Japanese, Russian companies will look for gas in Far East
(Nikkei Asian Review; Dec. 16) - Japanese and Russian resource developers are joining hands for large-scale natural gas field development southwest of Sakhalin Island in the Russian Far East. The parties — Marubeni, Inpex and Japan Oil, Gas and Metals National Corp. from Japan, as well as Russia's state-owned oil and gas company Rosneft — plan to conclude a basic agreement Dec. 16, including joint exploration and production cooperation.
They will soon start geological surveys and exploration, aiming to possibly start full-cycle production of liquefied natural gas in the late 2020s, at the earliest. In northeast Sakhalin, a two-train LNG plant started operations in 2009, named Sakhalin-2, involving Russia's Gazprom and Japanese trading houses Mitsubishi Corp. and Mitsui & Co. The proposed new LNG development on the other side of the island could grow to become as large as the Sakhalin-2 project.
Marubeni and its Japanese partners will likely seek to eventually own a total of one-third or so of upstream interests in the project. The area is mostly untouched, although it has long been considered a high-potential location for gas field development. Marubeni and its partners plan to start exploration using the Shigen, a three-dimensional seismic survey ship owned by the Japanese trade and industry ministry. Total exploration spending through 2025 is projected to be in the hundreds of millions of dollars.
Oregon LNG project sponsor will reapply after Trump takes over
(Portland Oregonian; Dec. 15) - It's not dead yet. Backers of a rejected liquefied natural gas export terminal in Coos Bay, Ore., said they intend to file a new application with federal regulators, opening a new chapter in the now 12-year-old effort to build the controversial facility on the state’s south coast. Calgary-based Veresen said it has redesigned the proposed $7.6 billion project so it will no longer require a separate power plant, reducing its environmental and community impacts.
And with an energy-friendly administration on its way into the White House, the company thinks the regulatory outcome will be different. The company’s Dec. 15 decision comes days after the Federal Energy Regulatory Commission reaffirmed its rejection of the Jordan Cove Energy Project in March. FERC said at the time that the sponsor had not demonstrated there was enough market demand to offset the negative impacts the facility's 232-mile gas pipeline would have on landowners.
The commission rejected Veresen's rehearing request last week, but left the door open for the company to reapply. A new application will go before a commission that will be entirely remade by the incoming Trump administration — two of the five seats at FERC are open, and the president will have the opportunity to name a new chair. FERC is not the only hurdle in getting the project approved. It still needs numerous federal and state permits and faces significant opposition along the pipeline route.
Turkey expects to start up first LNG receiving terminal next week
(Daily Sabah; Turkey; Dec. 15) - Expected to contribute more than 175 billion cubic feet of natural gas to Turkey's annual supply, the GDF Suez Neptune facility, Turkey's first floating liquefied natural gas receiving, storage and regasification unit, has started conducting tests. With minimal domestic production, Turkey currently imports by pipeline about 90 percent of its gas supply, buying from Russia, Iran and Azerbaijan.
The Norwegian-flagged, 2009-built, 930-foot-long, 141-foot-wide floating unit will be able to transfer LNG to the national pipeline grid system. It has the capacity to handle more than 10 percent of Turkey's annual gas demand. If the unit completes the testing process, it is expected to start providing gas to the system by the end of next week. It will provide a prompt solution to Turkey's energy supply shortage.
The floating LNG terminal project will be put into active use at a ceremony with Turkey’s president and prime minister on Dec. 23. Plans also are underway for a second floating LNG import facility of a similar size.
Vietnam forecasts annual LNG imports of 5 million tonnes by 2025
(VietNamNet online newspaper; Dec. 15) - Vietnam is expected to import 5 million tonnes of LNG by 2025, almost 240 billion cubic feet of natural gas per year. And that is expected to increase to 11 million tonnes by 2030 and 13.9 million tonnes by 2035. The Việt Nam National Oil and Gas Group (PetroVietnam) reports that gas is used to generate about 30 percent of the country’s electricity, with the expectation that long-term demand growth will outpace domestic gas production.
PetroVietnam forecasts the country’s gas demand will average more than 650 bcf a year before 2035. Current consumption is less than 400 bcf a year. The country needs to develop new domestic gas supplies while also importing LNG to meet demand, particularly from new power plants, said Vu Dao Minh, deputy head of the PetroVietnam’s Department of Oil and Gas Exploitation. PetroVietnam is building two LNG import terminals, though start-up dates are uncertain.
Spanish utility takes first Cheniere LNG cargo under contract price
(Argus Media; Dec. 16) - Spain's Gas Natural Fenosa may have loaded its first U.S. LNG cargo under long-term contractual prices. The La Mancha Knutsen LNG vessel, controlled by Gas Natural, left Cheniere Energy’s Sabine Pass, La., terminal Dec. 15 with a cargo. The ship can hold up to 3.6 billion cubic feet of natural gas as LNG. It has not listed its destination.
Gas Natural has a 20-year deal for up to 3.5 million metric tons per year of LNG from Sabine Pass when the facility’s second liquefaction train starts long-term operations in September 2017. But under a pre-commercial contract, the company can buy up to 2 million tons a year as soon as the plant’s second liquefaction train produces under correct specifications. That occurred in mid-September, and the La Mancha Knutsen is the first ship controlled by the Spanish firm that has arrived at Sabine Pass since then.
Under both deals, Gas Natural would pay Cheniere a liquefaction fee of $2.49 per million Btu, plus 115 percent of the final Nymex Henry Hub prompt-month settlement price for the month in which a cargo loading is scheduled. If the cargo on the La Mancha Knusten was bought under those terms, Gas Natural would have paid a free-on-board price of $6.72 per million Btu. Shipping costs would be additional.
Construction continues on gas pipeline expansions into Mexico
(Argus Media; Dec. 13) - Construction is on schedule for four cross-border gas pipelines from the United States to Mexico, with the pipelines expected to add 3.5 billion cubic feet per day of capacity to Mexico's pipeline system in the first half of next year. Mexico currently imports around half of its gas needs, including growing pipeline supply from the U.S. and LNG from Peru and other sources. U.S. gas pipeline exports to Mexico in September 2016 totaled 4.1 bcf a day, up from 3.3 bcf a day a year ago.
The Roadrunner pipeline connects Oneok Partners' Oneok WesTex pipeline in Coyanosa, Texas, to an international border hook-up. The pipeline is fully subscribed under 25-year firm fee-based agreements. Mexico's state-owned utility CFE is an anchor shipper. CFE will also be the anchor shipper for the Nueva Era pipeline, with a 25-year agreement to receive about 490 million cubic feet per day for power plants in the Escobedo and Monterrey areas. The 190-mile line will start work in June 2017.
The remaining two pipelines to start operations in 2017 are the Comanche Trail and Trans-Peco pipelines, both owned by Energy Transfer Partners, at 1.1 bcf a day and 1.4 bcf a day, respectively. Securing capacity in the new pipelines is crucial to CFE's strategy of transitioning toward gas-fired power generation through the conversion of existing oil-fired power plants and construction of up to nine new combined-cycle plants.
Rosneft pays $1.13 billion for one-third of 30 tcf gas field in Egypt
(Houston Chronicle; Dec. 12) - Rosneft has agreed to buy as much as 35 percent of a natural gas project offshore Egypt, joining Eni and BP in the largest discovery in the Mediterranean Sea. The Russian company will pay Eni $1.13 billion for an initial 30 percent stake in the Shorouk concession, which includes the Zohr find, the Italian producer said Dec. 12. Rosneft will add about $450 million to cover past costs and has an option to acquire a further 5 percent, which would require additional payments.
Rosneft’s acquisitions at home and abroad amount to more than $15 billion this year, according to data compiled by Bloomberg. The Moscow-based company, which pumps more than 40 percent of Russia’s crude and over 10 percent of its gas, has planned to expand its gas business for years. It has sought assets and contracts overseas, while at home challenging the pipeline gas export monopoly of state-run Gazprom.
Rosneft, which had more than $20 billion of cash at the end of September, sold almost $10 billion of 10-year bonds last week to refinance loans and fund development abroad. Rosneft is already involved in Egypt’s gas trade, supplying four liquefied natural gas cargoes to the country this year, the Russian state-run Tass news service reported Dec. 11. Egypt has said it will keep all of Zohr’s reserves for domestic use, allowing the country to reduce its LNG imports. Eni discovered the field last year, estimating its resources at about 30 trillion cubic feet. It expects the first gas to flow in late 2017.
B.C.’s 2016 oil and gas lease sale revenues lowest since 1970s
(The Mirror; Dawson Creek, BC; Dec. 15) - 2015 was a poor year for B.C.'s oil and gas provincial revenues, and 2016 was even worse. The province brought in just $15.5 million from its monthly land and drilling license sales in 2016 — the lowest annual total going back to the late 1970s. It was a decline over last year's sales, which saw totals of just over $18 million.
The province announced the results of its latest oil and gas rights auction Dec. 15. Ten drilling licenses, issued for five- to ten-year terms, went for an average price of about $60 per acre, while no land leases were sold. The sale of drilling rights for subsurface oil and gas accounts for 30 to 70 percent of B.C.'s total petroleum revenues, depending on market conditions, and is typically considered an indicator of future drilling activity.
Sales have been down since 2014 due to slumping oil and gas prices, as well as declining availability of high-quality land. In February, the province recorded its first-ever $0 land sale. Alberta brought in a record low $137 million at its drilling rights auctions this year. B.C.'s auction revenues peaked in 2008, when land agents plunked down $1.2 billion for the right to drill in the province.
Poll finds 54% of B.C. residents support oil sands pipeline project
(Vancouver Sun; Dec. 15) - More than half of British Columbians polled on behalf of an association representing Canada’s oil and gas industry support Ottawa’s approval of the Trans Mountain oil sands pipeline expansion. Fifty-four percent of British Columbians polled said they support the federal government’s green-lighting of the Alberta-to-B.C.-coast pipeline expansion, while 26 percent oppose the project.
The survey, conducted by Ipsos Canada for the Canadian Association of Petroleum Producers, notes B.C.’s level of support for the project is above the national average, which was recorded at 37 percent. On Nov. 29, Canadian Prime Minister Justin Trudeau announced approval of the $6.8 billion Kinder Morgan Trans Mountain expansion to triple the line’s capacity to 895,000 barrels a day. Construction is expected to begin in fall 2017 if the company can settle court challenges and threatened civil disobedience.
Oil stockpile in Oklahoma nears all-time record
(Bloomberg; Dec. 14) - For OPEC, there are few enemies more fearsome than the tiny Oklahoma town of Cushing. With oil inventories at Cushing creeping near an all-time high, U.S. benchmark futures prices are struggling to rise despite the promised production cuts agreed to by OPEC, Russia and other producers. And the storage tanks are likely to stay full as refiners park crude in Oklahoma to lower their tax bills.
Cushing, which prides itself as the “pipeline crossroads of the world,” is the delivery point for the West Texas Intermediate crude contract. With tanks that can hold 77 million barrels, it’s the biggest storage hub in the U.S. — and the tanks are filling up. For the OPEC-led efforts to boost prices, that’s a big problem. Too much oil in storage holds down pressure for higher prices. Cushing is getting more oil partly because of seasonal factors. Every year, U.S. Gulf Coast refiners try to reduce inventories in December to lower their tax bills, traditionally parking excess crude in Oklahoma and elsewhere.
Stockpiles rose by 1.22 million barrels last week, following a 3.78 million jump the previous week that was the biggest since 2008. The inflows have pushed up stocks to 66.5 million barrels, within a whisker of the all-time record of 68.3 million set in May. With the promise of production cuts sending forward prices up, that’s also encouraging traders and refiners to hold onto inventories to sell later at better prices, the last thing the Organization of Petroleum Exporting Countries wants to see.