LNG project developer could decide by April, B.C. official says
(Bloomberg; Nov. 16) - Petronas will be ready to decide whether to proceed with a proposed liquefied natural gas plant on the British Columbia coast by April, said Rich Coleman, the provincial minister of natural gas development. The state-owned Malaysian energy company, which won conditional Canadian government approval in September after more than three years of regulatory review, is in the process of reassessing the project’s costs, including those of steel, pipes and other inputs, he said.
“They need to go out and re-price the project,” Coleman said. “They hope to have that done in three to six months. Once they’ve done that, they’ll go back to the partners and decide whether to make a final investment decision.” British Columbia has been hoping for years to position itself as a gateway for LNG exports to Asia. “Before the project can proceed to a positive final investment decision, we need to ensure the project is competitive with similar projects around the world,” Petronas said.
Petronas is the majority owner of the multibillion-dollar Pacific NorthWest LNG project, which could produce as much as 19.2 million metric tons per year of the fuel, or about 8 percent of last year’s global trade. Its partners are China Petrochemical Corp., Japan Petroleum Exploration Co., Indian Oil Corp. and Brunei National Petroleum Co. The Sept. 27 regulatory approval from Canadian Prime Minister Justin Trudeau’s government came with 190 conditions, including a cap on greenhouse-gas emissions.
Statoil says decision on Tanzania LNG project at least 5 years away
(Reuters; Nov. 16) - The final investment decision on a $30 billion onshore liquefied natural gas export terminal in Tanzania will not be made for at least five years and possibly much longer, said Oystein Michelsen, Statoil's Tanzania country manager. "We are prepared for the project to take a long time, but we could bring it forward if the government is ready," he said on the sidelines of an investment conference in Tanzania. "We are not schedule-bound ... if the government delivers we would need five years.”
It would take another five years after the investment decision to build the plant, he said. Tanzania's natural gas reserves are estimated at more than 55 trillion cubic feet. The government is keen to promote the project but there has been little public discussion of the timeline. Outstanding issues include a stable framework with the host government, and clarity over local ownership requirements in some contracts, Oystein said.
In August, Tanzania President John Magufuli ordered officials to speed up long-delayed work on the project, a project involving BG Group (recently acquired by Shell), Statoil, ExxonMobil and Ophir Energy, in partnership with the state-run Tanzania Petroleum Development Corp.
Trade battle with Mexico could hurt U.S. natural gas industry
(Wall Street Journal; Nov. 14) - Donald Trump’s presidency is widely viewed as a boon for the U.S. energy industry, but some of his planned policies could pose problems for the natural gas business. He has pledged to tear up trade pacts and wall off Mexico, which could hurt the growing flow of U.S. natural gas to its southern neighbor. Mexico has become an increasingly important outlet for the fuel that has helped buoy U.S. domestic prices amid a glut of shale gas, analysts say.
“Mexico has been one of the few bright stories for prices and demand,” said Nicholas Potter, an analyst at Barclays, which warned clients on Election Day that Trump’s “trade policies would likely curb or at least limit incremental U.S. gas exports to Mexico.” A reduction in sales to Mexico could worsen the U.S. gas glut and pull down prices. It could also penalize the companies building pipelines to Mexico and the drillers, primarily in Texas, shipping their gas across the border.
U.S. natural gas shipments to Mexico reached an all-time high in August and accounted for almost 6 percent of total U.S. production. These exports have risen dramatically in recent years as U.S. prices have plummeted on abundant supplies of shale gas. This summer, Mexico’s imports of U.S. gas for the first time eclipsed its domestic production, which has declined more than 25 percent since 2010, according to S&P Global Platts. Meanwhile, demand in Mexico has risen 20 percent since the beginning of the decade.
U.S. natural gas exports exceed imports by 1 bcf a day
(Platts; Nov. 15) - In a historic first, the U.S. in early November began seeing net volumes of natural gas exports that climbed above 1 billion cubic feet per day, an analysis of data from Platts Analytics' Bentek Energy showed Nov. 14. The emergence and rapid acceleration in export volumes comes amid a recent decline in Canadian imports to the U.S. and a concurrent ramp-up in feed gas volumes delivered to the Sabine Pass, La., LNG export terminal.
In November, imports of Canadian gas have averaged just 4.5 bcf a day and are down 21 percent from imports that averaged 5.7 bcf in October. Over the same period, feed gas deliveries to Sabine Pass have climbed to record highs, averaging 1.5 bcf a day month-to-date in November, up from an average 0.25 bcf a day in October. In addition, U.S. pipeline gas exports to Mexico also are growing.
The dramatic ramp-up in feed gas deliveries to the Sabine Pass LNG export terminal comes following the end of maintenance activity in late October and the introduction of commissioning-feed gas volumes to Train 3.
U.S. sets new gas storage record at 4.017 trillion cubic feet
(U.S. Energy Information Administration; Nov. 16) - Working natural gas in U.S. storage reached a record high 4.017 trillion cubic feet as of Nov. 4, according to the Energy Information Administration’s latest Weekly Natural Gas Storage Report. Inventories have been relatively high throughout the year, surpassing previous five-year highs in 48 of the past 52 weeks.
The injection season for gas storage typically runs from April through October, although net gas injections sometimes continue for several weeks in November. The previous record for gas storage was set at 4.009 tcf for the week ending Nov. 20, 2015. This year, inventories have been relatively high in almost every region in EIA’s survey. Based on the National Oceanic and Atmospheric Administration's winter forecast, EIA expects U.S. average household gas consumption to increase 8 percent this winter.
IEA predicts 1.5% annual gas demand growth; less than past 25 years
(ICIS; Nov. 16) - Natural gas will be the fastest growing fossil fuel out to 2040 but the increase in demand will be slower than over the past 25 years, said the latest annual report from the International Energy Agency. Within the gas industry, LNG will account for a larger share of trade, as complex pipeline projects find it harder to gain support, the Paris-based agency said in its World Energy Outlook 2016.
In its baseline “New Policies” scenario, the IEA sees global gas demand growing annually at 1.5 percent out to 2040. That is below the 2.3 percent annual growth rate seen in the past 25 years, but still would make gas the fastest growing fossil fuel and increase its share in global primary energy demand from 21 percent today to 24 percent in 2040. The “New Policies” scenario is based on nations following through with current policies to tackle global warming, including acting on pledges made at the Paris summit.
The power sector is the largest gas consumer and would contribute more than one-third of the global growth in the “New Policies” scenario. The IEA noted, however, that although it now assumes lower gas prices than in its calculations last year, gas could still find it hard to compete against coal for baseload generation in Asia. The IEA also said the gas market will be “in flux” to the mid-2020s. The wave of new LNG capacity will gradually be absorbed, new players will enter the market, incumbents will be challenged and prices will eventually “rebound as the market rebalances.”
China National sees LNG as growth opportunity
(China Daily; Nov. 16) - China’s top offshore oil producer is eyeing liquefied natural gas as a major growth market after oil. “Liquefied natural gas will become another important pillar industry for the company, as new energy is playing an increasingly significant part in the national and the global energy industry,” said Jin Xiaojian, general manager of strategy and planning at the state-owned China National Offshore Oil Corp.
Natural gas production accounts for 18 percent of the company’s total, with oil accounting for the remaining 82 percent. However, the gas production proportion will see a gradual rise to around 20 percent in the near future, Jin said. “The company has become the nation’s biggest LNG trader and the world’s third-largest, and has imported liquefied natural gas from around 20 countries worldwide, including Australia, Indonesia and Qatar.”
CNOOC’s gas business currently covers 78 cities nationwide, with the company’s LNG imports soaring to 7.675 million metric tons in the first half of 2016, an increase of 24.4 percent year-on-year. The LNG imported by CNOOC accounts for 69 percent of China’s total. The country’s growing interest in gas is due in part to government efforts to move China’s energy supply away from its heavy reliance on coal. Gas consumption in 2015 grew by 3.7 percent, with a mix of domestic production, pipeline gas and LNG imports.
Turkey adding LNG import capacity, expanding pipeline volume
(Anadolu Agency; Turkey; Nov. 15) – Turkey’s BOTAŞ Pipeline Corp. aims to increase the capacity of its natural gas distribution system to 12.3 billion cubic feet per day from 7 bcf a day currently. BOTAŞ moves an average of more than 3 bcf a day of Russian gas, and more than 1.6 bcf from Azerbaijan and Iran. The country’s two liquefied natural gas import terminals have the capacity to receive and add to the pipeline grid more than 1.5 bcf a day, with BOTAŞ planning to expand one of the terminals by 50 percent next year.
BOTAŞ is working to increase Turkey’s energy supply security and diversify its gas sources, including expanding LNG receiving, storage and regasification capacity. Work continues on two new floating receiving, storage and regasification units, scheduled for completion in 2019 with a capacity averaging 1.4 bcf a day of gas.
Pakistan expects delivery of second floating LNG terminal next year
(The Internal News; Pakistan; Nov. 15) - Pakistan is likely to receive its second floating storage and regasification unit for handling liquefied natural gas imports next year, a short delay from the original in-service date of the end of this year. The vessel is currently at Samsung Heavy Industries in South Korea. It will be capable of storing more than 3 billion cubic feet of natural gas as LNG, with a peak regasification capacity of 750 million cubic feet per day.
Pakistan, largely dependent on imported fuels, will be importing a cumulative 3 bcf a day as LNG by 2018 to bridge the demand-and-supply gap, which has already crossed the 4 bcf a day mark. Pakistan currently is importing about 0.6 bcf a day as LNG, with plans to boost that volume over the next couple of years. The government is negotiating with six countries, including Russia, Malaysia and Oman to import LNG.
Australian energy company considers LNG imports to ease shortage
(Reuters; Nov. 14) - AGL Energy is considering importing liquefied natural gas to southeastern Australia starting in 2021 in a move that could ease the grip on gas supply that domestic producers hold in the region. Australia is on track to become the world's top exporter of LNG, but that is paradoxically creating a shortage at home as gas is pulled away from local markets in the southeast. The Australian Energy Market Operator sees a shortfall in domestic gas looming after 2019.
AGL, one of Australia’s largest gas and electricity providers, said Nov. 14 it was running a $17 million ($13 million U.S.) study on building an LNG import terminal, and aimed to make a final investment decision in 2018-19 on a project that it estimated would cost between $200 million and $300 million. Import cargoes could come from as far away as Europe, the Middle East, Africa, the United States and Asia, despite the fact that by then Australia will have 10 LNG export plants.
"We are really staring through the looking glass when the world's largest exporter of LNG is considering importing gas in the face of unaffordable domestic prices," said Bruce Robertson, an analyst at the Institute for Energy Economics and Financial Analysis. In a taste of what would happen without new sources of gas, prices in Victoria rocketed in July to six times the level of Asia LNG during a cold snap, as demand had to be met with gas diverted from LNG plants in Queensland and piped 1,200 miles south.
Natural gas drilling in northeastern B.C. at lowest level since 1993
(Vancouver Sun; Nov. 16) - Natural gas drilling in northeastern British Columbia has fallen to a 23-year low as producers continue to navigate a complicated market dogged by a supply glut in the United States and lack of outlets outside of North America for the fuel. At the end of October, producers had punched just 267 new wells in the region, according to figures from the B.C. Oil & Gas Commission, down 40 percent from the 450 new wells drilled a year ago — and a level not seen since 1993.
North America’s natural gas storage facilities are “fairly full,” and nothing has happened to change the fact that Western Canada’s biggest market, the U.S., with all of its own shale gas production, has become Canada’s biggest competitor in the past five years, said Dave Tulk, an energy-sector consultant and principal with Calgary-based Gas Processing Management. While production from British Columbia and Alberta has remained relatively flat, U.S. shale producers continue to expand production.
The shorter-term market dynamics continue to put a hole in Alberta’s provincial revenues from the resource. Royalties from natural gas plummeted to just $2 million in the first quarter of the province’s fiscal year, ending June 30, compared with $32 million estimated in its 2016-17 budget, and down from $51 million in the same quarter a year ago, reflecting those dismally low prices earlier in the year.
Half of all land-based drilling rigs in U.S. at work in Permian Basin
(EnergyWire; Nov. 14) - Drillers in West Texas had only begun to latch on to the shale oil revolution in 2014. Most wells were still vertically drilled, but oil companies were beginning to dabble in horizontal drilling and hydraulic fracturing. Then the bottom fell out of the global oil market. Today, the Permian Basin is reinventing itself, despite the 2-year-old plunge in oil prices. Drilling rigs are at work and new businesses are cropping up, touting water delivery and wastewater services for the fracking industry.
The Permian is repositioning itself to become the dominant shale oil force in the U.S. as the industry recovers. By some estimates, the Permian's oil fields hold the equivalent of eight Bakken Shale basins, the booming North Dakota reserve. "It's as hot as I've ever seen it," said Patrick Van Ooteghem, with Venable Royalty out of Dallas. The Permian now is home to about half of all active U.S. land rigs. Oil-field services giant Baker Hughes recently put the Permian's rig count at 218, up from 132 at the end of April.
The arid region is dominated by cattle ranching and oil and gas. But 275 million years ago, the Permian was covered in a shallow sea. The warm, oxygen-rich and sun-rich environment grew shallow-water aquatic life that, in death, settled on the seabed. This organic matter was eventually covered in sediment. It was slowly cooked under extreme pressures and temperatures to form the hydrocarbon reserves chased by humans in modern times. The Permian Basin's oil fields first opened up in a big way in the 1920s.
Approval looking more likely for oil sands pipeline expansion
(Bloomberg; Nov. 14) - Prime Minister Justin Trudeau has set the table for Canada to approve the Trans Mountain oil sands pipeline expansion by announcing environmental measures aimed at placating opposition to the project. He unveiled a national carbon price in October, and in the past few weeks has pumped billions into marine protection and "green" infrastructure, as well as begun an overhaul of the federal energy regulator and granted crown protection to a rainforest that essentially blocks a rival proposal.
The prime minister has also backed a hydroelectric dam and natural gas project favored by British Columbia Premier Christy Clark, as any quid-pro-quo support from her for Kinder Morgan’s Trans Mountain project would help him claim consensus ahead of the Dec. 19 deadline for a decision by the Trudeau cabinet. However, opposition from Vancouver’s mayor, indigenous communities and environmentalists will test Trudeau's resolve to approve the pipeline and defend the decision against a likely court challenge.
“You could interpret all these signs as part of a grand design to make construction of one or two pipelines possible,” said Tom Flanagan, a former adviser to Stephen Harper, Trudeau’s predecessor. “Let’s hope he has the stomach to see it through if the opposition continues after the announcement of cabinet approval, because I think it will.” Trudeau and his officials regularly stress Canada’s need to get its resources to tidewater. Expansion of Kinder Morgan’s pipeline from Alberta to the B.C. coast would move an additional 590,000 barrels a day down the 710-mile line to a shipping terminal.
IEA sees less Canadian oil production under climate change policies
(The Financial Post; Canada; Nov. 16) - The world’s thirst for oil will not diminish over the next few decades, but Canadian production will not grow as swiftly to meet that demand, said a new report by the International Energy Agency. The latest World Energy Outlook expects Canadian output to grow to 6.1 million barrels per day by 2040 if governments stick to their Paris agreement pledges — but that’s 1.5 million less than the IEA scenario that assumes no new international policies to fight climate change.
Over the past few years, the IEA has been steadily cutting its Canadian oil output forecast. Last year, the Paris-based agency estimated 2040 production primarily from the oil sands to grow to 6.8 million barrels per day — which was 600,000 barrels less than its 2014 forecast. Now, it’s looking like 6.1 million barrels. Despite the challenges, the Canadian oil and gas sector will remain an investment magnet, attracting $1.1 trillion over the next 24 years, the IEA said.
Analyst suggests $35 oil possible if OPEC cannot agree on cuts
(Bloomberg; Nov. 13) - OPEC members need to stop bickering over output curbs or risk the group becoming irrelevant to global oil markets, said an analyst who predicted the biggest price crash in a generation. It’s in the interest of all producers to reach a deal that’s aimed at stabilizing prices, which are 61 percent lower than their 2014-highs, said Gary Ross, executive chairman at PIRA Energy Group, now a part of S&P Global Platts.
A failure to implement an agreement could drag down crude to as low as $35 a barrel, while success at the group’s meeting later this month could push oil to $60. Crude slumped below $45 a barrel earlier this month amid concern over the ability of the Organization of Petroleum Exporting Countries to implement a deal to cut production for the first time in eight years.
Key members Iran and Iraq argue they should be exempt from output cuts. OPEC ministers will meet in Vienna on Nov. 30 to decide how to share the burden. “OPEC has to reach a deal to become relevant again,” Ross said. “Our view is that they will cut and I think when push comes to shove, they will collectively agree.” The International Energy Agency shared its own opinion Nov. 10, forecasting that prices may retreat amid “relentless global supply growth” unless OPEC enacts significant production cuts.