Russia asks Saudi Arabia to participate in Arctic LNG project
(Reuters; July 6) - Russian Energy Minister Alexander Novak said his country’s energy cooperation with Saudi Arabia was "top flight" and would deepen if Riyadh took up an offer to participate in a Russian Arctic liquefied natural gas project. Russia and Saudi Arabia, the world's top oil producers, joined forces in the past year in a deal with other nations to cut oil output and lift global oil prices, although that effort has been undermined by rising production elsewhere.
To expand cooperation, Novak said state-owned Saudi Aramco was offered a role in the proposed Arctic LNG-2 project led by Russia's largest private gas producer, Novatek, which aims to start construction on the development in 2022-2023. "Saudi Aramco was offered different options of participation in Arctic LNG-2," Novak said, without elaborating on the kind of role envisaged for Saudi Arabia.
In early June, Saudi Energy Minister Khalid al-Falih was asked by Russia's TASS news agency whether the kingdom would be interested in taking part in Arctic LNG-2. He responded: "All is possible but it's premature to talk about specifics." Novatek, with Chinese partners and its major shareholder Total, is building its first liquefaction and export plant, Yamal LNG, with first gas scheduled for late this year. Russia is looking to double its share of the global LNG market by 2020.
U.S. LNG developers continue work regardless of Qatari expansion
(Bloomberg; July 5) - America’s gas exporters, at least for now, are brushing aside Qatar’s bid to claim a bigger share of the global market for liquefied natural gas. Qatar’s plan to dramatically boost gas output signaled to rivals — including Australia and the U.S. — that the race is on to find buyers and lock them into long-term contracts. U.S. LNG exporters have already spent years pursuing such agreements, which are needed to finance the multibillion-dollar export terminals under construction and still proposed.
The impact of Qatar’s gas plans will hinge largely on whether the world’s biggest LNG supplier can secure more long-term supply agreements with buyers in Europe and Asia. U.S. exporters already have contracts to supply more than 80 million metric tons of LNG a year, according to estimates by Bloomberg New Energy Finance, though developers are vying for even more contracts to build additional terminals over the next decade.
Some industry executives have suggested the U.S. may even jump ahead of Qatar and Australia to become the world’s biggest LNG supplier by 2035 — a threat Qatar may be looking to quash with its latest move. Qatar still stands to make life more difficult for U.S. LNG suppliers. The North Field expansion will allow Qatar to sell more of some of the cheapest gas in the world, said Victoria Zaretskaya, a Washington-based analyst for the U.S. Energy Information Administration. That’ll have “major implications” for U.S. LNG export terminals that companies are proposing in the next decade, she said.
Sales to China an opportunity for U.S. to show its LNG strength
(EnergyWire; July 6) - In his visit to the Energy Department last week, President Trump reveled in the "America First" image of the United States as the new global energy superpower, with rising cargoes of oil, gas, petroleum products and coal crisscrossing the seas. But glutted global markets ruled by low prices and stiff competition will be the true test for what the administration can actually do to boost U.S. energy exports. Deals for liquefied natural gas exports to China could grab the headlines.
That’s the possibility, broached by Commerce Secretary Wilbur Ross, that China will sign long-term commitments to buy U.S. liquefied natural gas and double down by investing capital needed to start a new round of LNG export terminal construction in this country. A May 11 trade agreement between the Trump administration and China's government sets the stage for expanding LNG shipments.
U.S. suppliers provide about 7 percent of China's LNG imports, according to a Wood Mackenzie analysis. And with China’s LNG demand perhaps tripling by 2030, the opportunities are enormous, according to the research firm. Nicholas Potter and Blerina Uruci, with Barclays Research, noted that China has been “noticeably absent from the first round of U.S. LNG contracting.” However, the ability of Chinese companies not only to sign long-term purchase contracts but also to contribute billions of dollars of capital to the cost of new U.S. LNG facilities could move some projects to construction, they said.
Tanzania’s new resource development laws could hurt LNG proposals
(Natural Gas Daily; July 6) – Tanzania’s parliament July 3 passed two new laws to give the government sweeping control over the country’s natural resources, including the power to renegotiate contracts in favor of the state at any time. The new legislation could seriously affect multibillion-dollar liquefied natural gas export projects proposed for the East Africa country.
President John Magufuli has said the legislation will bring greater transparency to the extractive industries and lead to fairer distribution of the country’s resource wealth. However, the uncertainty the new laws create — and the fact that they forbid the arbitration of disputes in international courts — could kill off private-sector investment in Tanzania altogether.
The Natural Wealth and Resources Contracts (Review and Renegotiation of Unconscionable Terms) Act, allows the government to renegotiate all mining or petroleum contracts to ensure they “protect the interests” of the Tanzanian people. The Natural Wealth and Resources (Permanent Sovereignty) Act, bans the export of raw minerals and rules that all disputes should be settled in Tanzanian courts. Several multinational oil and gas companies are looking at developing an LNG export project in Tanzania to monetize the country’s substantial offshore gas reserves.
Australia forecasts LNG output to come in 5% below earlier estimate
(Platts; July 7) - The Australian government July 7 lowered its forecast for the country's fiscal 2017-18 (July to June) liquefied natural gas exports by 3.8 million metric tons, due mostly to delayed start-up of the Ichthys LNG project, an offshore development led by Japan’s INPEX Corp. The Department of Industry, Innovation and Science revised its forecast for fiscal 2017-18 LNG exports to 63.8 million tonnes, down from 67.6 million in March.
While pointing to the delay from late 2017 to March 2018 for the Ichthys LNG project, as well as minor revisions to production forecasts for other projects, the report also flagged intensifying global competition and federal government LNG export restrictions as casting uncertainty over the outlook. Two other projects are scheduled to start up in Australia in the fiscal year: the Chevron-led Wheatstone project and Shell-led Prelude floating LNG facility, totaling more than 12 million tonnes at full production capacity.
"The extent of the (production) decline will depend on the cost competitiveness of Australian LNG projects and the amount of flexibility in Australian LNG contracts," the government forecast said. "LNG contracts often include clauses which allow buyers to reduce purchases to minimum 'take-or-pay' levels. It is possible buyers may utilize these provisions if oil-linked contract prices remain higher than spot prices, or if they become over-contracted for LNG," the report said.
Japanese sponsor says Ichthys LNG on track for first gas March 2018
(Reuters; July 10) - A massive floating component for INPEX Corp's $37 billion Ichthys liquefied natural gas project in Australia will soon sail from the South Korean shipyard where it is being built, the Japanese company and its shipbuilder said July 10. INPEX and South Korea’s Daewoo Shipbuilding & Marine Engineering have denied reports of technical problems in the floating production, storage and offloading unit. When the project is at full capacity, Ichthys is set to produce 8.9 million tonnes of LNG per year.
INPEX, Japan's biggest energy explorer, said there has been no change in its latest plans to begin gas production and shipments by the end of March. The project, the first LNG development managed by a Japanese company, has been hit with delays, contract disputes and overruns. In April, INPEX said start-up would be delayed up to six months to the end of March 2018, citing issues with installation of offshore production facilities. The gas will be piped 545 miles to an onshore liquefaction plant and export terminal.
INPEX and Daewoo said construction of the offshore production unit was complete, after CNBC reported on the existence of a crack in the massive piece of equipment that processes output from the gas project, which includes liquid petroleum gas and condensate. CNBC cited unnamed sources. A Daewoo spokesman said he was not aware of any crack. The unit was originally scheduled to leave the shipyard by the end of last year. An INPEX spokesman said there were no technical issues, at the moment.
Japanese firm would help build proposed LNG plant in Oregon
(Nikkei Asian Review; July 7) - Japan's JGC, a global engineering firm, and two U.S. engineering groups have signed on to build a liquefied natural gas export terminal in Oregon, provided that the Calgary-based sponsor of the project wins federal approval and decides to proceed with the investment. JGC would join Kiewit and Black & Veatch on the project, estimated at up to $6 billion. JGC’s portion is expected at nearly 200 billion yen ($1.76 billion). The plant’s output would be 6 million tonnes of LNG per year.
The Jordan Cove LNG project sponsor, Veresen, restarted its application at the Federal Energy Regulatory Commission in February after FERC last year rejected the LNG terminal and accompanying 232-mile gas pipeline to the plant site in Coos Bay. Working toward making the project economically viable, Veresen last year reached a non-binding preliminary deal to sell LNG to Jera Co., a joint fuel-supply venture of two Japanese utilities. The 20-year deal, if implemented, would cover 25 percent of the plant capacity.
Gas and renewables eat away at coal’s share of power market
(Wall Street Journal; July 5) - Not long ago, coal provided 98 percent of the electricity for the pulp-and-paper mills and iron-ore producers around the western edge of Lake Superior, as well as nearby Duluth, Minn. That was 2005. Today, coal use is plunging, and by 2025 it’s expected to power just one-third of the region. It’s part of a plan by the utility, Minnesota Power, to generate 44 percent of its electricity from renewable sources like wind farms. It also plans to build a new high-efficiency gas-fueled power plant.
The utility has already closed six of its eight coal-fired units. The transition is happening across the U.S. as gas, wind and solar power are expanding rapidly, while electricity generation from coal and nuclear reactors is shrinking. It isn’t just small utilities like Minnesota Power that are changing their mix. Duke Energy, a large utility based in Charlotte, N.C., generated 7 percent of its power from gas and renewables in 2005. Last year, Duke got 32 percent from those sources and expects 44 percent by 2026.
According to nationwide statistics, gas, wind and solar now meet 40 percent of U.S. power needs, up from 22 percent a decade ago, according to the U.S. Energy Information Administration. As gas and renewables have grown, coal, the mainstay of American electricity generation for decades, the past few years has been a bloodbath. Three of every 10 coal generators has closed permanently in the past five years. Gas has been the main agent of change, mostly because the advent of hydraulic fracturing unlocked vast new natural gas reserves in the U.S., creating very low prices for the fuel.
Idaho Power shutting down coal-fired power plants early
(EnergyWire; July 10) - As Idaho Power Co. undergoes its transition to what it calls a "new energy world," wholesale electricity market conditions are driving a decision to retire its coal plants earlier than previously planned. The utility has ownership stakes totaling 1,118 megawatts in three coal-fueled plants, with the remainder of its generation consisting of three gas plants, a diesel fuel plant and market purchases.
Its coal plants had been scheduled for retirement between 2019 and 2032, but the utility now says it will work with its partner to shutter the plants early. Altogether, the utility will retire more than 730 megawatts of coal-fired capacity, leaving just two units in operation until 2036. The decline in output from its coal fleet is driven "by low natural gas prices and the expansion of renewable generating capacity," along with prices "too low to merit economic dispatch of coal generating capacity.”
"A new energy world, driven by technological innovation and changing customer preferences, is emerging, one that is efficient, green, resilient and interconnected," Idaho Power said. It could take six to 10 months before state regulators approve the utility’s revised power management plan.
Fracking ban limits gas supply in Canada’s Maritime provinces
(JWN Energy Group; Edmonton; July 4) - Tough decisions are ahead for Nova Scotia and New Brunswick as a gap looms between domestic natural gas supply and demand, the Canadian Energy Research Institute indicated in a study released July 4. Natural declines in both offshore and onshore production will increasingly conflict with rising demand in both provinces over the next 20 years, CERI said, noting that hydraulic fracturing of wells, which could unlock large resources, is currently prohibited.
“With dwindling offshore production and increasing local demand for natural gas, both jurisdictions will need to weigh the options moving forward, how and where local demand for natural gas will be met,” CERI said. “The interesting irony is that Nova Scotia and New Brunswick have extensive histories in oil and gas exploration and production, New Brunswick dating back to 1859 — the same year as Pennsylvania’s famous Drake well — and may yet become larger oil and gas players in the future.”
Combined, the Frederick Brook Shale in New Brunswick and the Horton Bluff Shale in Nova Scotia are estimated to hold up to 136 trillion cubic feet of gas. CERI developed three scenarios in its report, based on whether the provinces develop additional gas resources: Imports, self-sustaining, and exports. In its “We are Exporters” scenario, CERI envisions lifting the fracking moratoriums and the provinces pursuing more production growth with investment in liquefied natural gas exports.
Apache sells all of its Canadian assets; will exit the country
(The Financial Post; Canada; July 7) - Apache says it has sold its assets in British Columbia, Alberta and Saskatchewan for close to $1 billion in a strategic exit from Canada. The Houston-based oil and gas company said July 6 that leaving Canada was part of its goal of streamlining its portfolio to focus on projects in the United States, United Kingdom and Egypt.
Apache said the sell-off will mean a significant reduction in its costs, as well as improve the revenue and cash generated on the energy it produces. It said the $125 million in spending planned for 2017 and 2018 in Canada would be redirected to other areas of its portfolio. The company said it is selling off its Canadian assets in a trio of deals worth about $927 million to Paramount Resources, Cardinal Energy and an undisclosed privately owned company.
U.S. oil exports to China averaged 180,000 barrels a day April and May
(Wall Street Journal; July 6) - It was a gusher few expected. What began as a trickle of U.S. crude being sold to China is turning into a flood, the result of a surprise American glut that has made the country’s oil cheaper than Mideast rivals just two years after Congress lifted a 40-year export ban. China bought nearly 100,000 barrels of oil a day from the U.S. in the first five months of 2017 — 10 times the average in 2016. Imports in April and May surged to an average of more than 180,000 barrels a day.
The shift has been greeted with enthusiasm by U.S. producers, who have been trying to pull the sector out of a three-year slump. Industry executives and local officials are now scrambling to retool Gulf of Mexico ports to accommodate the large vessels needed to ship vast quantities of crude around the globe. While still far below the figure China pays its top suppliers — Russia, Saudi Arabia and Angola — the bill for U.S. oil could come in well above $1 billion this year, up from $150 million last year.
Falling production from China’s aging fields has forced the country to step up its hunt for new supplies. The search came as America was opening oil exports in 2015 for the first time in four decades amid a boom in drilling. Political uncertainty in the Mideast also has played a role. The economics have tilted in favor of the U.S. partly because of OPEC production cutbacks that have pushed up the price of benchmark Brent and Dubai oil. At the same time, rising U.S. shale output has pushed down the cost of American crude.
Offshore drillers say business is showing signs of recovery
(EnergyWire; July 5) - Offshore drilling is showing signs of a revival, despite lingering uncertainty over low oil prices. Major new deals are being made, and rigs are being put back to work. Some consolidation in the offshore drilling rig market is moving ahead. Meanwhile, major oil companies are returning to sanctioning large greenfield projects, such as ExxonMobil's recent decision on a South American offshore project in Guyana.
All indicators could point to a resurgence in offshore drilling internationally, unless oil prices collapse again. Prominent offshore explorers and producers have boasted that new technology and efficiencies now permit them to sanction projects at just $40 per barrel. Rig operators hit hard by the industry's downturn could see new business opportunities, given oil companies' success in reducing their operating costs. Several offshore drilling contractors have announced new work for their vessels in recent weeks.
Maersk Drilling said it has secured a contract for another rig, the fourth rig it has managed to put back to work after the fall in oil prices forced it and several other contractors to idle vessels. Maersk isn't alone. Competitors Ensco, Vantage Drilling and Seadrill have all reportedly landed new contracts for previously idled equipment, or extensions on contracts that were earlier in doubt.