Brazil’s Petrobras to sell other gas pipelines in wake of TAG deal’s success
State-run oil company Petroleo Brasileiro SA is preparing to sell three more gas pipelines after successfully selling its larger TAG unit to France’s Engie for $8.6 billion, according to three sources with knowledge of the matter. The group of pipelines, considerably smaller than the TAG unit sold by Petrobras, as the company is known, could be valued at more than $3 billion altogether, one of the sources said. Petrobras has hired the investment banking unit of Credit Suisse AG to sell the pipelines that link oil fields in the so-called pre-salt area in the Santos basin to onshore infrastructure, said the sources, who asked to remain anonymous as the discussions were not yet made public. Petrobras and Credit Suisse declined to comment. Petrobras had initially planned to sell only a minority stake in the units, but after getting a better-than-expected price for the TAG unit, the company may sell control of the pipelines, two of the sources said. [ID:nL1N21N1LV] A controlling stake would lure more investors than a minority one, one of the sources said. Some of the investors that participated in the TAG deal were interested in the other pipelines, which similarly offer table cash flows. A final decision will be made once Petrobras’ new Chief Financial Officer Andrea Marques de Almeida, who was appointed last month, starts in her new role, one of the sources said. The three units, known as Rota 1, Rota 2 and Rota 3, comprise roughly 1,000 kilometers (621.37 miles) of pipelines stretching from the Santos basin to the coast. Two of those units already transport natural gas generated in sub-salt fields in the Santos basin to onshore facilities in the coast of Rio de Janeiro and Sao Paulo, and the third one is still under construction. The process of selling the additional pipelines will probably not start before the second half of the year, one of the sources said. That’s because Petrobras needs to get the approval of its oil exploration partners in the pre-salt oil fields for the sales since they own stakes in the natural gas production in the fields. Those partners include France’s Total SA, Royal Dutch Shell Plc and China’s CNPC.
Kpler, Powernext to launch LNG trading platform in Singapore
French data firm Kpler and energy exchange Powernext plan to launch a trading platform for liquefied natural gas (LNG) in Singapore this year, company executives told Reuters, joining a run of firms capitalising on growing spot volumes. The move comes amid a surge in supply of the super-chilled fuel, along with healthy demand, which has triggered a boost in trading as many countries and companies switch from burning coal to cleaner natural gas. The two companies set up Spark Commodities in Singapore in March and have hired Tim Mendelssohn, previously with Koch Supply and Trading and oil major BP, as its managing director. Spark, which is majority-owned by Kpler, aims to launch a trading platform for physical LNG buyers and sellers by the fourth quarter of this year, Mendelssohn told Reuters in an interview this week. Spark will not be alone. Rising spot trading volumes have attracted several companies to launch LNG pricing and trading platforms, including GLX and dominant oil price agency S&P Global Platts. GLX is based in Australia, but Spark will join Platts in Singapore – already Asia’s main oil trading hub – which is vying to establish itself as the main exchange point for the booming LNG market. Unlike oil, which has several liquid financial and physical trading platforms and exchanges, LNG markets are still evolving, and Kpler chief executive and co-founder Francois Cazor said clients had been asking how to trade LNG faster and more efficiently. “To do this, we wanted to create a separate entity to Kpler; one which allowed us to focus on providing greater transparency to commodity flows whilst giving the new entity, Spark, the necessary freedom to focus on price and improving the transaction process,” said Cazor. Kpler is a French data intelligence firm mostly known for its ship tracking and cargo information services, which traders and analysts use to monitor global supply and demand changes for products like oil or LNG. Powernext is part of the European Energy Exchange (EEX), Europe’s biggest wholesale electricity bourse, which also offers natural gas products. EEX, which launched EEX Asia in Singapore last year, is a subsidiary of Germany’s Deutsche Boerse AG exchange group.
Goa: Two years on, govt’s piped gas project remains pipe dream
Goa’s vision for piped gas is still a ‘pipe dream’. Among the factors contributing to the delay are the ongoing highway expansion at Ponda, inability to acquire land at Madkai and lack of a formal nod from the Petroleum and Explosives Safety Organisation (PESO). For over two years, Goa Natural Gas Pvt Ltd (GNGPL) has struggled to implement the Centre’s city gas distribution (CGD) network, but sources say delays by various state departments to classify land has put a spanner in the works. Officials say that while GNGPL has identified and obtained 2,300sqm of land from the Comunidade of Marcaim, the formal acquisition procedure is stuck in red tape. Now, the ongoing Lok Sabha and byelection process has only compounded matters. “The owner has given the NOC and all parties agree on the price, but the government is unable to classify the land due to which the file is yet to reach the cabinet for a final approval,” said a senior official associated with the project. “Clarifications are repeatedly sought and if any clarification is needed, the file gets stuck for three months.” Goa Natural Gas, a joint venture of GAIL GAS Limited (GGL) and Bharat Petroleum Corporation limited (BPCL), has been authorised by the Petroleum and Natural Gas Regulatory Board (PNGRB) to build the city gas distribution network in north Goa. GNGPL plans to acquire land at Madkai under the Policy of Procurement of Land of the Rights to Fair Compensation and Transparency in Land Acquisition, Rehabilitation and Resettlement Act, 2013. The land is required to set up district regulating skids (DRS) or field regulating stations to help reduce the pressure of the gas supply so that it can pass through the low-pressure medium-density polyethylene (MDPE) maze of pipeline network that connects to individual houses. GNGPL is also on the lookout for 200sqm of land in Ponda and Panaji for a similar purpose, but the search has not borne fruit yet, GNGPL officials say. While the Nagpur-based PESO has given the first round of approval to start work, the second permission to commission the facility and commence supply is awaited. PESO has delayed the necessary approval and has sought documents proving that GNGPL has ownership of the land where the DRS will be set up. However, state government departments are struggling to identify whether the earmarked land is agricultural, commercial, settlement or orchard. Until the land has been classified, formal acquisition of the land cannot go ahead, said GNGPL officials.
Overhauled oil policy to apply from fourth bid round: DGH
The overhauled oil and gas exploration licensing policy will be implemented from the fourth bid round, likely sometime in June or July, the Directorate General of Hydrocarbons (DGH) has said. Junking two-year-old revenue bidding model for award of acreage for exploration and production of oil and natural gas, the Union Cabinet had in February approved a policy for awarding blocks based primarily on exploration commitment such as drilling of wells. This was aimed at attracting the elusive private and foreign investment to raise domestic output. “Parameters of new policy reforms published vide resolution dated February 28, 2019 shall apply from OALP-IV onwards only,” the DGH said in a notice. Oil and gas blocks for exploration are bid out under Open Acreage Licensing Policy (OALP). Second and third round of OALP bidding is underway with last date of bidding set for May 15. The fourth round is expected by end June or July, official sources said. Under OALP, companies are allowed to put in an expression of interest (EoI) for prospecting of oil and gas in any area that is presently not under any production or exploration licence. The EoIs can be put in at any time of the year but they are accumulated twice annually. The two windows of accumulating EoIs end on May 15 and November 15 every year. EoIs accumulated till May 15 are supposed to be put on auction by June 30 and those in the second window by December 31. With the notice, DGH attached the official notification that overhauled the exploration policy. Breaking from the two-and-a-half decade old practice of having a uniform contractual regime for all sedimentary basins in the country, the new policy provides for different rules for areas that already have producing fields and ones where commercial production of oil and gas is yet to be established. Irrespective of the basins, producers will get complete marketing and pricing freedom for oil and gas in future bid rounds, said the notification detailing rule changes approved by the Union Cabinet on February 28. Oil and gas acreage or blocks in all future bid rounds will be awarded primarily on the basis of exploration work commitment, it said. While companies will have to pay a share of revenue from oil and gas produced in Category-I sedimentary basins such as Krishna Godavari, Mumbai Offshore, Rajasthan or Assam where commercial production has already been established, they will be charged only prevalent royalty rates on oil and natural gas in the less explored Category-II and III basins. “To expedite production, concessional royalty rates will be applicable if production is commenced within four years for onland and shallow water blocks, and five years for deep water and Ultra-deepwater blocks from the effective date of the contract,” it said. India began bidding out oil and gas exploration acreage in 1999 under New Exploration Licensing Policy (NELP) that awarded blocks to companies offering maximum work commitment. But companies were obliged to share with the government profits made after recovery of cost. Two years back, the BJP-government brought in Hydrocarbon Exploration and Licensing Policy (HELP) that provided for blocks being awarded to companies offering maximum revenue at different levels of prices and production. HELP failed to either raise output or attract new players. The notification said the new policy was being formulated “to increase exploration activities, attract domestic and foreign investment in unexplored/unallocated areas of sedimentary basins, and enhance domestic production of oil and gas”. While blocks in Category-1 basins would be awarded on basis of exploration work and revenue share in the ratio of 70:30, those “in Category-II and Category-III Basins will be awarded on the basis of international competitive bids based exclusively on the exploration work programme.” “The contractor will have full marketing and pricing freedom to sell on arm’s length basis. Discovery of prices will be on the basis of transparent and competitive bidding. No exports will be allowed. There will be no allocation by Government,” the notification said. The contractor will have liberal freedom to transfer/exit the block provided work programme has been adhered to. However, a suitable penalty mechanism will be devised for non-completion of the work programme. The notification said in case of the existing contracts, marketing and pricing freedom to sell on arm’s length basis through competitive bidding will be permitted to those new gas discoveries whose Field Development Plan (FDP) will be approved for the first time after the date of issuance of the new policy. In case of nomination fields given to national oil companies, marketing and pricing freedom will be provided subject to the condition that FDP for new gas discoveries is approved by DGH. “To incentivise additional gas production from Administered Price Mechanism (APM) fields, reduction in royalty by 10 per cent of the applicable royalty will be granted on the additional production over and above Business As Usual (BAU) scenario. BAU scenario will be approved by DGH on third-party evaluation,” it said. Existing contracts already having marketing and pricing freedom would continue on the existing terms.
Landmark multi-billion dollar natural gas deal signed by Papua New Guinea
Papua New Guinea has agreed terms for a new multi-billion dollar natural gas project with Total, ExxonMobil and Oil Search that would double energy production and boost exports from the poor Pacific nation. Announcing the deal Tuesday, Prime Minister Peter O’Neill vowed the much-needed investment of nearly $13 billion would benefit local communities which have complained bitterly of missing out on earlier projects. “We will be developing this project for the country,” O’Neill said at a ceremony in Port Moresby that capped nearly 12 months of negotiations marked by wrangling over land ownership. “This is a significant boost to our economy,” he said. One of Asia’s most impoverished nations, Papua New Guinea is rich in natural resources including large gas fields. Total said the proposed project — which includes gas fields, a pipeline and new liquefaction units at a facility west of Port Moresby — put Papua New Guinea in a prime location to sell liquefied natural gas (LNG) to the powerhouse economies of Asia. The project will see the construction of two new processing units — or “trains” — set to roughly double LNG exports to 16 million tonnes. An existing LNG project in the country has been deeply controversial, with locals seeing little benefit from billions of dollars in foreign investment. The $19 billion plant was completed half a decade ago, but a drop in energy prices resulted in very few royalties being paid to locals. A memorandum of understanding for the new Papua LNG project was signed last year, but Tuesday’s agreement fleshes out the costs and profit sharing. O’Neill said the new agreement was better for the country, with a fixed price making gas and power generation inside the country cheaper. Papua New Guinea has entered a partnership with the United States, Australia and others to increase the number of people with reliable electricity from 13 percent today to 70 percent by 2030. O’Neill predicted that the new Papua LNG project would add around three percentage points to the nation’s GDP and help employ about 20,000 people during construction. He added that the government, provincial authorities and the land’s traditional owners would get their “fair share” of profits, royalties and other benefits. The state will have a roughly 22.5 percent stake in the project. Construction is expected to begin at the start of 2021 and the first cargoes are expected to leave facilities in late 2024.
Sri Lanka gets ADB help to tender for own LNG terminal
Sri Lanka’s state-run Ceylon Electricity Board has received Asian Development Bank funding to tap international expertise to prepare bid documents to acquire a liquefied natural gas terminal, officials said. “We don’t have the expertise around LNG terminals so the ADB funding was made to available to us so we could consult experts recommended by the ADB in India and other countries to prepare a tender book,” Athula Wanniarachchi, past president of the CEB Engineers Union said. Sri Lanka current administration has been entertaining several proposals from private parties to build LNG terminal provided the power utility purchases large volumes of LNG. In 2018, the Cabinet approved a controversial unsolicited proposals brought forward by the Ministry of Development Strategies and International Trade from countries like Korea and Japan to set up an LNG terminal by giving the firm the right to sell fuel to Sri Lanka for up to 20 years. If the fuel is not required, the CEB has to pay the terminal operator for the unused LNG, which is known as take-or-pay. The unsolicited bids for take-or-pay floating terminals to force the CEB to buy 2.7 million tonnes per annum, whether it was needed or not, earlier reports said. One terminal proposed 1 million metric tonnes a year while another proposed 0.6 million tonnes, according to reports. The terminal itself will come ‘free’ as long as a commitment was given to buy the gas for 20 years. Floating terminals may cost anything from 250 million dollars upwards, if they are built on used ships. But the take or pay gas contracts may be worth 7 billion US dollars. “This will be the biggest contract ever awarded by the government of Sri Lanka,” Saumya Kumarawadu, President of the Union said. ‘it will be bigger than the Mahaweli projects”. Officials say the terminal could be state owned or if privately owned could be build operate transfer project where guaranteed terminal charges will be given like the capacity charge of an independent power producer to recover its capital. “The gas procurement and the terminal have to be separate,” Wanniarachchi said. Sri Lanka is planning to build more LNG plants under a new power plan and diesel combined cycle plants that are now proposed have to be dual fuel. Without a gas terminal plans that are now called ‘300MW LNG’ will remain in fuel oil. One 300MW plant tendered in 2016, expected be built in Kerawalapitiay near the capital Colombo remains mired in alleged tender corruption and is now caught in a court battle. Another 300MW plant is due in 2021 to replace a coal plant cancelled by President Maithripala Sirisena and Prime Minister Ranil Wickremesinghe’s administration. China is planning a 400MW plant in Hambantota with its own terminal. Sri Lanka also has found offshore deposits of natural gas, estimated to contain a combined 2.3 trillion cubic feet, but they are too deep to be commercially viable. Cairn India, which found the deposits, exited the field after spending 240 million US dollars as global LNG prices collapsed. Imported LNG is liquefied below 160 degrees Celsius for ease of shipping and storage, and re-gassified and distributed for use. It is not clear whether the CEB will have to pay above global prices to buy LNG extracted from Sri Lanka. More combined cycle plants including one promoted by India and another by Japan of 300MW each are expected to be built in Kerawalapitiya. Union officials say whatever plant is acquired it has to come through competitive bidding. Given past attempts to bypass tenders by powers-that-be the CEBs engineers union is prepared to lobby hard, even resort to strike action. “We will have to resort to union action if the government fails to adopt open tenders when calling for bids for strategic projects of this nature,” Kumarawadu, President of the Union said. “The tender process will minimise fraud because there is visibility on who is offering what. This will prevent vested interests from making unfair gains,” he said. The government attempted to bring the take-or-pay plants through a ‘Swiss Challenge’ process. The CEB has now exited the technical evaluation committee officially. A case in point about how competitive bidding is subverted is the tender for a 300MW plant which has now ended in court. The tender for a 300MW combined cycle plant that was floated in 2016 shows how even competitive bidding can be subverted at higher levels. Seven companies had tendered their bids to build a 300MW plant in 2016 but authorities decided to open just one bid from a Korean company. The CEB Engineers Union objected to the move and lobbied to open and evaluate the bid documents of all seven companies. “But due to interference from various political bigwigs, undue influence on members of the tender board(s) and unwarranted actions by several officials in the ministry have left this tender entrapped in a legal stranglehold,” the union said in a statement last Tuesday. “Removal and reappointment of members in the tender boards on several occasions is clear testimony to the extent of political interference in the selection process. “Instead of proper mediation by the authorities to get this massive power plant built by a suitable company, it is learnt that several attempts are underway to award the tender to a party which is more favourable to them,” the union claims. However, at a press conference on Tuesday the union’s executive committee declined to name the persons or companies behind what they called a mafia. Meanwhile, the government has announced plans for three separate LNG power plants which will be funded and built by companies from China, Japan and India. India’s proposal is believed to be a government-to-government agreement for a 500MW plant. The Japanese proposal is for the same capacity while the Chinese offer is for 400MW. “Even though the government attempts to include these power plants in future plans, there is neither any appropriate proposal nor any agreement on pricing reached up to date,” the CEB Engineers Union said. “One other
Bangladesh pipeline hits a hurdle
The construction of the India-Bangladesh Friendship Product Pipeline (IBFPL) from Numaligarh Refinery Ltd’s marketing terminal in Siliguri to Parbatipur in Bangladesh could be hit because of a technical objection raised by H-Energy Pvt Ltd, a subsidiary of real estate firm Hiranandani Group. “The customer — Bangladesh Petroleum Corporation (BPC) — for which the dedicated pipeline has been proposed is a marketing and distribution company of petroleum products in Bangladesh. Hence, the customer (BPC) will resell the products to its customers,” H-Energy informed the Petroleum and Natural Gas Regulatory Board (PNGRB). “Therefore, the proposed pipeline does not fall within the definition of a dedicated pipeline and the application of a dedicated pipeline under the provisions of PNGRB authorisation regulations cannot be considered,” it contended. H-Energy pointed out that rule 19 (2) of the authorisation regulations states that “the entity proposing to lay, build and operate or expand a dedicated pipeline to transport petroleum products to a specific customer and not for resale”. Sources said the regulator would soon come out with its ruling on the issue based on the submission made by H-Energy. Of the 129.5km long pipeline, only 5.16km would fall in India. The Indian leg of the 1-million-tonne-a-year pipeline will be financed by Assam-based Numaligarh Refinery (NRL), a BPCL subsidiary. The pipeline is to be financed through India’s ongoing development co-operation programme. The total cost is estimated at Rs 3.60 billion. Depending on the availability of the right of way in Bangladesh, the pipeline is scheduled to be completed in 27 months. At present, high-speed diesel is being supplied from the Siliguri terminal through rail rakes. The completion of this pipeline will ensure an assured, sustainable and eco-friendly supply to Bangladesh.
Government defers oil block bid deadline by a month to May 15
The government has again deferred the last date for bidding for oil and gas exploration blocks offered under the Open Acreage Licensing Policy (OALP) by over a month to May 15. Last date for OALP bid round II and III, which are running almost concurrently, was April 10 but has now been pushed back. “Bid submission closing date for OALP Bid Round II & III stands extended up to May 15, 2019,” upstream regulator DGH said in a notice. It did not give reasons for extending the deadline. The government had in January offered 14 blocks in OALP-II bid round and a month later offered another 23 oil and gas blocks and coal-bed methane (CBM) blocks in third round. Bids for the 14 blocks offered in OALP-II bid round, covering an area of 29,333 square kilometres, were to close on March 12 but the deadline was extended to April 10, according to the Directorate General of Hydrocarbon (DGH). April 10 was also the bid deadline for the 23 oil and gas and CBM blocks offered in the third round, which was launched on February 10. OALP-II bid round was delayed by six months and its launch came barely a month before the third round. Officials said OALP-II and OALP-III will run concurrently. Oil Minister Dharmendra Pradhan had at the time of launch of OALP-II bid round on January 7 stated that an investment of about Rs 400 billion is expected in the prospecting of oil and gas in blocks offered. In the first round of OALP last year, as much as Rs 600 billion was committed in the exploration of oil and gas in 55 blocks or areas. In the third round, the government is expecting up to USD 700 million (about Rs 490 billion) of investment that it hopes will help raise domestic output and cut imports. India had in July 2017 allowed companies to carve out blocks of their choice with a view to bringing about 2.8 million sq km of unexplored area in the country under exploration. Under this policy, called open acreage licensing policy or OALP, companies are allowed to put in an expression of interest (EoI) for prospecting of oil and gas in any area that is presently not under any production or exploration licence. The EoIs can be put in at any time of the year but they are accumulated twice annually. The blocks or areas that receive EoIs at the end of a cycle are put up for auction with the originator or the firm that originally selected the area getting a 5-mark advantage. The two window of accumulating EoIs end on May 15 and November 15 every year. EoIs accumulated till May 15 are supposed to be put on auction by June 30 and those in the second window by December 31. The first OALP round was launched in 2017 and bids came in by May 2018. EoIs for second round closed on May 15, 2018, and the blocks were supposed to be put for auction by June but the round was delayed for unknown reasons. OALP-II was finally launched on January 7. In the meanwhile, EoIs in the third window also closed on November 15, 2018 with as many as 18 blocks and five CBM blocks, measuring 31,722 sq km, being sought for. OALP-III bid round was launched on February 10 with April 10 as the last date for bidding. Officials said the 14 blocks in OALP-II are estimated to hold in-place resource of 12,609 million tonne oil and oil equivalent gas. In OALP-1, mining mogul Anil Agarwal-led Vedanta walked away with 41 out of 55 blocks bid out. State-owned Oil India won nine blocks while Oil and Natural Gas Corp (ONGC) managed to win just two. The 55 blocks have a total area of 59,282 sq km. This compares to about 1,02,000 sq km being under exploration prior to OALP. Blocks are awarded to the company which offers the highest share of oil and gas to the government as well as commits to doing maximum exploration work by way of shooting 2D and 3D seismic survey and drilling exploration wells. Increased exploration will lead to more oil and gas production, helping the world’s third largest oil importer to cut import dependence. Prime Minister Narendra Modi has set a target of cutting oil import bill by 10 per cent to 67 per cent by 2022 and to half by 2030. Import dependence has increased since 2015 when Modi had set the target. India imports 83 per cent of its oil needs. The new policy replaced the old system of government carving out areas and bidding them out. It guarantees marketing and pricing freedom and moves away from production sharing model of previous rounds to a revenue-sharing model, where companies offering the maximum share of oil and gas to the government are awarded the block.
Fitch sees Brent crude at $62.5 in 2020 as economic woes bite
A faltering global economy may start eating into demand for oil as early as this year, pushing prices lower, Fitch Ratings’ senior director Dmitry Marinchenko told Reuters in an interview. He said that the rating agency expects global economic growth to slow to 2.8 percent in 2019-2020 from 3.2 percent in 2018. “If the global growth slowdown becomes more pronounced, or even if recession materialises, then demand for oil could fall sharply, which is the main risk for global oil prices.” he said. Fitch Ratings sees 2019 oil prices averaging around $65 per barrel, falling to $62.50 in 2020 and $57.50 by 2022. The price of Brent crude is currently testing $70 per barrel, its highest this year, following cooperation between the Organization of the Petroleum Exporting Countries and other large oil producers led by Russia to cut supply. U.S. sanctions against Iran and political and economic turmoil in Venezuela have also capped output. The OPEC-led group agreed to cut their combined oil production by 1.2 million barrels per day for six months starting from January 1. The next OPEC and non-OPEC meeting is expected to be held in June to discuss an extension of the supply cuts. Marinchenko said the future of the deal would likely hinge on the situation in Venezuela and Iran. He said it was possible the size of the cuts could be adjusted. “Oil production in Venezuela will continue to decline, the quotas will have to be revised.” AZERBAIJAN Marinchenko said Fitch does not expect to change the credit rating of Azerbaijan’s energy company SOCAR from BB+ in the next two years. The rating is in line with Azerbaijan’s sovereign rating, on which Fitch is due to give an update in July. Marinchenko said Fitch expects Azerbaijan’s oil production to rise by 2020 thanks to a boost in gas condensate output at the large Shah Deniz field.
Engie secures 70 per cent financing for purchase of Brazil pipeline
France’s Engie has closed an agreement with a group of banks to finance 70 percent of its gas pipeline acquisition from Brazil’s Petroleo Brasileiro SA, Engie’s Brazilian head told Reuters on Saturday. An Engie-led consortium that includes Canada’s Caisse de Depot e Placement du Quebec on Friday presented the highest bid for Transportadora Associada de Gas SA, known as TAG, valuing the major Brazilian gas pipeline at $8.6 billion. “There is already a firm commitment on the part of the banks, which is very important,” Engie Brasil chief executive Mauricio Bahr said. Organized under a project finance structure with a ten-year term, Engie will repay banks involved in the deal with the cash flow generated by receivables from TAG’s contracts, Bahr said. Three Brazilian and six international banks will be participating in the project finance, Bahr said, declining to name them. Two sources close to the matter told Reuters on Friday that about 60 percent of Engie’s bid for TAG would be financed by Itau Unibanco, Banco Bradesco SA and Banco do Brasil SA. “It is an important strategic move, practically doubling our participation in Brazil,” Bahr said.