ONGC ordered to pay wharfage compensation to Mumbai Port Trust
Oil and Natural Gas Corporation Ltd (ONGC), has been ordered to pay arrears of ₹1.7369 billion to Mumbai Port Trust as wharfage compensation for the transportation of crude oil through two pipelines it had laid within the limits of the state-run port. The wharfage compensation payable by ONGC according to a 28 January 2005 agreement signed with Mumbai Port Trust was approved by the Tariff Authority for Major Ports or TAMP, the rate regulator for major ports such as Mumbai, with retrospective effect on a proposal filed by Mumbai Port Trust. “ONGC shall pay to the Mumbai Port Trust a compensation at one half (1/2) of wharfage rate as applicable on the per tonne of crude oil which will be imported into the Port of Mumbai through all or any of these ONGC pipelines and which will not be exported through the Mumbai Port Trust marine oil terminal, Jawahar Dweep or through any other existing and future oil, gas or chemical terminals of the Port,” TAMP wrote in its 03 October order. The TAMP order settles a long-running dispute between two state-run firms over wharfage levied on the two pipelines, each stretching 19.5 km, within Mumbai Port Trust limits. The Mumbai Port Trust said that as per the terms and conditions of the agreement entered between ONGC and MBPT, ONGC has committed to pay wharfage compensation to the Port Trust. ONGC paid the wharfage compensation charges till fiscal year 2014, but discontinued payment from then on citing that such a levy, apart from being “unreasonable”, did not have the sanction of the rate regulator for major ports and hence, Mumbai Port Trust was “not authorized to levy compensation on ONGC”, according to documents reviewed by BusinessLine. ONGC further contented that Section 38 of the Major Port Trusts Act, 1963, is applicable for sea going vessels for goods and passengers, whereas, crude oil is transported from Mumbai High field to Uran plant by pipelines and it is not brought to the Port and the Port Trust has not created any facility for receipt of crude oil from offshore fields of ONGC. The oil explorer also argued that it signed the 2005 agreement with Mumbai Port Trust “under duress and without full consent.” “But, the ONGC was not obliged to accept such agreement if it did not want to. The intention of Mumbai Port Trust to levy the wharfage compensation charge was known to the ONGC way back in 2003 itself,” the TAMP order read. “Having signed the agreement, the ONGC cannot, at this stage, argue that it signed the agreement under duress and without consent,” it said. “Agreement has been made between both the parties who have intended to bind together to serve the interest of both the parties. When a binding agreement is not honoured by one party to the agreement by non-performance there is breach of agreement. The other party is discharged from its obligation under the agreement and it is entitled to rescind the agreement which would affect the oil industry. The MBPT, as a responsible public authority, has chosen not to rescind the agreement,’ TAMP wrote in its order.
Sudan to launch over 30 oil bids in 2019
Sudan is preparing to launch over 30 oil exploration bids next year in an attempt to lure western companies to reinvest in its petroleum industry after the left of economic sanctions, the Financial Times reported on Monday. “Now, as relations between Sudan and the US improve, the ministry of petroleum plans to tender 30 to 35 new oil blocks in the second half of next year to revive exploration activity in the country,” Azhari told the Financial Times. Since the split of South Sudan in 2011, the Sudanese economy felt the tough effect of economic sanctions because it did not use oil financial income to develop the national economy but to fund its war against the armed groups in southern Sudan and Darfur region. The Sudanese oil industry was developed by the oil-hungry China, India and Malaysia. The U.S. Chevron oil company made the first discovery of oil in Sudan in the late 1970s, but it had to stop exploration activities after the outbreak of Sudan’s second civil war in 1983 After, the lift of embargo in October 2017, few western countries showed interest to invest in Sudan because it is still under several U.S. sanction as the country remains on the list of state sponsors of terrorism. Also, corruption and heavy taxes dissuaded investors from the Gulf to work in Sudan. However two weeks after the lift on 31 October of the past year, Sudan’s Oil and Gas Ministry invited several U.S. oil firms to visit the country and offered them to invest in Sudan, pointing to the need of introducing advanced technology to push forward oil production in Sudan. During a meeting with the visiting oil firms, the then oil minister Abdel-Rahman Osman called to invest in a number of oil blocs in the Red Sea area, eastern Sudan. Following what, Baker Hughes a U.S. industrial service company in November 2017, signed a cooperation agreement with Asawer Investment Company, the technical arm of the state oil and gas firm Sudapet. Sudan has proven gas reserves of 3 trillion cubic feet, but development has been limited. It also does not have the pipelines or the port terminals to bring in gas or liquefied natural gas, according to the U.S. Energy Information Administration in 2014. Sudan lost 75% of its oil reserves after the southern part of the country became an independent nation in July 2011, denying the north billions of dollars in revenues. Oil revenue constituted more than half of Sudan’s revenue and 90% of its exports. Sudan currently produces 133,000 barrels of oil per day (bpd). The country’s production is stationed mainly in the Heglig area and its surroundings, as well as western Kordofan.
Asia to dominate global LNG regasification capex and capacity additions
GlobalData’s report, H2 2018 Global Capacity and Capital Expenditure Outlook for LNG Regasification Terminals – Asia to Dominate LNG Regasification Capex and Capacity Additions states that the global liquefied natural gas (LNG) regasification capacity is expected to grow by 48% during the outlook period 2018–2022, from 43.7 trillion cubic feet (tcf) in 2018 to 64.6tcf by 2022. Among regions, Asia continues to lead in terms of planned and announced regasification capacity growth, contributing 62% of the total global growth. The region is expected to add around 12.4tcf of regasification capacity by 2022. The Middle East and Europe follow with capacity additions of 2.3tcf and 1.8tcf, respectively. Among countries, India leads globally with 5.2tcf of regasification capacity additions by 2022. China and Bangladesh follow with 2.3tcf and 1.6tcf, respectively. Planned and announced LNG regasification capacity additions by key countries, 2018–2022 In terms of new-build capital expenditure (capex) outlook for planned and announced regasification projects during the period 2018–2022, Asia again leads with proposed capex of $49bn. Europe and the Middle East have almost equal capex of $6bn each, to be spent during the outlook period. Among countries, in terms of new-build capex during the outlook period, China, India, and the Philippines lead globally with $18.5bn, $6.8bn, and $5.9bn, respectively. Among companies, Kuwait Petroleum Corp, Bangladesh Oil, Gas and Mineral Corp, and China National Offshore Oil Corporation have the highest planned and announced LNG regasification capacity additions globally by 2022, with capacities of 1,155 billion cubic feet (bcf), 910bcf, and 684bcf, respectively. In terms of capex, China National Offshore Oil Corporation has the highest new-build capex of $5.4bn to be spent on new-build regasification projects in the outlook period. Shandong Hanas New Energy Co and Kuwait Petroleum Corp follow with $3.4bn and $3.2bn, respectively.
China overtakes Japan as world’s top natural gas importer
China has overtaken Japan to become the world’s top importer of natural gas, as Beijing’s crackdown on pollution boosts its demand for the more environmentally friendly fuel, while the restart of nuclear reactors in Japan reduces its LNG imports. China’s total natural gas imports over January to October this year via pipeline and as liquefied natural gas (LNG) were at 72.06 million tonnes, up a third from the same period last year, according to Reuters calculations based on General Administration of Customs data. Japan, on the other hand, imported about 69.35 tonnes of LNG over that period, according to ship-tracking data from Refinitiv Eikon, down 17 per cent for the same 10 months of 2017. Japan imports all of its gas as LNG. China’s push to switch away from coal to natural gas is key to its rapid gas demand growth, said Edmund Siau, gas analyst with energy consultancy FGE. “Meanwhile, nuclear reactors continue to restart in Japan, which reduces demand for gas-fired power generation and consequently LNG demand,” Siau said. China – already the biggest importer of oil and coal – is the world’s third-biggest user of natural gas behind the United States and Russia, but it has to import around 40 per cent of its total needs as domestic production can’t keep up with demand. China still lags behind Japan on LNG imports but could overtake its North Asia neighbour in the early 2020s, FGE’s Siau said. China’s surging demand pushed it past South Korea as the world’s second-biggest LNG importer in 2017. China last year started to move millions of households and many industrial facilities from coal to gas as part of efforts to clean its skies, sparking an unprecedented rally in overseas import orders. Its three biggest LNG suppliers are Australia, Qatar and Malaysia. Pipeline imports come from Central Asia and Myanmar, and a pipeline connecting China to Russia is under construction. “China has become a hotbed of contracting activity, with many suppliers courting the large Chinese national oil companies as well as the emerging buyers for long-term contracts,” Siau said. China’s natural gas demand is expected to grow about 10 per cent next year, he said, while Japan’s gas demand will continue to fall.
Digitalisation can save oil upstream business $73 bn a year: Woodmac
Energy firms could save an annual $73 billion within five years in oil and gas exploration and production by making better use of existing computing technology, energy consultancy Wood Mackenzie said. Exploration and production, known as the upstream industry, requires energy firms to analyse huge amounts of seismic and geological data and to monitor and maintain offshore platforms and other complex assets, often in high-risk environments. In a report on how technology can be used for these tasks and potential savings, Wood Mackenzie (Woodmac) said many firms could spend less by buying technology and know-how from outside of the industry. “Start-ups that merge Silicon Valley roots and domain knowledge … may bring benefits to companies much more quickly than in-house approaches,” it said. The consultancy saw big savings from using technology that would make drilling faster, more accurate and less likely to end up with a dry well, and by using applications to predict when maintenance would be needed. Woodmac estimated the industry could save up to $12 billion a year on drilling, mostly in onshore and shallow waters. It said big savings were also available from the use of cloud computing services, particularly for smaller firms that did not have enough in-house computing power. The US shale industry, which uses a cocktail of high-pressure water and chemicals to coax crude from rock deep underground, known as hydraulic fracturing or fracking, could also offer insights to conventional drillers, the report said. In offshore drilling, where rig rates tend to drive costs, the industry overall might be able to use rigs for 2,000 fewer days through more digitalisation and automation, Woodmac said. It said average annual exploration spending of $50 billion could be cut to about $35 billion, while still boosting the discovery success rate to 45 per cent from about 35 per cent now. In addition, it estimated the industry could save as much as $24 billion a year on operating oil producing assets through better use of technology. Citing examples of firms that have effectively employed new technology, it said Norway’s Equinor estimated more automation would drill wells 15 to 20 per cent faster by 2020. Norwegian firm Aker BP had bought software engineer Cognite to digitise its assets, and was now selling software to rivals and sharing data, it said. The report also said Aker had shifted from rigid maintenance schedules to a more flexible system, while BP was using robots and drones to inspect a platform in the Gulf of Mexico.
Saudi Aramco, Abu Dhabi’s ADNOC agree to invest in gas exploration, LNG
The state petroleum producers of Saudi Arabia and Abu Dhabi on Monday signed a “strategic framework agreement” to invest in natural gas exploration and liquefied natural gas ventures. The heads of Saudi Aramco and ADNOC signed the agreement at a ceremony in Abu Dhabi.
Central Asia-China gas pipeline to hit maximum capacity: PetroChina
* China oil major PetroChina says the Central Asia-China gas pipeline will supply 160 million cubic metres of gas per day this winter, its highest ever level * The pipeline will be operating at 100 percent utilisation rate, said the company on its website on Monday * The announcement comes as China prepares to start up winter heating across the north from November 15 * Demand for gas in China surged last year leading to a shortage of supply, after a government push to switch household heating systems to gas from coal * The pipeline accounts for about 25 percent of China’s oil and gas pipeline network, it said * The Central Asia-China pipeline bring natural gas from Turkmenistan, Kazakhstan and Uzbekistan to China
Govt mulls selling 149 fields of ONGC to private companies
The government is mulling selling as many as 149 small and marginal oil and gas fields of ONGC to private and foreign companies and allow the state-owned firm to focus only on big fields, sources with knowledge of the development said. On the anvil is some kind of extension of the Discovered Small Field (DSF) bid round where discovered and producing fields of Oil and Natural Gas Corp (ONGC) are auctioned to firms offering the maximum share of output to the government, sources said. This is the second attempt by the oil ministry to take away some of the fields of ONGC for private and foreign companies. In October last year, the Directorate General of Hydrocarbons (DGH) had identified 15 producing fields with collective reserve of 791.2 million tonnes of crude oil and 333.46 billion cubic meters of gas of national oil companies for handing over to private firms in the hope that they would improve upon the baseline estimate and its extraction. The plan, however, could not go through as ONGC strongly countered the DGH proposal with its own suggestion that it be allowed to outsource operations on same terms as the government plan. Sources said the current plan started as a follow up of the October 12 meeting called by Prime Minister Narendra Modi to review domestic production profile of oil and gas and the roadmap for cutting import dependence by 10 per cent by 2022. At a meeting, the ministry made a presentation showing that while 95 per cent of ONGC’s production was from 60 large fields, 149 smaller fields contributed to a mere five per cent. It was suggested at the meeting that these smaller fields could be given out to private and foreign firms and ONGC could concentrate on the big ones where it could rope in technology partners through production enhancement contracts (PEC) or technical service arrangements. Sources said thereafter a six-member committee under Niti Aayog CEO Amitabh Kant was set up to give a proposal on the same. ONGC, however, is opposed to the plan as it feels it should be allowed the same terms that the government extends to private and foreign firms in DSF. The government gave out 34 fields to private firms by offering them pricing and marketing freedom for oil and gas they produced from the fields in the first round of DSF. A second round of DSF with 25 fields on offer is currently under bidding. The fields offered in DSF were taken away from ONGC and Oil India Ltd on the pretext that they were lying idle and unexploited. But under the present proposal, the government plans to take away discovered and producing fields. Sources said ONGC feels it too should be allowed to seek revenue sharing partnership for its fields. Field operations could be outsourced to foreign or private firms that offered the highest revenue or production share over and above a baseline production. The ministry is reasoning that the areas where the fields discovered by ONGC were given to the state-owned firm on nomination basis. In the proposal that was mooted in October last year, the plan was to give out 60 per cent stake in 15 fields — 11 of ONGC and four of Oil India. These included Kalok, Ankleshwar, Gandhar and Santhal — the big four oilfields of ONGC in Gujarat. The DGH too had identified 44 fields of ONGC and OIL, which could take on partners for production enhancement work where bidders would get the ‘tariff’ that they bid as a return for increasing the output ‘over the baseline production’ for an initial period of 10 years. The oil ministry is unhappy with the near stagnant oil and gas production and believes giving out the discovered fields to private firms would help raise output as they can bring in technology and capital, sources said. It has been tasked by the prime minister to cut dependence on oil imports by 10 per cent by 2022 over 77 per cent in 2014-15. But, the dependence has only increased and is now over 83 per cent. The privatisation is repeat of the infamous round in 1992-93 when medium sized discovered fields like Panna/Mukta and Tapti oil and gas field in the western offshore was given to now defunct Enron Corp of the US and Reliance Industries Ltd (RIL). As many as 28 fields were then awarded. Under this regime, ONGC was made licensee and given an option to farm in 40 per cent of stake. The controversial privatisation under the then oil minister Satish Sharma had resulted in an inquiry by the Central Bureau of Investigation.
Oil exporters discussed proposal for supply cut next year, Kuwaiti official says
A meeting of major oil exporters in Abu Dhabi has “discussed a proposal for some kind of cut in (crude) supply next year”, state-run Kuwait News Agency KUNA on Monday cited a Kuwaiti oil official as saying. It said the proposal did not specify the volume of the cut, according to Kuwait’s governor to the Organisation of Petroleum Exporting Countries (OPEC), Haitham Al-Ghais. Sunday’s meeting was attended by OPEC and non-OPEC countries with several oil ministers still in Abu Dhabi on Monday, including Saudi Arabia’s Khalid al-Falih.
India to lease out half of Padur strategic oil storage to ADNOC
India plans to lease out half of its Padur strategic oil reserve site in southern India to Abu Dhabi National Oil (ADNOC) for storing crude, sources said. Indian Strategic Petroleum Reserves Ltd (ISPRL) will sign an initial agreement with ADNOC on Monday in the presence of oil minister Dharmendra Pradhan, three sources with direct knowledge of the matter said. The agreement will allow ADNOC to sell oil to local refiners but give the government of India the first right to the oil in the case of an emergency. It will be the second such deal with ADNOC, which is already storing oil at the Mangalore strategic storage in Karnataka. “We will sign a memorandum of understanding with ADNOC to fill two compartments in Padur along the same lines as the Mangalore cavern,” said one source with direct knowledge of the matter, declining to be named ahead of an official statement. In return for allowing ADNOC to store its crude at a strategic reserve site, India does not have to pay for the imports, only accessing the oil in emergencies. India’s oil ministry and ISPRL, a government entity that builds the caverns, did not respond to Reuters’ request for comments. An ADNOC spokesman said: “We are already working with India’s ISPRL in Mangalore and we hope to build on this positive working relationship in the future.” India’s cabinet last week approved a plan allowing foreign oil companies to store oil in Padur’s strategic storage. “Participation by foreign oil companies will significantly reduce budgetary support of government of India by more than 100 billion rupees ($1.38 billion) based on current prices,” Law Minister R. S. Prasad told a news conference last week. The Padur site is located about 5 km (3 miles) from the southwest coast and 40 km from Mangalore Refinery and Petrochemicals Ltd’s refinery. India relies heavily on oil imports, which account for about 80 per cent of its total demand. To protect itself from potential supply disruptions, it has built emergency storage in underground caverns at three locations, with a capacity to hold 36.87 million barrels of crude, or about 9.5 days of its average daily demand.