipyard to build more such ships.
 8What if no repeat orders are forthcoming subsequently?
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There are also question marks over the capability of some of the shipyards to build sophisticated LNG vessels.
 8Already, L&T has announced that it is not interested in building a vessel because of the clause that requires shipyards to hold equity stake of as much as 13% in the LNG carriers that are to be built locally.
 8This leaves only two shipyards -- Pipavav Defence and Offshore Engineering Co. Ltd (PDOECL) and Cochin Shipyard Ltd -- in the race for building the ships.
 8Cochin Shipyard had signed a deal with French technology company Gaztransport & Technigaz (GTT). GTT, which holds a patented technology for LNG ships, that encompasses the giving of designs, engineering and supervision for building of the cryogenic carriers as also performance guarantee for the ship.
 8The potential of the other shipyard -- PDOECL -- is suspect given that it had messed up the construction of 12 offshore supply vessels (OSVs) that ONGC had contracted to the shipyard for Rs 736 crore. Building LNG vessels is a far more complicated job than constructing OSVs.
 8The original completion date for the OSVs was September, 2011 but the delivery dates rolled over to 2015, a stupendous delay of three years and three months. 
 8Many things have gone wrong with the OSV contract, including delay in preparation of drawings and delays on account of requiring to conduct additional model testing of the hull of the OSVs in Austria.
 8Clearly, the company had little or no experience in building OSVs. In this context, it remains a moot point whether the shipyard will have any capacity at all to be able to build LNG vessels.
 8At the end of the day, the construction of the ships have been delayed so much so that they will not be in a position to take on cargoes that GAIL is obliged to pick up from the US.
 8Only time will tell how this whole story is going to unwind.
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This website seeks to argue that India should set aside security concerns and push through as many online or deepwater gas pipelines as possible, either from Turkmenistan or Iran or other Gulf countries.
 8India in turn should build a strong network of LNG gasification terminals with a reasonable amount of spare capacity as a counterweight measure. Another purpose for which the spare capacity can be built is to assuare long term demand for gas.
 8This spare capacity can then theoretically be put to use in case security issues lead to a shutdown of any or all of the pipelines.
 8The same LNG spare capacity can be used as a bargaining chip to ensure continuous supply of gas through these pipelines and keep pipeline based gas prices under check.
 8Even as India builds downstream capacities attached to the gas to be delivered via the pipelines, countries such as Iran and Turkmenistan will also be required to build upstream capacities and the attendant evacuation facilities to feed the pipeline network.
 8Disruptions from the supply side will then become more costly to the supplier of gas, for it will not be as easy to put the committed gas to use elsewhere as it will be for India to start receiving spot LNG supplies to make up for the shortfall.
 8While gas supplying countries will have little provocation to disrupt supply, this may not be the case for state and non-state players in transiting countries such as Afghanistan and Pakistan where the stakes will not be as high as those of the actual supplier of gas.
 8Here again, besides the loss of hefty transit fees, what will work as a deterrence is the awareness that spare LNG capacity can be brought to use in case of a supply disruption.
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The focus of the global gas market has shifted to how gas prices behave in the United States and while there are many who claim that gas prices are going to keep sliding down, there are those who believe that a recovery is just around the corner.
8The market in 2015 had remained structurally over supplied because of:
-- Year on year growth in associated gas production from shale oil output
-- Continued growth of the low cost Marcellus and Utica shale fields, albeit at a slower pace
-- This was however combined with the strongest demand growth since 2010 led by gas based power plants in the US
-- Extremely warm autumn/early winter 2015, depressing heating demand for gas and pushing the price below $2
8The point to note is that the average 2015 natural gas price of $2.63 was well below the marginal cost of supply of $3.50. 
8This excess in production over demand cannot continue indefinitely with natural gas trading because of the following reasons:
-- Reduced capital spending by the producing companies
-- Growing natural gas demand stimulated by the low gas price creating a new market equilibrium
8The outlook for natural gas in 2016 is likely to be defined by a number of factors:
--Rebalancing the market so that there is a price recovery to around $3/mcf as excess inventory gets depleted by greater demand
--Continued growth of supply in the Marcellus/Utrica fields
--Steady replacement of coal utility fleet by new gas-fired electricity generation plants
--Declining associated natural gas production
--LNG exports through Sabine Pass capacity of 2.2 Bcf/day in 2016 and other LNG export facilities with capacity of 10.1Bcf/day in 2019
8The outlook for growth in world oil supply for 2016 and beyond is deteriorating as a result of low oil prices.
8Non-OPEC producers are suffering a tremendous activity cut leading to stagnating supplies in 2016 and significant reduction in new project supply in 2017.
8All of these factors are likely to push gas prices up.
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The gas supply dynamics in Europe provides an appropriate example of how LNG spare capacity works as a deterrence to either blackmail or over charging of gas supplied by Russia through an onland pipeline network.
 8In general, the economics of gas trading via seaborne LNG transport are more advantageous relative to pipeline trading if the transportation distance is more than 4000
 km, which allows for shipping super-cooled gas across continents at a lower cost than if using pipelines.
 8Both the Iran-Pakistan-India and the Turkmenistan-Afganistan-Pakistan-India pipelines are below the 4000 km mark. The landed cost of gas will be lower than long term LNG price.
 8Then again, supply diversification will work to keep both long term LNG suppliers as well as onland suppliers in competition with each other to keep prices under check.
 8The website wants to argue that for India to create a large enough bargaining base on both ends of the spectrum, it must encourage as many online pipelines as possible, without being overtly troubled with security issues. To financially de-risk such investments, non-recourse funding of pipeline projects will be the best way out.
 8Once a pipeline is built, there will be a significant number of players who get financially involved down the line and it will be in their interest to keep the gas supply lines open.
 8The website carries here appropriate data to show that the investments made in putting up spare LNG capacity as a counter weight to pipeline gas supplies are more than made up by the price bargains that such an arbitrage provides by playing off both LNG and online suppliers.
 8What is more, the spare LNG capacity will not go waste as it can be used for hedging and arbitrage opportunities as is the case with similar terminals in Europe.
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It is no doubt risky to rely on LNG to fill supply shortfalls or to meet peak demand.
 8Industry insiders say that one reason for this pessimism is that, on average, it would take at least two weeks to attract an unscheduled LNG cargo.
 8Due to the specifics of LNG technology and the industry setup (long-term contracts), relying on the LNG industry as a source to meet supply disruptions and shortfalls is less attractive than pipeline gas.
 8LNG production is limited by the export capacity of existing LNG projects as well as outstanding long-term contractual commitments that are prioritized over short-term sales.
 8But flexible volumes are likely to go up. In 2014, it accounted for about 26% of total LNG production.
 8Eventuality flexibility would depend on the strength of recovery of gas demand elsewhere and ramping up of export infrastructure in a low oil price environment.
 8Out of around 400 LNG tankers in operation today, only around 30 are available for spot trading as of August 2015. This availability is likely to shrink further as some vessels are awaiting the starting-up of the long-term projects for which they were built.
 8There is no mechanism to ensure that sufficient tonnage will be available in a market facing a severe demand crisis. Re-directing a vessel from a long-term project to spot trading typically requires a buyer to absorb optimisation costs. In fact, LNG is probably the most expensive commodity when the mid-stream is reflected as a percentage of the cargo’s costs.
 8In this context, the lesson that was learnt from the European example was that its LNG spare capacity was used more as a bargaining chip with the Russia to keep the price of gas supplied via pipeline down.
 8Some of the LNG capacity was utilized in the re-export trade, whereby LNG volumes were re-loaded at terminals in Spain, France, Belgium and the Netherlands and exported to other global buyers. About 5 million tonnes of LNG was re-exported from the EU in 2014. The reload operations were carried out largely to take advantage of arbitrage opportunities from buyers in other geographies.
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It is in this context that it is important to understand GAIL's options with 5.8 MMTPA per annum of LNG cargoes  -- 3.5 MMTPA with Sabine Pass terminal and the other for 2.3 MMTPA from the Cove Point terminal.--that the gas major has booked through US LNG terminals for delivery from 2017-18 onwards.
 8The company's upfront commitments are high: With Sabine Pass for example, GAIL has a 20-year deal. And the deal is that GAIL will pay a fixed cost of $3/mmbtu and an LNG cost pegged at 115% of the Henry Hub price.
 8The cargoes were meant for delivery to India either by way of swaps or directly from the US but it looks like West Asian suppliers like Qatar may under price their cargoes just below GAIL's cost of delivery to India.
 8The other option is for GAIL to get customers in India who are willing to enter into long term arrangements against US supplies. But given the uncertainties ahead, it will be difficult to rope in such customers soon.
 8In the absence of long term contracts in India, GAIL may be forced to look for term contracts outside of India, in unfamiliar markets.
 8Or it has to become an LNG trader, hedging its bets and looking for the next opportunity wherever it occurs.
 8All of this will require a level of sophistication that GAIL lacks at this juncture.
 8Given that the market for LNG is still less than 50 active participants, the commodity is not heavily brokered and most transactions are concluded on a bilateral basis.
 8The short-term market is dominated by portfolio suppliers such as Shell and BP, as well as several Japanese trading houses—Mitsubishi, Itochu, Marubeni and Mitsui—and commodity traders like Trafigura, Vitol and Gunvor.
 8Large producers will typically also engage in spot trading but more as a way of optimising their existing supply positions than of focusing on short-term risks and profit opportunities.
 8Due to high entry costs and associated financial risks, there have been several instances where companies have ceased LNG trading operations.
 8The least successful and short-lived strata of commodity trading in LNG have been banks and financial traders.
 8If Qatar is successful in unhinging GAIL from the Indian market, then it will be an uncertain road ahead for the companyL. Saddled with a massive commitment, it will have to work very hard indeed to find markets for its cargoes. 8And the situation will be doubly difficult if there is cut throat competition, with producers and terminal owners willing to sell at any cost above the variable cost.
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The uncertainty over GAIL's orders for its own fleet of LNG vessels to ferry its cargoes from the US can have dangerous repercussions for the Indian gas major.
 8The tender for submission date for nine ships have been extended to February 29, 2016. If orders are placed now, the ships are unlikely to be ready for delivery to take in GAIL's cargoes from the US from December, 2017, as these ships take between 30 to 36 months to deliver from the date of LOI.
 8There is now unconfirmed talk of postponing the orders till 2021 but that will imply that GAIL will have to depend on floating and unattached LNG vessels to ferry its cargoes.
 8There are currently a total of 431 LNG tankers which are used for international trade. This number also includes floating storage and regasification units (FSRU) which,while they can be used as conventional tankers, are designed to act as floating LNG terminals. 142 vessels are on the order books with shipbuilders and expected to be added to the global fleet within the next five years.
 8Most LNG tonnage has been ordered to service specific production projects, and is commonly referred to as project tonnage. The cost of building an LNG carrier has varied dramatically due to fluctuations in global steel prices, technical specifications and carrying capacity. The cost of a new-build usually varies from $200-$250mn for a conventional vessel. Most LNG carriers are built in either South Korea or Japan. Due to the comparatively high cost of LNG ships, very few ship-owners have ordered vessels on a purely speculative basis.
 8Of 142 tankers on the order books, only 18 are being built without a long-term commitment from a charterer. In terms of the existing global fleet, less than 5% of the
 existing fleet has been built on a speculative basis. Rather than servicing any particular production project, the owners of these vessels target mid-term, short-term and spot markets.
 8If GAIL by postponing its tender is banking on uncommitted vessels to take on its load, it is too big a risk to take.
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Tonnage built and designed to service specific LNG projects will typically have a long-term charter agreement signed between the owner of the tanker and the operator of the project. The charter agreement will stipulate, firstly, the charter rate, which is typically expressed in dollars per day ($/day), servicing agreements, conditions for sub-chartering the tanker and so on.
 8In case GAIL does not have its own fleet, it will also have to look at the sub-charter market which aims to deal with imbalances on the global LNG market.
 8There are several scenarios under which the operator of a project may consider offering project tonnage on the sub-charter market.
 8These could include prolonged production outages at an LNG plant, lower-than-expected production or force majeure conditions experienced by project offtakers.
 8Depending on the market conditions, a sub-charter rate may be lower or higher than the long-term charter rate.
 8Since 2010, LNG shipping has gone from feast to famine on several occasions. While a long-term charter rate is typically locked for the period during which a vessel is expected to service the project, which normally ranges between ten and fifteen years, short-term or spot rates fluctuate with the movements of the market and are therefore indirectly exposed to the price of LNG.
 8During strong seller market periods, such as the one following the aftermath of the Fukushima incident in Japan, spot charter rates have reached highs of $140,000/day, whereas when the market hits bottom due to oversupply the very same vessel could attract only $25,000/day.
 8It should be added that all LNG carriers face operational costs which range from $30,000-$40,000/day. These costs include items like crewing, insurance, technical servicing and finance re-payments. It is not uncommon during bear markets to see charter rates fall below operational costs as long-term charterers attempt to minimize their daily losses. In any scenario, idling an LNG carrier is an expensive exercise that costs about $1,000,000 per month. Hence, shipping optimization aims to minimize idling time.
 8With a long term LNG offtake commitment, it is near impossible for GAIL to survive on the vagaries of floating LNG vessels -- either through sub charter deals or by way of uncommitted vessels -- to take care of its transport requirements.
 8Sooner rather than later GAIL will have to fix its own fleet of vessels.
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News that solar tariffs have fallen to an unprecedented low of Rs. 4.34 / kWhr through reverse auction for one of six projects of 70 MW each to be put up in Rajasthan under the National Solar Mission does not augur well for the oil and gas industry.
 8When solar tariff rates fall below that of gas fired projects, the need for gas based power will only be for peaking power requirements.
 8This is because solar power is intermittent in nature and stays unsupplied at night.
 8A subsidy based regime is unsustainable in the long run, so in that sense even though gas prices have fallen sharply, the viability of gas based power plants in India remain in doubt.
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The question now is: “for how long does Saudi persist with this strategy?” It is a very expensive strategy in the near term (Saudi Arabia is forecasting an $87bn deficit in 2016 even after cutting spending by $36bn), but it is one that is clearly achieving its stated objective. There is a reasonable chance that Saudi Arabia, potentially with Kuwait and the UAE, start to quietly hold back some production later in the year at about the time that global oil inventories start to peak.
 8For the time being, even as Saudi Arabia pumps record volumes of crude and Iran steps into the market with large unreleased volumes, US onshore oil production, having grown at 1?1.5m b/day per year between 2010 and 2014, is likely to register a production decline of around 0.3m b/day in 2016. US onshore production has declined by 0.4m b/day over the last six months, and an annual decline rate of 0.8m b/day – a dramatic change in twelve months.
 8Non?OPEC (excluding US onshore supply) output is likely to be down 0.2m b/day in 2016 versus 2015, and that rate of decline will increase in 2017 to around 0.5m b/day. After this, there is a reasonable chance that non?OPEC (ex US) oil production will decline more sharply and if oil prices remain low in 2016, the slate of new projects starting in 2018/2019 will be very poor indeed. Brazil and Russia contribute the major part of the potential new supply.
 8After falling 25% in 2015, the expectation is that  capex for the region will be down a further 15% or more in 2016 (based on $60 Brent in 2016). Without a recovery in oil prices, the expectation is that the same trend will continue again in 2017, yielding a compound decline in capex of around 50% from its peak. This is substantially bigger than the capex decline of 25% witnessed between 2008 and 2009 when the financial crisis took place.
 8Tumbling rig rates and seismic rates plus general cost deflation means that planned expenditure will go further, but even allowing for this there is a substantial shortfall in ‘new project’ production coming from 2017 and beyond.
 8Oil demand in 2015 was around 1.8m b/day, the highest growth in five years, but then in 2016, demand growth is likely to be of the order of 1.2m b/day.
 8The assumption is that the slowdown in production will be faster than that of demand, thereby eating into the current inventory levels of oil.
 8A tightening of the market is therefore expected around the end of 2016.
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The biggest piece of the $328.9bn invested in clean energy in 2015 was asset finance of utility-scale projects such as wind farms, solar parks, biomass and waste-to-energy plants and small hydro-electric schemes. This totaled up to $199bn in 2015, up 6% on the previous year.
8After asset finance, the next largest piece of clean energy investment was spending on rooftop and other small-scale solar projects. This totaled $67.4bn in 2015, up 12% on the previous year, with Japan becoming by far the biggest market, followed by the US and China.
8The following national trends have been observed in 2015 with respect to clean energy:
-- China, the largest investor, witnessed a 17% increase in investment to $110.5bn
-- US being the second biggest investor was up 8% to $56bn.
-- Europe as a whole saw lower investment down by 18% on 2014, with UK being the strongest market at $23.4bn, Germany - $10.6bn, France - $2.9bn
-- Brazil's clean energy investment dipped 10% to $7.5bn on account of the ongoing economic crisis.
-- India gained 23% to $10.9bn but remains a far cry from Modi Government's ambitious plan
 
-- New markets include Mexico ($4.2bn, up 114%), Chile ($3.5bn, up 157%), South Africa ($4.5bn, up 329%) and Morocco ($2bn, up from almost zero in 2014).
Comment: Investment in clean energy has a negative impact on fossil fuel demand and prices. The two are not substitutable but more clean energy means less demand for gas based or oil based power generation. This works it way into the pricing of fossil fuels, albeit in a slightly indirect manner.
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Clean energy investment has increased significantly in China, Africa, the US, Latin America and India in 2015.
Investments totaled up to $328.9 billion (bn), up 4% from last year.
8The good sign is that investments have grown six times since 2004 despite four adverse influences, including
-- decline in the cost of solar photovoltaics
-- the increasing strength of the US currency
-- the continued weakness of the European economy
-- the plunge in fossil fuel commodity prices
8Wind and solar power are now being adopted in many developing countries as a natural and substantial part of the generation mix because it:
-- can be produced more cheaply
-- reduces a country's exposure to expected future fossil fuel prices
-- can be built very quickly to meet unfulfilled demands for electricity
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Iran will be able to sell its oil and gas production without any restraint subsequent to the lifting of western sanctions on January 17, 2016.
 8With the lifting of sanctions, 38 million barrels of oil which are in Iran’s floating oil reserves, in the Persian Gulf, will be added to the international markets besides an additional production of 500,000 barrels of oil per day (bpd) over and above its existing exports of 1 million barrels per day.
 8However, post imposition of sanctions, dozens of Iran’s oil wells were mothballed and bringing them back to production would involve fresh investment.
 8Accordingly it is estimated that over and above the aforementioned 1.5 million barrels of oil per day, an additional 250,000-500,000 bpd could enter the markets in the latter half of 2016.
 8The additional production of Iranian oil assumes significance considering the already oversupplied market and weaker than expected demand and would have a further dampening effect on crude oil prices.
 8With the decline in crude oil prices, spot prices of LNG are also expected to trend downwards in order to retain competitiveness with crude derived alternate fuels.
 8Besides the current and near term increase in production, it is pertinent to note that Iran holds about 9.3% of the global oil reserves and 18.2% of the global gas reserves. While exploiting these reserves, which require significant capital expenditure, it nevertheless indicates the potential to ramp up production over the long term.
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The IEA is pushing for a new way of storing carbon dioxide in oil and gas reservoirs. 
8The method has been dubbed as EOR+, wherein traditional CO2 pumping (usually with water) used worldwide in Enchanced Oil Recovery (EOR) schemes is fine tuned to pump in significantly higher levels of CO2 than is conventionally required to produce oil and gas.
8In other words,  EOR+ involves injecting more CO2 per barrel of extra oil recovered than is the practice today. 
8According to the IEA,  EOR+ practices can result in net emissions savings, as the amounts of CO2 stored would be vastly more than the additional CO2 resulting from the combustion of the recovered oil.
The EOR+ involves taking at least four extra steps involving:
8Additional site characterisation and risk assessment about the reservoir’s cap-rock and geological formations, as well as abandoned wellbores, to assess the potential for CO2 leakage.
8Extra measurement of venting and fugitive emissions from surface processing equipment.
8Monitoring and enhanced field surveillance to assess that the reservoir behaves as anticipated.
8Changes to abandonment processes to assure long-term containment of injected CO2, such as plugging and removal of the uppermost components of wells so they can withstand the corrosive effects of CO2-water mixtures.
8CO2-EOR operators would need sufficient incentive to offset the costs of  the extra steps for EOR+: that could be accomplished through carbon pricing or linking the regulatory framework for oil production to that for tackling climate change.
Comment: EOR+ can be an interesting area of study for the research arm of companies such as ONGC. Now that carbon pricing is likely, ONGC can take up EOR+ schemes in many of its EOR projects around the country. The cost economics can be worked out by the company and a paper can be forwarded to the government for possible policy options. The cost of procuring the additional CO2 and pumping it underground will have to be lower than the carbon price for the whole project to be viable. Details
India stands to gain from free access to Iranian crude oil supplies.
 8A decline in crude oil price is positive for the current account deficit as India imports about 80% of its crude oil requirement, as well as the petroleum subsidies as domestic fuels i.e. LPG (domestic) and Kerosene remain subsidised. Every one dollar decline in international crude oil price reduces the import bill by about Rs 6550 crore and the gross under recoveries by Rs 800 to Rs 900 crore.
 8A lower crude oil price is also positive for the Indian downstream companies due to lower working capital requirements and lower under recoveries (for the oil marketing companies).
 8Besides, Iran being one of the geographically closest neighbours leads to lower freight costs for crude oil imports as compared to Africa or South America.
 8Additionally Iranian crude was also attractive for the India refiners owing to sops that Iran offered such as concessional pricing and 3 month credit period as against 1 month credit period which is the norm in the industry. These sops significantly buttressed the GRMs of the Indian refineries and aided their liquidity.
 8Whether the sops would continue remains to be seen, however with India’s huge oil requirements and the Iranian leadership’s emphasis on increasing production and market share, it is expected that Indian refiners would continue to enjoy favourable terms.
 8The decline in crude oil prices would be negative for the upstream companies like Oil and Natural Gas Corporation, Oil India, Cairn India as their realisations on crude oil sales would also decline, though the impact would be partially offset by the lower under recoveries. Additionally with the Indian Upstream Companies looking to acquire overseas E&P assets, the Iranian market could offer attractive projects especially considering the close diplomatic ties that the two countries enjoy.
 8With the lifting of sanctions, the government could also consider revival of projects for setting up fertilizer production plants in Iran with the latter providing gas under long term contracts. Rashtriya Chemicals and Fertilizers,
 Gujarat Narmada Valley Fertilizers and Chemicals and Gujarat State Fertilizers Corporation had been nominated earlier by the GoI for setting up a 1.3 million tonne urea plant. The lifting of sanctions could provide impetus to the project.
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The end of the Iran stalemate will see more activity on two pipeline projects that are aimed at pushing Iranian gas to India.
 8One is the a deepwater pipeline that skips Pakistan altogether and the other is the Iran-Pakistan-India pipeline.
 8Under US pressure, India had abandoned the onland route citing security reasons for doing so, even as it actively pursued a Turkmenistan-Afganistan-Pakistan-India pipeline which carries the same of more security risk than the onland pipeline from Iran.
 8The deepwater pipeline carries no security risk but is a technological challenge even though its promoters claim that the landed price of gas in India will be cheaper than that of  LNG.
 8Both projects have their pros and cons but a thaw in Indo-Pak relations can see politicians from both sides of the border announce the launch of the onland version with much fanfare.
 8Iran can set the price right -- given that it has a massive 18.2% of the world's gas reserves -- for the landed cost in India to be more attractive than LNG cargoes.
 8India too will have a much needed alternative pipeline delivery option for gas just like Europe has Russian gas even as the continent continues to build LNG regasification capacity as a counterweight to any blackmail by Russia.
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Little known Root Thinkers Pvt Ltd along with Bureau Veritas Pvt Ltd have been appointed third party agencies by the Petroleum & Natural Gas Regulatory Board (PNGRB) for certification of Emergy Response and Disaster Management Plan documents for midstream and downstream activities in the oil and gas sector.
 8The PNGRB supervises disaster management plans in these segments under its Codes of Practices for Emergency Response and Disaster Management Plan Regulations, 2010.
 8The two agencies were selected based on the recommendation of the Quality Council of India (QCI).
 8The agencies are required to facilitate periodic audits by the QCI.
 8Roots Thinkers Pvt Ltd has been asked to expedite its accreditation under ISO-17020 from the QCI.
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IOC is looking to conduct a pigging operation in its ATF pipeline network in the Bangalore airport.
 The list of work will include:
 8Monitoring, gauging and diverting the product at appropriate tanks during pigging operations, including taking samples
 8Procuring and supplying the requisite filter elements, including micronic filters, coalescers and separators
 8Conducting pigging operations
 8Cleaning of filters
 8Cleaning of underground test, recovery and vertical tanks
 8Joint handling of samples
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GAIL plans to give out contracts for laying of pipelines to various small consumers in Northern region, covering the states of Punjab, Haryana, Himachal Pradesh, Uttar Pradesh, Uttarakhand and the National Capital Region.
 8Most of the work will involve laying of 3-layer PE externally coated carbon steel pipelines for various consumers.
 8The work will also involve terminal facilities made up of piping systems and metering skid equipment at the gas receiving end and hook-up of underground or over-ground pipelines with existing tap off facilities.
 8All other associated civil, structural, electrical, instrumentation and telecom or SCADA works to develop and complete the terminal and tap-off area will be part of the scope of work.
 8Contractors will be required to work at multiple fronts on a minimum of 4-5 connectivity jobs.
 8The entire tendering process will be conducted by Tractable Engineering through an E-bidding process.
 8Detailed specifications involving 100 different items required for the various jobs are also carried here.
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Disruptive change is the new reality. Technological innovations have challenged the very existence of the old order in more ways than one. The advent of shale oil has pushed the price of oil to 12 year lows. Analysts are now talking of oil prices going as low as $10/bbl. A potent combination of solar power and electric cars threaten the very existence of the conventional oil and gas industry.
8Yet another disruptive change comes in the form of a driverless car which can dramatically bring down the demand for cars -- and the consequent demand for petrol and diesel -- as autonomous vehicles transport people around in a seamless manner.
8Earlier projections were that driverless cars will become a reality only by 2030s but the timeline has now been advanced to 2020.
8Combining the popularity of App-based taxi services such as Uber and its Indian counterpart Ola, which are often cheaper and more efficient than conventional cabs, with driverless cars, can increasingly make owning a car less enticing than in the past.
8Some people who might hitherto have wanted to own a car may no longer do so.
8This may have the impact of cancelling out the growth the motor industry might otherwise have expected from the rising middle classes in developing countries.
8These developments by themselves will have far reaching implications for the oil and gas industry.
The disruptive changes that downstream and even upstream oil companies should keep an eye on are:
--The electric care becoming cheaper to own and use than a conventional care: Likely to happen by 2020
--The driverless car becoming a practical reality: Can happen now by 2020.
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The following qualification criteria has been laid down for the Indian subsidiary of the Foreign Principal by Engineers India Ltd:
 8The supplier must be a 100% owned subsidiary of the Foreign Principal for at least one year,
 8The scope or the activity matrix between subsidiary and Principal must be submitted to EIL upfront for information.
 EIL will have right to dictate the level of indigenization
 8EIL has reserved the right to mandate certain activity(ies) or sourcing to be from identified sources only depending upon the product line under consideration and its criticality. The Principal and the supplier will have to jointly ensure progressive indigenization of equipment.
 8The Indian subsidiary must demonstrate that he has the necessary capability and adequate infrastructure comprising of space, manpower, equipment corresponding to matrix given for the product line under consideration.
8If the subsidiary either does not have a testing facility at all or an appropriate testing facility, it will outsource testing to another independent testing facility subject to acceptance by EIL.
Service facility will have to be in India
8The supplier will need to have an established service facility in India which must be approved by the Principal.
Back-up Bank Guarantee
8In order to ensure continued support and back up by the Principal from designing to commissioning of the product, the Principal will have to provide a Back-up Bank Guarantee for 10% of the estimated order value within one month of receipt of each of the first two orders respectively of a project handled by EIL as a consultant or as a contractor. This will be in addition to any other bank guarantee required from the supplier in any bidding document.
8The subsidiary will also provide extended warranty of 18 months from commissioning.
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Engineers India Ltd has announced a new enlistment policy for equipment makers which are 100 per cent subsidiaries of Foreign Principals as part of Narendra Modi's Make in India campaign.
The following will be the qualification criteria for the principal:
8The principal will have be in the business of manufacturing of a product line (for at least last five years) for which the Indian supplier is seeking enlistment.
8The Principal should already be enlisted with EIL for the same product line.
8The Principal has already executed at least two orders for the same product line within the last five years, reckoned from the date of application for enlistment.
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MS consumption posted a growth of 11.8% in December, 2015 in comparison to same month in the previous year.
8This is a slower rate than in the earlier months but is still very high by any yardstick.
8In comparison diesel growth is lower, at 5.34 per cent, on concerns that is usage is more polluting than petrol and CNG. Other seasonal factors are also at play here.
8ATF consumption too has remained high at 11.8% in December 2015 in relation to the same period last year.
8Bitumen consumption grew at 11.16%, pushed by an increase in highway building activity around the country.
8LPG growth is a positive 6.15% whereas SKO consumption fell 4.33%.
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The continuing growth in the consumption of  naphtha, LDO and FO/LSHS points to their increasing industrial use.
8Naphtha consumption grew by a whopping 24% in December, 2015 in comparison to the same month last year. Similarly, FO & LSHS consumption went up by 12.5% and LDO by an impressive 21.8%.
8The point to note however is that industrial growth has contracted in November, and December could not have been significantly better. But despite the negative growth in industrial production, what explains the rise in consumption of naphtha, LDO and FO/LSHS?
8There has been a fall in price of crude and, by implication, the price of liquid fuels too that can cause a rise in demand.
8But if industrial growth has contracted, the rise in consumption of liquid industrial fuels can only come at the cost of natural gas usage.
8The deal for a reduction in the price of LNG supplied by RasGas, which will lower the price of long term LNG by $5/mmbtu, is effective only from January, 2016. Till December therefore, clearly, there was some kind of a  substitution effect taking place.
8Gas consumption is likely to remain buoyant, now that suppliers of LNG have begun cutting rates in response to low demand. Besides significant cuts in long term LNG price, the cost of spot LNG too is likely to plunge as a surfeit of LNG liquefaction capacity around the world comes on stream in the coming years, thereby outstripping demand by a wide margin.
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The outlook for crude oil continues to be grim for all of 2016.
8This  is shaped by the fact that two of the world's biggest economies are showing signs of slowing down.
8The prediction is that the slump in the Chinese industrial sector will continue on account of significant over capacity while US’ exports and manufacturing industry are experiencing decelerating growth. A  stronger USD could potentially pose further drags to the country’s exports and manufacturing industry.
8Already, US railroad cargo has shown a slide in volumes in recent weeks. This is after recording the sharpest drop in six years in 2015.
8The growth rates projected for the world by the IMF and the World Bank will now have to be pared down by up to 1 per cent over even more, the analysis claims.
8For reference purposes, the website carries here crude oil price projections for 2016 and 2017 by
 --Bloomberg
 --EIA
 --World Bank
 --IMF
 --Various banks and research outfits
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Predicting oil prices remains an uncertain art and the bottle is either half empty or half full depending upon the perspective taken.
 8Amidst the enveloping gloom, there are those who claim that the current low oil prices are unsustainable over a period of time.
 8This analysis shows that should prices remain on average at current low levels for a further period of time, almost all production with the exception of on-land fields on the Arabian Peninsula and North Africa would become uneconomical.
8Even for those produce who have production breakeven, their fiscal reliance on oil revenues to fund their budgets require a much higher oil price.
8Globally, while increased capacity in the services and equipment sector will likely put some downward pressure on production costs, the analysis finds it hard to envisage oil remaining at these price levels for any significant period of time.
8The analysis provides some significant insights. For example, the Chinese slowdown notwithstanding, there has not been a deceleration in demand for oil. The sensitivity of oil demand to changes in economic growth is much lower than that of other industrial commodities. Also, the most recent statistics for Chinese oil imports suggest, if anything, acceleration in demand growth over recent months despite the turmoil in the Chinese stockmarket and the depreciation of the Renminbi. This is because the Chinese are now switching to larger cars with higher fuel consumption.
8An analysis of production breakeven prices across the world is given for reference purposes.
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Saudi Aramco's potential listing in the stock exchanges has further depressed sentiments as it is indicative that the world's largest oil company -- with crude reserves 10 times larger than Exxon Mobil -- and its owner the government of Saudi Arabia is planning to dig in and fight the battle with US shale oil and gas industry till the finish.
8However the listing of the consolidated firm would require time as it will have to  unbundle non-core assets, which includes a fleet of eight jets, four Boeing 737 aircraft, football stadiums and a hospital for 360,000 people.
8This is because Saudi Aramco is the Saudi Government’s project manager of choice for non-oil developments.
8For reference purposes, the website also lists here Saudi Aramco's refining and petrochemical assets in terms of the the name of the company, partnership with others if any, location and capacity along with relevant notes.
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For reference purposes, the website carries here the fiscal breakeven prices of major oil exporters in the world.
8The data shows that Saudi Arabia has the highest breakeven point, at $103/bbl
8Only one other country has a higher breakeven and that is Libya at $215/bbl.
8Iran has a breakeven of $70.90, Venezuela $89/bbl while Russia's breakeven is $78/bbl/
8Qatar and Kuwait have breakevens of $59 and $47 respectively.
8Some of these countries are burning existing cash reserves to keep their economies going.
8Saudi Arabia has already spent $100 billion of its $600 billion cash pile and now that the price of crude has fallen to $25/bbl, the burn rate is accelerating.
8Meanwhile, a modeling exercise has shown that while the oil price shock helps oil importing countries to lower inflation, the long term impact on growth rates is not necessarily positive because governments do not cushion the fall in oil prices by levying higher taxes.
8There is a negative impact through as a spill of the lower growth in the oil importing countries  through trade, remittances, tourism, foreign direct investment
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The advent of solar energy, the electric car and the driverless car will eventually impact the refnining sector too as demand for petrol and diesel and other fuels are adversely impacted but that is only in the long run.
8For the time being, the outlook remains neutral as refinery and petrochemical operators are spread takers and their operations are not greatly affected by the low oil price environment, except for  stock losses.
8They are also moving forward with their expansion plans.
8The earnings of these companies depend more on product spreads, which are both seasonal and
cyclical.
8The outlook is that refineries and petrochemical spreads will in fact remain stable to strong in the coming year
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A slew of new business development opportunities will emerge out of the government's order advancing the implementation of BS-V & VI fuel emission norms to 2019-20.
8MRPL seems to be first off the block with a study on what needs to be done to make its newly revamped 15 MMTPA refinery conform to the new norms.
8What MRPL wants to do is to look at the upgradation of the treatment facilities for MS & HSD to ensure compliance.
8In a parallel exercise, the company wants to revamp and augment its existing units to improve operational flexibility.
8Arab Heavy Crude is taken as the benchmark for processing at the refinery.
 What was investigated was:
8The capacity adequacy of existing process units along with units that can be revamped or modified
8New process units which have to be installed
The approach followed in this study was a bottoms up approach with the following characteristics:
8The mass balance along with treatment adequacy is carried out from the short to light residue sections.
8Mass balance of each straight run stream from the primary processing crude distillation is assessed from the bottom up and then the treatment unit adequacy of the process units along with utility treatment units to meet the aforesaid objectives are assessed.
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The following requirements have been drawn up for revamping the refinery to ensure compatibility with BS-V and BS-VI units:
8A new feed preparation unit of the Petrochemical Fluidised Catalytic Cracking unit (PFCC) to reduce sulphur from MS
8A new unit for selective desulphurization of gasoline from the PFCC unit and a new MS upgradation unit from other hydrocarbons to attain sulphur levels of less than 7 ppmw in the total MS pool
8Revmp of the Sour Water Stripper Units to accommodate the incremental sour water generated from the deep hydroprocessing in the revamped or new units.
8Revamp of one of the Hydrogen generation units to offer operation flexibility for sustained meeting of the incremental hydrogen demand from hydroprocessors
8A new Sulphur Recovery Unit to recover sulphur from additional H2S generated
8New tankages and allied facilities along with a new pipeline to the coastal terminal to enable contamination-free delivery of BS V/VI grade auto fuels
8Revamp of the ETP for additional effluents generated, if necessary
8Offsite and infrastructure facilities including logistics support as required to handle treated products.
8The exact specifications will be drawn up while conducting detailed engineering for the project.
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There is also a parallel exercise to debottleneck the refinery for operational flexibility.
The requirements under this segment are:
8Revamp of the CCR II unit along with the reformate splitter unit to increase aromatic streams production
8Revamp of the CCR I unit to increase production from aromatic streams
8New splitting unit to split the full range of naphtha generated at various hydrotreaters as well as imported naphtha
8Revamp of the DHDT downstream of the reactor circuit to provide more hydraulics for treated naphtha.
8Infrastructure to import power form grid the grid
8Reduction of existing Phase III flare load by using suitable flare gas recovery systems, diverting top one or two hydrocarbon flaring process units while depressurizaing during emergencies to a new flare along with modification of associated facilities or relocation of the existing flare to a less prominent location.
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