Canadian exporter, Chinese buyer may partner on import terminal
(Reuters; May 18) - Guangzhou Gas Group plans to build a 2 million tonne per year import terminal for liquefied natural gas on China's southern coast by 2020, possibly in partnership with Woodfibre LNG, an executive with the Chinese firm said. The company agreed in 2016 to buy 1 million tonnes of LNG annually for 25 years from the export facility that Woodfibre — a subsidiary of Singapore company Pacific Oil & Gas — is building at a former pulp mill site about 40 miles north of Vancouver, B.C.
The proposal for joint investment in the LNG receiving terminal at Guangzhou port reflects efforts by LNG buyers and producers to share risks, Liu Jingbo, deputy general manager of Guangzhou Gas, said May 18. Local government-backed Guangzhou Gas is one of China's fast-growing independent players in the LNG sector, outside dominant state giants like China National Petroleum Corp. and China National Offshore Oil Corp. It has emerged over the past few years as a niche importer and infrastructure investor.
Backed by Indonesian billionaire Sukanto Tanoto, site preparation is underway at the $1.6 billion Woodfibre LNG project. The company plans to award a construction contract later this year and start production in 2020. To secure gas beyond the Woodfibre deal, Guangzhou Gas is looking for more flexible supplies under shorter terms, maybe three or five years, Liu said. Guangzhou Gas supplies some 90 percent of the city's gas demand, with consumption forecast to more than double to almost 125 billion cubic feet a year in 2020 from current levels, driven by industrial, commercial and power sectors.
China oil and gas exec says U.S. will be a source of supply
(Bloomberg; May 14) - China is setting its sights on U.S. energy as a growing reliance on imports forces it to look beyond traditional suppliers, according to the head of the country’s biggest oil and gas company. China National Petroleum Corp. will import more oil and gas from the U.S. and will consider participating in America’s growing liquefied natural gas export industry, Chairman Wang Yilin said in an interview May 14 with Bloomberg on the sidelines of the economic initiative Belt and Road Forum in Beijing.
“The U.S. has very rich oil and gas resources, and as China pursues a diversification of its crude supply the U.S. will of course be one of the sources.” Wang said. “We will consider exploring cooperation in areas such as jointly developing liquefied natural gas facilities and gas transport.” Wang’s comments follow a deal between China and the U.S. announced May 11 that encourages long-term contracts with U.S. LNG suppliers. The agreement with could help pave the way for investment in U.S. LNG terminals.
The world’s biggest energy user is becoming more reliant on overseas oil supplies as production at home plummets after state-run firms cut spending to cope with the price crash. Though China’s oil giants are raising combined spending for the first time in four years, that may not be enough to halt the drop in domestic crude output.
The $20 billion in deals to be signed during the Belt and Road Forum include Saudi Arabian Oil Co. taking a stake in China National’s Yunnan refinery, a $4 billion deal for a gas processing plant in Azerbaijan with the state oil company, gas storage and gas-fired power projects with Russia’s Gazprom, and a geothermal project in Kenya.
Analysts expect more Canadian gas will go out as U.S. LNG
(Financial Post; Canada; May 12) – U.S. liquefied natural gas exporters have been courting Canadian producers, and analysts expect more northern gas will move south in the absence of Canadian LNG projects. “The North American gas market is going to be one market,” said Advantage Oil and Gas CEO Andy Mah, especially with improving pipeline connections. Though developers have proposed several LNG export terminals in Canada, none of the larger projects have committed to construction.
“The last thing you want to do is have your gas trapped in Alberta,” said Calgary-based Stream Asset Financial Management’s Dan Tsubouchi. At a recent industry conference, Calgary-based Painted Pony Petroleum CEO Patrick Ward said demand for Canadian gas is building, in part because of growing LNG exports from the United States. Calgary-based Seven Generations Energy has an agreement to send its gas through Cheniere Energy’s LNG export terminal in Sabine Pass, La. Seven Generations CEO Marty Proctor said the company was sending 100 million cubic feet per day.
“I know that a number of Montney producers are trying to figure out what the opportunity is,” GMP FirstEnergy director of institutional research Martin King said of the prolific shale play that straddles Alberta-B.C. Cheniere spokesperson Eben Burnham-Snyder wouldn’t name specific Canadian producers but confirmed that his company has been in talks with multiple companies about sourcing their product for its export operations. “We’re willing to talk to any supplier we can access — in Canada and the U.S.”
Oregon county voters defeat initiative to block LNG project
(Reuters; May 17) - A coastal Oregon county overwhelmingly rejected a ballot measure May 16 aimed at blocking a proposed liquefied natural gas terminal, dealing a blow to what was the latest in a series of efforts to thwart energy projects across the Pacific Northwest. The measure, had it passed, would have banned transport of fossil fuels not intended for local use through Coos County, located about 200 miles south of Portland.
About 76 percent of votes were cast against the measure, according to results posted on the county website. "This ballot measure was not a good measure by any means, and I think (the voters) were able to see that," said Coos Bay Mayor Joe Benetti, who opposed the measure. Supporters of the ballot initiative were targeting Calgary-based Veresen’s proposal to build an LNG export terminal, the Jordan Cove LNG project. Federal regulators rejected the project last year, but the developer has reapplied with a revised plan and is hoping for a better answer under the Trump administration.
The initiative was part of regional resistance in the Northwest to fossil fuel projects that has seen the blockage of several major export facilities. Last year, the Lummi Nation Native American tribe and environmental groups blocked an export terminal in Northwest Washington that would have moved Montana and Wyoming coal to markets in Asia. In January, Washington state denied a permit for a coal export terminal in the city of Longview, citing concerns about the financial viability of the project.
Weak LNG prices threaten costly coal-seam gas projects in Australia
(Australian Financial Review; May 15) - Queensland's high-cost LNG exporters may have to curtail production as some drilling becomes uneconomic amid depressed prices caused by a global supply glut, energy consultancy Wood Mackenzie warns. In what he calls the coming "LNG wars," analyst Saul Kavonic will tell the Australian Petroleum Production & Exploration Association conference that the ongoing need for more drilling makes the projects particularly vulnerable in an extended period of low prices.
Wood Mackenzie believes the growing oversupply in the market means that in a few short years the focus of the industry has switched from where the next major LNG project would emerge to how to ensure existing ventures survive and keep running. Most analysts forecast the current oversupply in global LNG will persist for several more years, putting renewed pressure on spot prices as more plants start production.
Kavonic said in an outline of his May 15 presentation that while Australia's conventional LNG projects lie low on the short-term cost curve, it’s different for the Queensland ventures that have to keep drilling hundreds of coal-seam gas wells each year to maintain supplies. Kavonic calculates that by 2019, while 84 percent of Queensland's LNG production will be from completed wells and will be low cost, the other 16 percent is at risk of not being profitable to drill. "In each subsequent year the percentage of undrilled production at risk of being uneconomic grows," he said.
Chevron shuts down liquefaction train at Gorgon for a month
(Reuters; May 15) - Chevron has shut the first production line at its giant Gorgon liquefied natural gas export plant in Australia and expects the outage to last about a month in order to replace a faulty flow-measurement device, a spokesman said May 15. Chevron has struggled to maintain stable production at the $54 billion project, which came on stream in March last year. This month’s shutdown is at least the eighth outage since operations started at the most-expensive project in the company’s history.
Gorgon's third production line started up in March 2017, bringing the plant’s export capacity to 15.6 million tonnes. It is unclear if recurring production setbacks could hinder or delay Chevron's plans to bolster the efficiency of the plant and lift production capacity through a process known as debottlenecking. Chevron said trains 2 and 3 were running normally and the plant is continuing to ship cargoes.
LNG import prices in Japan, the world’s biggest buyer, averaged about $9 per million Btu in 2009 when the Gorgon project was sanctioned, then shot up as high as $18 during construction before sliding back below $6 after it started production amid a global glut, according to data from LNG Japan Corp. Chevron holds a controlling stake of 47.3 percent in the project, while ExxonMobil and Shell each have a 25 percent stake. The remaining stakes are held by Osaka Gas, Tokyo Gas and Japan’s JERA Co.
East Coast Canada LNG hopeful wants to buy producing assets
(Reuters; May 15) – Pieridae Energy, the company behind a proposed liquefied natural gas export terminal on Canada's East Coast, is looking to buy gas-producing assets in Western Canada or in the Marcellus shale play in the United States, its chief executive said May 15. Alfred Sorensen told Reuters that Calgary-based Pieridae wants to buy about 200 million cubic feet a day of gas production to supply its terminal and would consider buying a company or just assets.
Privately held Pieridae wants to develop the Goldboro LNG project in Nova Scotia, with a targeted in-service date of 2021 and capacity of 10 million tonnes of LNG per year (more than 1.3 billion cubic feet of gas per day). "What we really want is a resource with potential to grow into rather than producing right now," Sorensen said. "Pieridae's plan from the beginning was to be a fully integrated LNG facility owning the upstream as well as the terminal." He said Pieridae would look for acquisitions later this year.
Pieridae expects to make an investment decision on the terminal later this year, and estimates the project at $7.3 billion. German utility Uniper has committed to buying output from the first of two liquefaction trains at Goldboro and owns a 1 percent stake in the terminal, Sorensen said. More than a dozen Canadian LNG exports terminals have been proposed for the Atlantic and Pacific coasts, but none of the large-scale projects have received a final go-ahead as developers face low prices and a global oversupply.
Lack of drilling activity in Mexico leads to need for more U.S. gas
(The Hill; May 15) - The onshore rig count in Mexico fell to one in March, a particularly ominous sign for a country that is attempting to dramatically increase its reliance on natural gas for power generation. With a declining domestic resource base, Mexico will increasingly rely on U.S. pipeline gas and imported liquefied natural gas and may be forced to backtrack in the short term on some of its energy goals by returning to heavier reliance on oil for power generation.
Total Mexican dry gas production fell to 3.2 billion cubic feet a day in March, according to the most recent data from Mexico’s Secretaría de Energía. That marks a 14 percent decline from March 2016 levels. The lack of drilling activity will likely lead to further production declines through the rest of the year and into 2018. The primary indicator for future production is drilling, and the Mexican drilling fleet is down to only six total rigs.
This downward trend contrasts sharply with the trend in the United States, where total active rigs have recovered by 62 percent over the same timeframe. What is starkly apparent is that while U.S. drillers have demonstrated price responsiveness as the oil markets have strengthened, Mexico drillers continue to forestall drilling activity, which will almost certainly drive gas production lower over the near-term.
Gas production growing again at Haynesville Shale
(Bloomberg; May 16) - A gas basin that helped kickstart the U.S. shale boom a decade ago is getting a new lease on life as the market recovers. Production in the Haynesville reservoir will climb for the seventh straight month in June, reaching the highest since October 2014, government data show. Output in the play, located in Louisiana and East Texas, fell to a six-year low last March, pressured by tumbling gas prices and competition from gushier, more profitable wells in Pennsylvania and West Virginia.
As pipeline bottlenecks strand gas supplies in the eastern U.S., the vast network linking the Haynesville to the rest of the country — along with a new liquefied natural gas export terminal in Sabine Pass, La., shipping gas overseas — has made production in the play more valuable. Drillers have refocused resources there to slash production costs, while private-equity backed companies bought assets to do the same. Production is about 4 billion cubic feet of gas a day, and growing.
“Once left for dead, the Haynesville Shale in Louisiana and East Texas is in the midst of a resurgence as new well designs bring natural gas gushers to life,” William Foiles, a New York-based analyst for Bloomberg said in a May 12 report. “Redesigned wells have since expanded the Haynesville’s untapped potential, with output expected to rise as capital and rigs return.” The gas market’s rebound has created strong economics to drill in the Haynesville, said Hal Hickey, CEO of Dallas-based Exco Resources.
South Korean president orders temporary closure of older coal plants
(Platts; May 15) - South Korea's new President Moon Jae-in on May 15 ordered a temporary shutdown of aged coal-fired power plants in an urgent move to address worsening air pollution, which will likely boost LNG demand for power production. Under the order, eight coal-fired power plants aged 30 years or older will be closed for 30 days starting June 1, the presidential office said.
The plants have a total capacity of 2,745 megawatts, about 8.4 percent of the country's total coal-fired power capacity and 2.5 percent of the country's total generation capacity. All of the plants are owned by the country's state-run electricity monopoly, Korea Electric Power. The one-month shutdown will have little impact on the country's overall power supplies because they can easily be replaced by more costly but less polluting liquefied natural gas-fueled power plants largely run by private companies.
The eight coal-fired plants will be closed again for four months during off-peak spring season from March to June each year starting in 2018, the presidential office said. South Korea runs 10 coal-fired power plants aged 30 years or older, but two have been excluded from the temporary shutdown this year due to a possible power shortage in the industrial zone where they are located. However, all 10 of the coal-fired plants will be permanently shut by May 2022 when Moon leaves office, the presidential office said.
U.S. shale potential could hold down OPEC-led price gains
(CNBC; May 16) - OPEC, Russia and other major producers could help drive oil prices back to $60 per barrel or more with a new production deal, but that would also be a green light for U.S. shale drillers. At $50, and even more so at $60, U.S. oil drillers can profit on a much wider group of drilling sites. Analysts say a new deal expected from OPEC and other producers could speed up a rebalancing of the market, but the wave of new U.S. shale wells would also unleash enough new oil to cap OPEC's price gains.
Energy ministers from Russia and Saudi Arabia this week said they would recommend that other producers agree to an extended nine-month deal to hold down output. Oil jumped on the news, with U.S. crude edging back toward the psychological $50 per barrel level May 16. Many analysts expect to see $60 oil by the end of the year, but the gains are not expected to spike much higher.
"I think this market will rebalance itself very quickly,” said Ed Morse, Citigroup's global head of commodities research. He expects shale drilling to accelerate and U.S. shale alone could meet any growth in global demand. IHS Markit expects U.S. shale to grow by 900,000 barrels a day this year, and by the end of this year or early next the U.S. will be producing record amounts of oil. "You can certainly say a lot of shale today will be competitive between $40 and $50 a barrel," said Daniel Yergin, vice chairman of IHS.
Canadian legislation would ban oil tankers from northern B.C. coast
(Globe and Mail; Canada; May 12) - The Canadian government May 12 introduced legislation that would bar most oil tankers from operating along the coast of northern B.C., fulfilling an election pledge by Prime Minister Justin Trudeau and formalizing a moratorium Ottawa announced last year. Supporters welcomed the bill’s introduction, including an alliance of First Nations that lobbied against Northern Gateway, a proposed oil pipeline to the coast that the federal government rejected last year.
“This law puts an end to any future oil pipeline and tanker project in our territories,” the alliance’s board chair, Patrick Kelly, said in a statement. “Our coast is no place for oil pipelines and tankers. They are a threat to our culture, environment and economy.” Others disagreed, saying Canada already has legislation that protects the environment, and that a tanker ban could hinder economic development in the region.
“We had really hoped the government would embark on a more comprehensive planning process and actually look at what risks they were trying to address,” said Robert Lewis-Manning, president of the Vancouver-based Chamber of Shipping. Tankers carrying less than 12,500 metric tonnes of oil would be exempt from the law, so that northern communities can continue to receive fuel deliveries. The legislation would prohibit tankers carrying crude from stopping, loading or unloading in northern B.C. in a zone that stretches from the U.S. border to the northern tip of Vancouver Island.
Opponents will continue pushing banks to stop financing pipelines
(The Associated Press; May 14) - Opposition to the Dakota Access oil pipeline has persuaded some banks to stop supporting projects that might harm the environment or tread on indigenous rights, but calling the divest movement a success might be a stretch. It doesn't appear to be hurting the ability of energy companies to get financing and it doesn't seem to concern lenders broadly.
Yet pipeline opponents see victory in the fact that they have made financial institutions more aware of indigenous rights — and they're intent on keeping up the fight. "We aren't ignoring the fact we couldn't stop that pipeline," said Vanessa Green, a campaign director with the DivestInvest initiative. "There's a battle, and then there's a war." The $3.8 billion pipeline from North Dakota to Illinois will be fully operational by June 1, a half-year later than planned by Texas-based developer Energy Transfer Partners.
The project was delayed by lawsuits from American Indian tribes who fear it threatens cultural sites and drinking water, and months of protests by tribal members and others. Opponents also picketed banks in major U.S. cities and urged banks in Europe and even Japan to take a stand against the pipeline. Opponents also targeted cities, including in Seattle, where leaders in February voted to cut ties with Wells Fargo in part due to its role in funding Dakota Access.