Larry Persily

Arctic LNG-2 extends Russia’s reach in Asia

Russian-led ventures earlier this month announced plans for two more liquefied natural gas terminals that would double the country’s production capacity by the mid-2020s. One is in the Arctic and the other in Russia’s Far East, and both are counting on Asian buyers to take much of the LNG. Arctic LNG-2 will aim to send 80 percent of its output to Asia, Leonid Mikhelson, CEO of project leader Novatek and Russia’s richest businessman according to Forbes magazine, said after the development partners signed a final investment decision Sept. 5. And it’s not just China, which is on its way toward becoming the world’s biggest LNG consumer and is a 20 percent partner in Arctic LNG-2. Japan is a partner in the venture, too, one of the largest in the history of Japanese-Russian relations, said Japan’s Industry Minister Hiroshige Seko. “It will unite Japan and Russia even more, as well as Europe and Asia. The Japanese government will provide all necessary assistance for the realization of this project,” the minister said as company officials announced the final investment decision at the Eastern Economic Forum in Russia’s Pacific port of Vladivostok on Sept. 5. On the same day at the forum, Novatek, which holds a 60 percent stake in the $21 billion Arctic LNG-2 project, announced a joint venture with marine shipping company Sovcomflot to purchase, finance and operate a fleet of 17 new ice-class LNG carriers for year-round transit through the Northern Sea Route to buyers in Europe and Asia. The vessels will be built at the new Zvezda shipyard, developed with Russian oil and gas producer Rosneft and with assistance from South Korea’s world-leading LNG carrier shipbuilders. The $4 billion shipyard is near Vladivostok, in the Russian Far East. Novatek, which developed Russia’s first LNG project in Siberia, Yamal LNG, will benefit from extremely low-cost gas at Arctic LNG-2, helping it compete against gas from the U.S. and Canada, Wood Mackenzie analyst Nicholas Browne told Reuters. Arctic LNG-2, at 19.8 million tonnes annual capacity, is scheduled to start production in 2023, reaching full capacity by 2026. Yamal is at 16.5 million tonnes annual capacity. Global LNG production capacity this spring totaled almost 400 million tonnes per year. “Novatek is clearly driving home their ambitions to be a global LNG powerhouse,” Chong Zhi Xin, associate director of gas, power and energy at analysts IHS Markit, said to Reuters on Sept. 5. Novatek’s partners in Arctic LNG-2 are France’s Total, China’s National Petroleum Corp. and China National Offshore Oil Corp., and the Japan Arctic LNG consortium comprised of Mitsui and state-owned JOGMEC, formally known as Japan Oil, Gas and Metals National Corp. “This is an important project for Russia and follows our strategy to create capacities for LNG production,” Russian Energy Minister Alexander Novak said at the forum in Vladivostok. It’s the largest LNG development to reach an investment decision this year, said global energy consultancy Wood Mackenzie, bringing to 63 million tonnes total project commitments in the first eight months of this year as suppliers look to meet growing demand. Meanwhile, Gazprom, which operated Russia’s only LNG export terminal until Yamal started up two years ago, is looking to expand its operation in the Far East and also build a new liquefaction plant and marine terminal on the Baltic Sea. If all of the projects move ahead, Russia would push its way on the top-four leaderboard of global LNG production capacity with Qatar, Australia and the United States, a fast climb from its No. 10 spot just a decade ago. The Baltic project, which would include an LNG plant and petrochemical operation, has been estimated at almost $14 billion, with 10 million tonnes annual LNG production capacity. Prime Minister Dmitry Medvedev said last month it would be impossible to build without government support, and soon after Russia’s state development bank VEB said it would invest up to 111 billion roubles ($1.68 billion) in the project. Reuters reported this summer that Russia’s National Wealth Fund also will help finance the Baltic investment. The government is helping with Arctic LNG-2, too. Novatek will get a reported $600 million in additional tax deductions for building the port, along with the Russian government covering more than half the construction budget at the port and channel, according to reports in Norway’s Barents Observer newspaper. Novatek also will receive about $160 million in property and income tax breaks from the regional government for its investment in a $1.6 billion construction yard near Murmansk, about 1,000 miles west from the project site, where it will build 1,000-foot-long concrete and steel platforms that will be towed and installed at Arctic LNG-2, the newspaper reported. In the Russian Far East, shareholders in the Sakhalin-1 oil and gas project have decided to build their own liquefied natural gas plant and export terminal at the mainland port of De Kastri, about 150 miles from the offshore oil and gas fields. Sakhalin-1 has been producing oil for almost a decade, with production of about 200,000 barrels a day in 2017, while the partners have considered options for selling the gas. The four partners in Sakhalin-1 are Rosneft, ExxonMobil, Japan’s SODECO and India’s ONGC Videsh. The partners had been talking with Gazprom about selling or sending their gas through the Sakhalin-2 liquefaction plant, but Rosneft CEO Igor Sechin announced on Sept. 5 that the Sakhalin-1 partners would build their own LNG plant, according to press reports Gazprom, Russia’s top gas producer, leads Sakhalin-2, where the partners plan to expand production capacity from the current 9.6 million tonnes of LNG per year. Gazprom has not issued any statements about the Rosneft-led effort to build a competing LNG terminal that also would draw on gas fields offshore Sakhalin Island. Sakhalin-2 went online in 2009. The company and its partners Shell and Japan’s Mitsui and Mitsubishi have been working toward an expansion for several years but are not yet at the final investment decision stage. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Excess supply, economic fears drive down oil prices

Fears of an oversupplied oil market amid rising global trade tensions are holding down prices. In addition, markets are reacting to weak economic indicators and unsettling political news, along with rising non-OPEC production, resulting in frequent daily price swings of $2 or more per barrel. Worries of too much oil chasing after uncertain demand is making investors, traders and corporate executives nervous, even prompting one bank to suggest prices could drop more than $20 a barrel if everything goes wrong. “Oil is at the edge of a cliff,” analysts at Bank of America Merrill Lynch wrote in a research note. Brent, the global price, started the week of Aug. 26 at around $59 per barrel, off more than 20 percent from its April peak of $74. U.S. crude tumbled roughly 8 percent on Aug 1, the steepest one-day drop since 2015, after President Donald Trump announced a new round of tariffs on China. “President Trump’s unexpected tariff announcement … suddenly revived the specter of an economic slowdown, akin to bubonic plague for oil demand,” Robert McNally, president of Rapidan Energy Group, told The Wall Street Journal in early August. “The U.S.-China trade spat has been at the center of the oil market demise, which has sent the global economy to the brink of recession and negatively impacted oil demand forecasts,” Stephen Innes, managing partner at VM Markets, Singapore-based trade specialists, was quoted by Reuters on Aug. 20. “Recession risk is now the single biggest factor driving oil prices because it will determine whether recent price falls will be enough to rebalance the market, or whether a deeper and longer slump is needed,” a Reuters’ columnist said Aug. 20. Putting numbers to the risk, a Bank of America Merrill Lynch global research report warned Aug. 2 that prices could sink more than $20 per barrel if China decides to buy Iranian crude in retaliation for U.S. trade tariffs. “A Chinese decision to reinitiate Iran crude purchases could send oil prices into a tailspin,” the report said, noting that the increased volume would add to an already well-supplied market. Global oil consumption is falling at the fastest rate since late 2014 as manufacturing and trade flows slip and as production of new cars and trucks declines, the Reuters’ columnist reported. Demand in the top 18 consuming countries fell by almost 0.2 percent in the three months between March and May compared with the same period a year earlier. Back in 2014-16, the combination of falling consumption with booming U.S. shale output and Saudi Arabia’s refusal to cut back on its production led to a price slump that dropped Brent from the $100-plus level in 2014 to a low of $27.88 in January 2016. This time around, Saudi production cutbacks have limited the price drop. OPEC is trying to prop up prices. Total output by its members hit an eight-year low in July with a further voluntary cut by top exporter Saudi Arabia. The 14-member Organization of the Petroleum Exporting Countries pumped 29.42 million barrels per day in July, according to a Reuters survey, the lowest OPEC total since 2011. But despite the cutbacks by OPEC and its allies, “bulging global oil stocks have failed to decline and the market remains well supplied,” said Stephen Brennock, with PVM Oil Futures, which bills itself as the world’s leading broker of oil trade and investment instruments. OPEC, Russia and other non-members agreed in July to continue their voluntary cutback in production, extending the deal adopted in December. The producing nations agreed to trim their output by more than 1 million barrels a day, about 1 percent of worldwide production. Even with that, OPEC has indicated the market will be in slight surplus in 2020. “The risk to global economic growth remains skewed to the downside,” said an OPEC report of early August. OPEC may be able to govern its own production to guard against global oversupply and low prices, but U.S. producers continue driving much of the surge in output, along with new projects in Brazil and Norway. Citigroup and JPMorgan Chase analysts project global supply will grow roughly 1 million barrels per day more than demand in 2020. The analysts said those new barrels could exacerbate the expected global surplus, particularly as concern about a slowing world economy triggers fears about crumbling demand. U.S. production totaled 12.3 million barrels per day in June, setting a new record. The nation’s output was just 5 million barrels per day in 2008. The U.S. Energy Information Administration forecasts 13.3 million barrels per day in 2020. Much of the booming production is coming from Texas, in particular the Permian Basin. Oil production in Texas has shot up from about 1 million barrels per day a decade ago to 5 million this summer. All that oil needs buyers, and much of it is leaving the country — but not as much as earlier in the summer. U.S. exports averaged 2.4 million barrels per day during the three-week period ended Aug. 9, down from an average 3 million barrels between the start of May and mid-July, Energy Information Administration figures show. It was easier to sell U.S. crude overseas when it was priced about $8 to $10 per barrel less than Brent, as it was over the winter and much of the spring. But U.S. oil is now trading at the smallest discount to global prices in more than a year. New pipelines are transporting oil from the Permian to the Gulf of Mexico, easing the bottleneck that constrained markets and held down prices. With improved access to overseas buyers, West Texas Intermediate crude was trading at just $3.50 less than Brent the third week of August. Higher prices reduce the attractiveness of U.S. crude exports. “Nobody really wants the barrels when they’re $3 cheaper than Brent,” Bob Yawger, director of the futures division at Mizuho Securities USA, was quoted by The Wall Street Journal on Aug. 20. “It could get ugly long term.” Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Spot-market LNG prices have buyers seeking more options

It’s just shy of six years ago when spot-market prices for liquefied natural gas in Asia hit a record $20 per million British thermal units and a cargo aboard a standard-size LNG carrier cost almost $65 million. That same volume of LNG would cost less than $13 million today, or around $4 per million Btu. Spot-market buyers paid more than long-term customers during the post-Fukushima, tight-supply price spikes of 2012-14, but the roles are reversed during today’s weak market conditions. It’s a matter of supply and demand driving spot prices, while long-term LNG contracts are linked to oil prices that are detached from LNG market conditions. In July, Japanese utilities paid an average $4.70 per million Btu for spot LNG cargoes amid an oversupplied market, according to trade ministry data, about half the price those same utilities paid for gas under long-term contracts linked to oil prices. Tokyo Gas and electric utilities in Hokkaido, Tohoku, Kyushu and Hokuriku regions have all said they are looking at ways to take advantage of cheaper spot LNG, Reuters reported Aug. 9. But they are limited in the number of cargoes they can take because most of their supply comes under long-term take-or-pay contracts. Oil-linked LNG contracts around the world vary, ranging from about 11 to 15 percent of the price of a barrel of crude averaged over the past six months to five years. When oil was $120 several years ago, contract buyers paid dearly for their LNG. But nothing linked to oil can compete with $4 spot-market gas. The low prices are pushing utilities in Japan to get more aggressive in the price reviews allowed under their long-term contracts, according to multiple news reports. The five- or 10-year reviews are built into many of the contracts. “Price-review negotiations are becoming more intense,” Thanasis Kofinakos, head of Wood Mackenzie’s Asia-Pacific gas and LNG consulting, told Reuters in early August. According to Reuters, Japan’s second-biggest city-gas company, Osaka Gas, is in arbitration with ExxonMobil’s LNG project in Papua New Guinea after failing to win a reduction in prices during a price review. However, there is a risk in negotiating for a new pricing structure in long-term contracts — what happens the next time the market flips and oil-linked LNG is cheaper than spot sales? Utilities would need to accept the risk that spot prices could surge in tight markets, Hirofumi Sato, Tokyo Gas general manager of financial management, said during an earnings news conference. Besides, it’s not easy for the utilities to gamble on market pricing swings, as they have long favored stability of supply over price. Still, Tokyo Gas is looking for ways to take advantage of cheaper spot prices, including buying up more gas and storing it for the peak winter season, Sato said. Another tactic is to scale back purchases within the limit of what’s allowed under their contracts. Some buyers in Japan and China are seeking to delay shipments or reduce volumes under their contracts from the Ichthys LNG project in Australia, an Inpex executive told Reuters Aug. 8. Inpex is the Japanese oil and gas producer that operates Ichthys. If the money-saving spot prices persist, India’s top gas importer Petronet LNG will look to renegotiate more of its oil-linked supply deals, its managing director said Aug. 8. “You don’t have much of a choice,” Prabhat Singh told Reuters. Petronet is paying $8.25 to $9.50 per million Btu under its long-term contracts with Qatar’s RasGas and for cargoes from ExxonMobil’s share of the Gorgon project in Australia, Singh said. The company renegotiated new price deals in other contracts in 2015 and 2017. No doubt Petronet is aware that Indian Oil Corp. bought a spot cargo for delivery in the second half of August from commodity trader Trafigura at $3.69 per million Btu. China National Offshore Oil Corp. bought a cargo for delivery in early September from trader Vitol at $3.90. As new LNG supply comes into the global market amid weaker demand growth, the volume of spot cargoes is growing, adding to the soft prices. Spot- and short-term trades comprised one-third of the market in 2018, the International Group of LNG Importers said in its 2019 annual report. It was 1.5 percent in 1997 and 8.9 percent in 2003. There is so much low-cost LNG available that traders are starting to look at booking vessels to store LNG at sea as they bet on winter demand to boost prices, according to multiple news reports. If October and November spot prices are 90 cents higher than August prices, “floating storage is starting to make sense … and at $1.50 people will be jumping on it,” a Singapore-based LNG trader told Reuters. Another factor is the steady return of Japan’s nuclear-power fleet over the next three years. Nine nuclear plants are back online, with 14 more expected in the next few years, leading a shift in demand away from imported LNG. S&P Global Platts estimates the issue of over-contracting for LNG will emerge this year among Japanese utilities. The situation could peak in 2020, with the over-contracted volumes reaching 19.5 million tonnes. Europe is buying more LNG, but has its limits. There is increasing concern Europe’s gas storage could hit “tank tops” by the end of summer, putting more downside pressure on prices, Reuters reports. Storage sites at some key hubs in the Netherlands and Austria are already more than 95 percent full, Refinitiv data shows. U.K. and Dutch gas prices, benchmarks for European gas sales, have lost half their value since last September. They hit 10-year lows in June, knocked down by an influx of LNG imports and pipeline gas from Russia. Continued oversupply, coupled with new liquefaction capacity coming online in the U.S., Australia, Russia and Mozambique, could cause developers to rethink their schedules. “We may see some delays in final investment decisions in new LNG projects given the current market environment,” Inpex Senior Managing Executive Officer Masahiro Murayama said in an earnings call. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

FERC sets eight public meetings in September on AK LNG draft EIS

The Federal Energy Regulatory Commission has scheduled eight meetings around the state in September to hear public comments on the draft environmental impact statement for the proposed Alaska LNG project. “The primary goal of the public comment meetings is to have you identify specific environmental issues and concerns with the draft environmental impact statement,” FERC said in its July 26 announcement. “All verbal comments will be recorded by a court reporter and become part of the public record.” FERC released the draft environmental review on June 28. Public comments are due by Oct. 3. Allowing time for state and federal agency review, along with revisions to the draft, the commission’s schedule calls for release of the final EIS in March 2020 and a commission vote on the project application in June 2020. The state, which has been by itself directing the estimated $43 billion project for almost three years, plans to finish the work with FERC and then put the effort on hold until it sees a way forward with private companies in the lead. The public comment meetings will run Sept. 9-12, with sessions in two different communities each day. All meetings are scheduled for 5 to 8 p.m. Monday, Sept. 9 Inupiat Heritage Center, Utqiagvik Trapper Creek Elementary School, Trapper Creek Tuesday, Sept. 10 Kisik Community Center, Nuiqsut Houston Fire Station, Houston Wednesday, Sept. 11 Tri-Valley Community Center, Healy Nikiski Recreation Center, Nikiski Thursday, Sept. 12 Morris Thompson Cultural and Visitors Center, Fairbanks Dena’ina Center, Anchorage FERC will lead the meetings, not the project applicant Alaska Gasline Development Corp. “Other federal agency representatives may also be in attendance and available to answer questions,” FERC said. In addition to the eight FERC meetings, the federal Bureau of Land Management will hold two public sessions on subsistence issues. Those meetings are scheduled for “potentially affected communities.” BLM will be looking at the effects of construction and operation and how they fit under the Alaska National Interest Lands Conservation Act. Those meetings are scheduled for 6 to 9 p.m. at: Anaktuvuk Pass Community Center, Tuesday, Sept. 17. Kaktovik Community Center, Thursday, Sept. 19. Comments on the draft EIS can be filed electronically through the eComment feature on the ferc.gov website. “This is an easy method for submitting brief, text-only comments,” FERC stated. Longer comments, or submissions with attachments, can be submitted through the eFiling feature on the website. Or people can mail comments to: Kimberly D. Bose, Secretary; Federal Energy Regulatory Commission; 888 First Ave. NE, Room 1A; Washington, DC 20426. All comments should include the project’s docket number: CP17-178-000. FERC staff is available to help with filing comments online: Call 1-866-208-3676 or email [email protected] The 3,800-page draft EIS determined that the project would damage areas of permafrost and wetlands and could affect migrating caribou and six endangered or threatened wildlife species — referred to as “adverse impacts” — but many of the effects could be reduced or eliminated if the right steps are taken during construction and operation to avoid, minimize or repair the damage. FERC is the lead on the environmental review of the state-sponsored project to pipe North Slope gas 807 miles to a natural gas liquefaction plant and marine terminal in Nikiski, on the Kenai Peninsula. The draft EIS was prepared with the assistance of nine other federal regulatory agencies, including the U.S. Fish and Wildlife Service, National Park Service, Environmental Protection Agency, National Marine Fisheries Service, Army Corps of Engineers and Bureau of Land Management. The state has been leading the project since North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips decided in late 2016 to stop writing big checks for regulatory and engineering work. Now the state, through AGDC, has decided it, too, needs to slow down spending. The state corporation plans to finish the FERC process and try putting together a project without the state in the lead. AGDC earlier this month announced it would lay off more than half its staff, shutting down its effort to find customers and investors. “We’re going to have just enough people to get this thing done (FERC) and at the end of next (fiscal) year in June, then we take a look and say, ‘Where do we go from here?’” AGDC interim president Joe Dubler told the state House Resources Committee on July 19. At that point, AGDC will re-examine the state’s future participation in the project, Dubler said, according to a July 24 report in the Alaska Journal of Commerce. Dubler also told legislators that AGDC did not renew the nonbinding joint-development agreement it had with three large, nationalized Chinese firms to buy up to 75 percent of the project’s LNG output in exchange for an equal share of financing. The project envisioned in the agreement “frankly doesn’t exist anymore,” Dubler said, explaining the Gov. Mike Dunleavy administration is not comfortable with the risk the state would assume as project leader, the Journal of Commerce reported. The agreement was signed in front of President Donald Trump and China President Xi Jinping in November 2017, promoted as a signature achievement in former Gov. Bill Walker’s effort to secure partners for a state-led Alaska LNG project.

LNG trucking expands as option in absence of pipelines

Though the liquefied natural gas industry is mostly focused on projects that produce millions of tonnes per year and LNG ships that transport almost 70,000 tonnes per load, a growing volume of the gas is moving in 20-tonne deliveries. Trucks are hauling 40-foot-long insulated LNG tanks around the U.S., Canada, Mexico and especially China. The “pipeline on wheels,” as they are called, have been delivering LNG to Hawaii to displace costly synthetic gas made from naphtha. The pilot project started in 2014 and has been expanded. FortisBC, which recently completed a $400 million expansion of its small 1971 gas liquefaction plant across the Fraser River from Vancouver, said July 16 it had signed a two-year contract to ship 53,000 tonnes per year to China — delivering almost 60 of the specialized shipping units per week. Pricing was not disclosed. The 40-foot tanks can each carry about 12,000 gallons of LNG, which, when regasified, is about 1 million cubic feet of gas. The LNG will go to smaller commercial and industrial customers in China that are not connected to a gas pipeline, potentially displacing coal or fuel oil, Doug Stout, vice president of market development at FortisBC, told Bloomberg. The company has been selling smaller shipments of LNG to China on a spot basis since 2017. The expansion at the Tilbury liquefaction plant and marine terminal took the facility’s capacity from 35,000 to 250,000 tonnes per year. The July contract is with Chinese LNG distributor Top Speed Energy. Such shipments are a growing component in the global LNG sector, especially when the customers are small or unconnected to a pipeline grid, Alex Munton, an analyst for Wood Mackenzie, was quoted by Bloomberg on July 17. China’s ENN Group last year opened a new LNG import terminal in Zhoushan, at the mouth of the Yangtze River. It’s the first in the world built to load the majority of its LNG into trucks instead of reheating it to a gas for pipeline distribution, according to a late-2018 Bloomberg report. The facility is designed to take in up to 3 million tonnes of LNG per year, with 2 million destined for loading into tanker trucks. The operation includes 14 loading bays, and the privately owned distributor started with a fleet of 400 trucks to serve the market during the 2018-19 winter. The trucked LNG market is unregulated in China, allowing nimble sellers to benefit from rising prices during peak demand, while pipeline gas prices remain set by the government. “We haven’t seen this kind of volume in trucked LNG anywhere else in the world,” Xizhou Zhou, head of China energy research for IHS Markit, said last year. Trucks delivered about 19 million tonnes in China in 2017, about 12 percent of the country’s total LNG consumption, according to Wood Mackenzie estimates. In North America, two companies have carved out a niche by using tanker trucks to deliver the fuel to industrial and agricultural customers in Mexico. Houston’s Stabilis Energy is tapping into a growing market in Mexico, supplying LNG to industrial customers and greenhouses, the Houston Chronicle reported this spring. Its $55 million plant in the South Texas town of George West can produce 120,000 gallons of LNG a day. The plant also supplies fuel to portable LNG-powered generators at remote drilling and fracking sites in Texas, and at fracking sand mining sites out of reach of pipelines and power grids. Mexican gas company Enestas serves customers outside of local power grids and miles away from pipelines. Gold, silver and lithium mines in Mexico use the company’s gas-fired generators to power equipment and provide heat in deep mine shafts, the Chronicle reported. Industrial-sized greenhouses designed for growing peppers, cucumbers and other vegetables in the mountains of Central Mexico burn gas to keep crops warm at night. Enestas expects to sell 10 million gallons of U.S. LNG to its customers in Mexico in 2019 — equal to more than 800 million cubic feet of gas. Up the U.S. East Coast, New Fortress Energy has proposed building an LNG export terminal in New Jersey, filling the storage tanks with gas liquefied at a plant in Pennsylvania and trucked to the dockside facility. The U.S. Army Corps of Engineers, the lead permitting agency for the project, released company plans in mid-July that said the terminal, just across the Delaware River from the Philadelphia International Airport, would receive as many as 15 trucks an hour — around the clock — to fill an oceangoing tanker every two weeks. The gas, produced from Pennsylvania’s Marcellus Shale, would be liquefied at a plant about 200 miles away in Bradford County, also proposed by New Fortress Energy. Rail might be another option to move the LNG to the waterfront terminal. Communities along Canada’s north shore of Lake Superior could start burning gas by late 2020, as the Ontario government this spring decided to provide $27 million (Canadian) toward building an LNG plant in Nipigon for distributing gas to communities struggling with high energy costs. The provincial funds will cover about half the cost of the plant. Residents in Marathon, Terrace Bay, Schreiber, Manitouwadge and Wawa — total population, about 11,000 — suffer under price spikes on fuel oil, propane and electrical power. An earlier feasibility study estimated trucking LNG into the towns would save municipalities, homeowners and business more than $6 million annually. Northeast Midstream, an Ontario energy developer, will take gas from a nearby pipeline and liquefy it. Trucks will deliver the LNG to depots in each community, where it will be warmed back to a gas and distributed by short pipelines into individual homes, public and commercial buildings. Press reports said longer pipelines were not a good option in the area’s rugged topography. The promise of lower home heating costs are the main selling points for Terrace Bay Mayor Jody Davis. “In the wintertime, over the past several years, heating bills in some of our homes have been up to $1,000 per month” for diesel, fuel oil or propane. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Pipeline obstacles constrain capacity amid energy boom

Oil and gas pipeline developers around the country are frustrated at the delays and legal challenges they have to plow through when they would prefer to be burrowing underground to install new pipe. Tulsa, Okla.-based Williams Cos. has been trying for more than four years to obtain permission to replace about six miles of an older 8-inch-diameter gas line it owns in Seattle’s northern suburbs with a 20-inch line to serve new development in the area. Alan Armstrong, Williams’ CEO, told The Wall Street Journal this month that permitting delays have driven the project cost to $50 million from an estimated $6 million. The company hopes to start work this summer. “That is such a simple piece of work,” Armstrong told the Journal. “It’s hard for me to even talk about it because it’s repulsive how much money has been spent there.” The North Seattle Lateral, as it’s called, just north of Bothell and Woodinville, was built in 1956 and delivers gas from Canadian and Rocky Mountain producers. “(It) is operating beyond its intended peak capacity on cold winter mornings and days,” the company says on its website. Challengers during the permitting process include the Sierra Club and Mothers Out Front. Environmental groups have pushed regulators for greater scrutiny of the project, which would cross 15 streams. Challengers also have raised concerns of a leak or explosion in the suburban and rural area of Snohomish County. In Michigan, Enbridge has taken the state to court over a $500 million pipeline project. The company wants to dig a tunnel for new liquids pipelines to replace a 66-year-old line on the lakebed under the Straits of Mackinac, which connects Lake Michigan and Lake Huron. The legal fight escalated between the Calgary-based company and the State of Michigan after Gov. Gretchen Whitmer won election last fall. She wants the line shut down. The company wants to the state to honor an agreement with the previous governor that would allow Enbridge to install new pipe in the protective tunnel. The company’s Line 5, as it’s called, can move 540,000 barrels per day of crude oil and natural gas liquids from Canada to Michigan and Ontario refineries and other customers. Enbridge is asking the Michigan Court of Claims “to establish the constitutional validity and enforceability of previous agreements.” The governor wants the pipe out of the water to protect the Great Lakes from the risk of spills. In Canada, the most recent legal fight is not a company versus government but two governments battling each other. British Columbia wants to restrict the flow of oil sands production from Alberta through the coastal province. The intent is to block expansion of the Trans Mountain pipeline to move 890,000 barrels per day of oil sands bitumen to an export terminal near Vancouver. The B.C. Court of Appeals ruled May 24 that the federal government has sole jurisdiction over interprovincial projects such as an oil line, shutting down British Columbia’s maneuver. The B.C. government appealed and Alberta responded by joining the case as an intervenor to protect its interests. “The B.C. Court of Appeals’ unanimous decision was clear. B.C. does not have constitutional authority to block cross-provincial projects,” Alberta Premier Jason Kenney said July 12. “The actions of the British Columbia government not only target Alberta’s economy by landlocking our energy resources,” but also undermine free trade within Canada, Kenney said. The project that started the debate over oil sands pipelines 10 years ago — the Keystone XL line — continues to have its multiple days in court. Opponents asked a federal judge on July 1 to cancel permits and other approvals issued by the U.S. Army Corps of Engineers for the line from Canada, opening another legal fight over the long-delayed project. Attorneys for the Northern Plains Resource Council, Sierra Club and other groups filed the lawsuit in Montana. They claim the Army Corps did not examine the potential for oil spills and other environmental damages when it approved plans from pipeline developer TC Energy (formerly known as TransCanada). The 1,184-mile pipeline from Canada would connect to existing pipe in Nebraska to deliver oil to U.S. Gulf Coast refineries and export terminals. First proposed in 2008, Keystone XL was rejected by President Barack Obama but revived under President Donald Trump. Besides the filing in Montana, legal challenges continue in Nebraska. Though oil lines may attract the most media attention, insufficient U.S. gas pipeline capacity creates a lot more price volatility for consumers. Earlier this year, two utilities that serve the New York City area stopped accepting new customers in two boroughs and several suburbs, citing a lack of gas pipeline capacity. They said they couldn’t guarantee delivery to additional furnaces, The Wall Street Journal reported July 7, never mind that the country’s most prolific gas field, the Marcellus Shale, is only a three-hour drive away. Environmental and political opposition is making it difficult to build new pipelines in New England and the Mid-Atlantic states. At the other end of pipelines, producers in the Permian Basin in West Texas and Bakken in North Dakota have so much gas with no way to get it to market that they are burning it — a combined 1.2 billion cubic feet per day at its worst earlier this year. There just aren’t pipelines to move all the gas. U.S. production rose to a record of more than 37 trillion cubic feet last year, up 44 percent from a decade earlier. Prices have been negative at times this year at a trading hub near Midland, Texas, where producers had to pay companies to take gas off their hands. At the other end of the distribution system, prices hit records when heavy demand coincided with supply disruptions. A cold snap along the East Coast led to gas prices as high as $140.85 per million Btu in New York and $128.39 in the Mid-Atlantic on Jan. 4. “I don’t recall a situation when we’ve had the highs and lows happen in such extremes,” the Journal on July 7 quoted Rusty Braziel, a former gas trader who now advises energy producers, industrial gas buyers and pipeline investors. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Trudeau signs off on Alberta pipeline expansion

Alberta’s oil sands producers have done a good job of overcoming technical challenges to boost output of the gooey stuff. It’s moving all that oil to market that’s become the problem. It took almost 40 years to get from the first barrel in 1967 to 1.3 million barrels per day in 2008. It then took less than 10 years to more than double that to 2.8 million barrels per day in 2017. Even better, global energy analysts at IHS Markit forecast production could climb to as high as 4 million barrels per day in another decade. All that oil means Western Canada needs more pipeline capacity. The industry received some good news when the government of Prime Minister Justin Trudeau on June 18 ruled that expansion of the Trans Mountain pipeline could proceed. The expansion will almost triple the line’s carrying capacity to 890,000 barrels per day from the oil sands pipeline hub of Edmonton to an export terminal in Burnaby, British Columbia. Construction could begin as early as this year. The Cabinet move came almost 10 months after a federal court tossed out an earlier approval of the $7.4 billion (Canadian) project, finding that the government’s decision was based on flawed consultation with Indigenous communities and inadequate consideration of the effects of increased oil tanker traffic in coastal waters. The divisive project pits Alberta and its supporters, which talk of the economic gains, against British Columbia and other opponents, which worry about spills, other environmental risks and climate change. Federal approval is about balancing those interests, Trudeau said. “To those who want sustainable energy and a cleaner environment, know that I want that, too,” he said. “But in order to bridge the gap between where we are and where we’re going, we need money to pay for it.” The Cabinet decision is expected to be a key issue in Canada’s federal election in October. This isn’t about a private company building an oil line. The federal government is now the pipeline’s owner, having bought the existing line and expansion project for C$4.5 billion from Kinder Morgan last summer when the company threatened to walk away from the venture over constant regulatory and legal delays. Kinder Morgan first proposed the expansion more than seven years ago. Without enough pipeline capacity to get their product to market, oil sands producers have endured painfully lower prices. Benchmark Western Canadian Select was selling for $13 less per barrel than U.S. benchmark West Texas Intermediate and almost $20 less than the global Brent price on June 28 — though that is far better than the $40 discount to West Texas crude late last fall. Moving more oil to the B.C. coast would give producers access to higher-priced export markets. But even with the cabinet decision to proceed with the Trans Mountain expansion, opponents are not ready to quit. Several coastal First Nations said June 18 they plan to appeal the government’s action, and Vancouver Mayor Kennedy Stewart said the city would do “everything in our power” to support local First Nations in their court battles. Analysts are betting on first oil through the expanded line in 2021 or 2022, depending on legal challenges. “I am not ready to do a victory celebration, especially on the back of a reapproval of a project that should have been built by now,” said Rob Broen, CEO of Athabasca Oil, which has contracted to move oil on the pipeline, as quoted by a Calgary Herald columnist. Many First Nations, however, support the project, and some are interested in taking an equity stake in the venture. The government plans to sell the line back into the private sector, though it’s not clear if the sale would come before or after the expansion is complete. The government plans to start a series of meetings with interested First Nations starting July 22 in Vancouver, with stops in Victoria and Kamloops, British Columbia, and Edmonton, Alberta. The Trudeau government is prepared to discuss equity ownership, revenue sharing and royalty agreements with 129 First Nations, according to Canada’s Department of Finance. There is strong interest from First Nations. The Calgary Herald reports that the Indian Resource Council, representing more than 130 First Nations that own oil and gas resources on their territories, already has consulted with the federal government and held preliminary meetings with First Nations about making a bid for the Trans Mountain pipeline. There even is competition for the right to buy an equity stake in the Trans Mountain system, according to a Canadian Press report in June. An Alberta coalition, calling themselves the Iron Group, said it has invited 47 First Nations and about 60 Métis organizations in the province to sign up for an investment try. And there is a group called Project Reconciliation, a consortium inviting Indigenous participation from British Columbia, Alberta and Saskatchewan in a bid for a controlling stake in the pipeline. Meanwhile, supporters of the project saw some visible progress in June when a train carrying stacks of steel pipe rolled through Calgary. Pipe segments have been arriving at work sites for weeks, where nearly a third of all the pipe needed for the project is now staged, according to the Calgary Herald. But stacking up pipeline sections doesn’t mean construction is imminent; just ask the backers of the Keystone XL project, which would move Western Canadian oil more than 1,600 miles to a connection point in Nebraska for delivery to U.S. Gulf Coast refineries and export terminals. The project developer, TransCanada, proposed the line in 2008. Under pressure from opponents, the U.S. government denied an essential permit in 2012. The government’s attitude changed with the election of President Donald Trump in 2016, but legal challenges in federal and state courts have continued. The U.S. Court of Appeals for the 9th Circuit on June 6 overturned a lower court injunction that prevented Calgary-based TC Energy — formerly TransCanada — from beginning construction, but the decision came too late for this year. “There will be no mainline construction in 2019 in the U.S.,” TC Energy spokesperson Matthew John said. Besides, the company is still waiting on a Nebraska Supreme Court ruling on whether its permits to build the pipeline through the state are valid. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Draft EIS outlines potential impacts from gasline project

The proposed Alaska LNG Project would damage some areas of permafrost and wetlands and could affect migrating caribou and six endangered or threatened wildlife species — referred to as “adverse impacts” — according to the federal draft environmental impact statement, or EIS, released June 28. “The project would result in substantial impacts on permafrost, wetlands, forest, and caribou (Central Arctic herds). Because the other current or reasonably foreseeable projects in the study area would similarly affect these resources, we found that cumulative impacts on these resources would or could be significant,” the report said. However, many of the effects could be reduced or eliminated if the right steps are taken during construction and operation to avoid, minimize or repair the damage, the draft said. “With the implementation of various best management practices and our recommendations, most impacts on wildlife would be less than significant, but adverse impacts on some species, including caribou (Central Arctic herds) and federally listed threatened and endangered species, would occur,” the draft EIS said. Not unexpected for a project of this size, the draft lists pluses and minuses in the same sentence: “The project would result in positive impacts on the state and local economies, but adverse impacts on housing, population, and public services could occur in some areas.” The Federal Energy Regulatory Commission is the lead on the environmental review of the state-sponsored $43 billion project to pipe Alaska North Slope gas 807 miles to a natural gas liquefaction plant and marine terminal in Nikiski, on the Kenai Peninsula. The review started when the Alaska Gasline Development Corp. applied in April 2017 for federal approval. The draft EIS was prepared with the assistance of nine other federal regulatory agencies, including the U.S. Fish and Wildlife Service, National Park Service, Environmental Protection Agency, National Marine Fisheries Service, Army Corps of Engineers and Bureau of Land Management. Report totals thousands of pages The draft review totals almost 3,800 pages, with 28 appendices of more detailed analysis, maps and charts adding thousands more pages to the three-volume package. The table of contents with its accompanying lists of tables, figures, appendices and acronyms is 40 pages on its own. Public comments to FERC are due by Oct. 3. The agency will hold a series of public meetings in Alaska; the dates were not announced with the release of the draft EIS. Allowing time for state and federal agency review, along with revisions to the draft, the commission’s schedule calls for release of the final EIS in March 2020. Under that timeline, FERC would be ready to vote on AGDC’s application in June 2020. Commission approval is required to build and operate a natural gas liquefaction plant. Even with FERC approval, the project would still face the economic-viability test of lining up a gas supply, LNG customers, investors and financing before the venture could reach an investment decision and start the estimated five-year construction timeline. Much of the report covers wildlife habitat. “Project construction and operation is likely to adversely affect six federally listed species (spectacled eider, polar bear, bearded seal, Cook Inlet Beluga whale, humpback whale, and ringed seal) and designated critical habitat for two species (polar bear and Cook Inlet beluga whale).” FERC requested that the project sponsor “initiate formal consultation with the U.S. Fish and Wildlife Service and National Marine Fisheries Service regarding project effects on federally listed species.” EIS rejects Port MacKenzie alternative In addition to reviewing effects on wildlife and their habitat, communities and their economies, the report considered alternatives to several parts of the Alaska LNG project. Federal law requires that an impact statement review economically feasible alternatives to determine the “least environmentally damaging practicable alternative,” including the developer’s preferred option. “We generally consider an alternative to be preferable to a proposed action if the alternative meets the stated purpose of the project, is technically and economically feasible, and offers a significant environmental advantage over a proposed action,” the FERC report explained. The alternatives reviewed that attracted the most attention in Alaska has been the Matanuska-Susitna Borough’s strong advocacy for its Port MacKenzie property across Knik Arm from Anchorage as a better location than Nikiski for the liquefaction plant and marine terminal. The draft EIS determined Nikiski is the better choice. “Although the Port MacKenzie alternative would be technically feasible, it would not allow the project to meet all its objectives,” the report said. “Moreover, its environmental advantages are not sufficiently great to offset operational environmental impacts stemming from the increased vessel traffic in Upper Cook Inlet. Therefore, we conclude that it would not provide a significant environmental advantage over the proposed Nikiski site.” Risks to Cook Inlet Beluga whales, listed as an endangered species, would be greater with the Port MacKenzie alternative, the report said. “These impacts would persist for the life of the project, as opposed to the short-term impact” from constructing the pipeline across Cook Inlet to reach the Nikiski site. “The summer density of Cook Inlet beluga whales in Knik Arm is more than 300 times greater than the density offshore of Nikiski,” the report said. “We estimate that there would be about an 80 percent higher probability of a whale strike from LNG carriers transiting to and from Port MacKenzie during operation.” In addition, the report noted, “the Port MacKenzie marine improvements would occur within Critical Habitat Area 1 for the federally listed Cook Inlet beluga whale,” while work at the Nikiski site would occur in a less critical habitat area. In sticking with the Nikiski site, the report also cited the heavier ice conditions of Upper Cook Inlet compared to the Nikiski area. Another concern was dredging: “The need to maintain a deeper and wider channel across the Knik Arm Shoal suggests that more overall dredging would likely be required to operate at the Port MacKenzie alternative site.” The Matanuska-Susitna Borough filed last year as an intervenor in the FERC review, which gives it the legal ability to challenge decisions in the EIS. Worker camps, tourism impacts In addition to considering environmental risks, the review analyzed the project’s economic impacts. “Project construction would increase population due to worker influx, but impacts would be minor due to the use of closed construction camps,” the report said. However, jobseekers and others would be drawn to Alaska during the construction, and “these additional residents could create an added burden on local governments because they would increase the demand for local community services and facilities.” Additional tax revenues during the construction period “in most cases would offset the increase in expenditures,” the report said. But keeping much of the construction workforce in closed camps, while reducing effects on local communities and services, has a downside, the report said: “Workers living in the construction camps would have little opportunity to make purchases within the local economy; therefore, most of the non-resident worker earnings would be spent outside the state.” The tourism industry could be affected as hopefuls coming to Alaska in search of construction work “could compete with tourists for temporary accommodations, such as hotel/motel rooms, campgrounds, and house/apartment rental units.” High occupancy rates could be good for business, the report said: “However, if tourists should be prevented from visiting these areas due to a lack of accommodations, other parts of the tourism industry could be adversely affected.” The draft EIS also looked at the project’s effects on residents who depend on subsistence harvests. “Project construction and operation have the potential to affect the subsistence practices of Native Alaska communities due to reductions in resource abundance and availability, reduced access to harvest areas, and increased competition from non-local harvesters,” it said. “Impacts would result from the loss or alteration of habitat and loss or displacement of wildlife,” the report said. “The extent of impacts would vary by community, but overall, the impacts would be less than significant.” Some impacts to wildlife ‘would be significant’ The report frequently refers to the project’s impacts on wildlife habitat and the environment, with the reminder that most effects could be reduced. “We conclude that project construction and operation would result in temporary, long-term, and permanent impacts on the environment,” the report states. “Most impacts would not be significant or would be reduced to less than significant levels with the implementation of proposed or recommended avoidance, minimization and mitigation measures, but some impacts would be adverse and significant.” The report included a substantial analysis of the project’s impacts on the state’s caribou population. “Impacts on all herds, other than the Central Arctic herds, would be less than significant,” the report said. However, pipeline facilities would be constructed “at the center” of the Central Arctic herd’s range. “Three construction camps would be within this herd’s range, including one that would be in insect relief habitat. Since project facilities would be central within this herd’s range, the project could serve as a barrier to migration between habitat areas or movement within specialized habitats. Operational activities would result in a permanent disturbance to these habitats.” Although the report determined that impacts on the herd would be significant, it qualified that statement: “We do not know if the impact would be temporary or long term, or to what extent, if any,” the gas treatment plant at Prudhoe Bay or the 62.5-mile pipeline from the Point Thomson gas field to Prudhoe Bay would affect caribou herd movements. To confirm that the gas treatment plant and Point Thomson pipeline “are compatible with caribou use of the area and to address concerns expressed by local residents,” the report recommends: • Following construction, AGDC should conduct seasonal monitoring for three years to track caribou herd movement and determine if the project is creating a barrier to caribou movement. • At the end of the three years, “if it is clear based on the annual reports that the project has created a barrier to normal herd movement, AGDC should develop and file” for federal review “a plan to minimize or mitigate any identified issues with caribou movement related to the project.” Report gives recommendations, more homework Multiple recommendations are scattered throughout the report for specific steps during construction and follow-up analysis after the work is done. The EIS also assigned additional homework before the final EIS, such as requesting that AGDC submit updates of its revegetation plan to restore disturbed soils and its plan to prevent construction equipment from bringing invasive species into specific areas. There are 35 pages of recommendations at the end of the report to prevent, reduce or mitigate impacts during construction and/or operations. The recommendations cover a wide range of issues, such as: • Before the public comment period closes on the draft EIS, regulators want AGDC to submit a revised plan of directional micro-tunneling to install the pipeline beneath the Middle Fork Koyukuk, Yukon, Tanana, Chulitna and Deshka rivers, and the Parks Highway. The plan should provide additional details of “feasibility crossing studies and the potential impacts and mitigation specific to the selected crossing.” • Also before the public comment period on the draft closes, AGDC shall file a summary of the “acreages of designated critical habitat for polar bear that would be affected by project facilities.” Acreage shall be listed “by the four categories of critical habitat (feeding, no disturbance zone, barrier islands and denning habitat)” as defined by the Fish and Wildlife Service. Protecting sensitive permafrost and wetlands are a major part of the EIS analysis. “We conclude that constructing the project would have significant impacts on permafrost due to granular fill (gravel) placement, particularly for the mainline pipeline facilities. The project would have significant adverse impacts on wetlands from granular fill placement resulting in substantial conversions of wetlands to uplands.” Between the Arctic Coastal Plain and the Alaska Range to the south, about 580 miles of the 807-mile-long pipeline would cross continuous or discontinuous permafrost terrain. Construction work could degrade or thaw permafrost, affecting surface wetlands, soils and runoff, the report said: “Operation of the mainline pipeline could cause long-term changes to permafrost, affecting subsurface hydrologic connectivity, groundwater flow, greenhouse gas emissions, right-of-way integrity, and revegetation. Frost heave could cause bending strain in the pipe or disruption to surface drainage patterns.” AGDC’s work plan “identifies construction, restoration and mitigation measures specific to permafrost areas,” including: • Selecting the most appropriate construction method based on permafrost type and topography. • Working in thaw-sensitive permafrost during the winter only. • Working from gravel or ice pads to provide insulation over the permafrost. • Putting insulating material on slopes to control the rate of permafrost thawing and/or minimize degradation. The report provided numbers: “The project would result in significant long-term to permanent impacts on thaw-sensitive permafrost (about 6,377 acres), thaw-stable permafrost (about 3,415 acres), and forest (about 12,474 acres); and convert about 4,162 acres of wetland to upland.” Air quality and noise levels also would be affected by the project. “During the years of simultaneous construction, start-up, and operational activities at the liquefaction facilities (in Nikiski), as well as during flaring events, impacts on air quality could be significant.” The report said the same for noise levels near the Nikiski facilities: “Operational noise associated with the liquefaction facilities at the two nearest noise sensitive areas would likely double due to facility operation, which would be considered a significant increase.” ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Russia eyes Asian market in LNG expansion

A lot of countries have a lot of natural gas they want to sell into the global marketplace, which is growing both in size and competitiveness. Russia’s advantages in supplying a bigger share of the liquefied natural gas trade include its strong political and substantial financial support. Russia aims to increase its LNG output about fivefold by 2035 to capture around 20 percent of the global market, with 70 percent of its production going to the Asia-Pacific region, Energy Minister Alexander Novak told the Nikkei Asian Review in an interview the first week of June. Russia’s current LNG capacity is about 28 million tonnes a year from the 10-year-old Sakhalin-2 plant in the Far East and the 18-month-old Yamal LNG Arctic project. Novak said his government would like to see that total grow to more than 120 million tonnes by 2035. That would include not only more production in the Arctic and Far East, but also in the Baltic region. It’s an ambitious number — likely unrealistic — but the intent is clear. “Russia will consistently build up its gas-liquefying capacities to carve out the niche that our country deserves in this field,” President Vladimir Putin said via video link at the April opening of a small-scale LNG plant in Vysotsk, just across the border from Finland, on the Baltic Sea. While the plant is intended to serve domestic customers and small-volume buyers in the Baltic region, Scandinavia and Northwest Europe, it’s the large-volume customers in Asia that Russia covets. Just as it did for the Yamal LNG project, which shipped its first cargo in December 2017, the government plans to help pay for the port infrastructure and dredging needed for Russia’s second Arctic LNG project targeting Asian buyers. The government will cover 26.6 percent of the costs for building a new export terminal on the Gydan Peninsula for the Arctic LNG-2 project, Norway’s Barents Observer newspaper reported June 12. The private sector will pay 73.4 percent. A government commission has approved the funding plan, which was ordered by Putin. The government spent several billion dollars on construction of the port and airport for Yamal, which is just across the bay from the Arctic LNG-2 site. Both ventures are led by Novatek, Russia’s largest privately owned gas producer. Novatek is expected to make a final investment decision on Arctic LNG-2 in the third quarter of this year. It’s planned for 19.8 million tonnes annual capacity, with an estimated cost of $20 billion to $25 billion. Yamal, at 16.5 million tonnes, came in at $27 billion. Looking to control costs, Novatek plans to build the production modules for its second project at a new work yard near Murmansk, then tow the massive structures into place. Novatek has signed up partners for Arctic LNG-2 from China, Japan and France. Mitsui and Mitsubishi, two of Japan’s largest trading companies, will acquire a combined 10 percent stake. The deal is supported by the Japan Oil, Gas and Metals National Corp., an independent government corporation. The final agreement will be signed, likely in front of Putin, during the G-20 summit in Osaka later this month, according to news reports in Norway. France’s Total took a 10 percent stake last year. In April, Novatek agreed to sell a 20 percent stake to Chinese partners, equally split between a subsidiary of China National Petroleum Corp. and China National Offshore Oil Corp. Total and CNPC also are partners in Yamal LNG. Even before making a final investment decision, Novatek reported in May that it had selected U.K.-based TechnipFMC to construct Arctic LNG-2, with first gas planned for 2023. And already Novatek is starting development of a smaller, third LNG project in the Yamal region. The Ob LNG venture is estimated at $5 billion and could start operations in 2023 at almost 5 million tonnes, the Russian newspaper Kommersant reported, attributing the information to a high-ranking official at Novatek. State-controlled Gazprom, the lead partner in the Sakhalin-2 project, is looking at expanding its Far East operation and also building a new LNG terminal on the Baltic. Reuters reported June 7 that the Russian government will use its National Wealth Fund to help finance Gazprom’s petrochemical and LNG project in the Baltic port of Ust-Luga. The project would require equipment purchases of at least 900 billion roubles ($13.87 billion), Reuters reported. The LNG terminal would have an annual capacity of 10 million tonnes. And just as it did for Yamal, the government is considering tax breaks for additional Arctic gas projects. Companies could get their tax burden reduced by as much two-thirds for the life of the project, Russian Deputy Prime Minister Yury Trutnev was quoted by the Barents Observer in April. “We are looking at two alternative approaches: One with up to 15-year tax preferences that include zero tax rates on profits and property, land use and extraction; and a second with two-thirds tax reductions for the whole project period.” Help is not limited to financing, tax breaks and political support — there are icebreakers too. “Without a modern nuclear icebreaking fleet, it is impossible to imagine development of the Northern Sea Route,” Vyacheslav Ruksha, director of the Northern Sea Route Directorate of Rosatom State Corp., said at the May 25 launch of the country’s newest nuclear-powered icebreaker. “A decision has been made,” he said, to build additional nuclear icebreakers. “With their appearance in the Arctic, it will be possible to talk about year-round navigation along the Northern Sea Route.” The 568-foot-long Ural, launched at a Baltic shipyard, will sail north to break ice for LNG carriers when it’s delivered to Rosatomflot by 2022. “The Ural, together with its sisters, are central to our strategic project of opening the Northern Sea Route to all-year activity,” said a Rosatom official. The Ural’s nuclear reactors can generate 350 megawatts of power and the vessel can break through ice 10-feet thick. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

State answers FERC questions about Cook Inlet pipeline crossing

The state-led gas line development team has told federal regulators it is confident the Alaska LNG project’s steel pipeline could withstand Cook Inlet’s strong currents, shifting seabed and traveling boulders along the 29-mile underwater route to the gas liquefaction plant in Nikiski, on the Kenai Peninsula. The water-crossing information is among the remaining batches of answers the Alaska Gasline Development Corp. owes to the Federal Energy Regulatory Commission, which is scheduled to publish sometime this month its draft environmental impact statement for the proposed $43 billion project to pipe North Slope gas to the LNG terminal for export. Federal regulators last October asked the state team for more information on the Cook Inlet pipeline crossing, including how the currents could affect the line’s stability on the seafloor and how the high-pressure steel pipe would be protected against boulders. “The strong tidal currents of Cook Inlet could potentially move debris and boulders across the pipeline,” AGDC reported in a May 24 filing with FERC. The project team analyzed what would happen if boulders as large as 10 tonnes (22,000 pounds) fell on the 42-inch-diameter pipeline, which would be laid — not buried — on the seabed floor. The analysis also looked at the risk of 15-tonne boulders “traveling at the maximum identified Cook Inlet bottom current velocity of 4.8 knots.” The analysis showed that any hits by boulders of the size modeled “can be easily absorbed by the pipeline steel alone,” AGDC told FERC. For additional protection, the 1.25-inch-thick steel pipe would be coated with 3.5 inches of concrete before the lengths are welded together and lowered to the seafloor. The pipe in Cook Inlet would be substantially heavier than the pipe along the rest of the 807-mile route from Prudhoe Bay to Nikiski, most of which would range between 0.677 and 0.862 inches thick. Because the gas moving through the line is pressurized — to about 2,000 pounds per square inch — to keep it moving and keep it cool, the gas line steel is much thicker than the 0.462-inch and 0.562-inch pipe used for the Trans-Alaska Pipeline construction more than 40 years ago. AGDC’s answers filed with FERC also addressed questions raised last fall by the U.S. Pipeline and Hazardous Materials Safety Administration, which regulates oil and gas pipeline safety standards. Responding to the regulators’ questions, AGDC said it is not planning to install any piling, riprap (large rock) or “concrete mattresses” to help hold the pipeline in place against Cook Inlet currents. Its analysis determined no such anchoring is needed, the state team said in its May 24 filing. “The analysis indicates that the installed pipeline would be stable and not subject to lateral movement,” AGDC said. The state team added that stability designs would be “further evaluated … when updated geotechnical information is available.” The pipe segments would be welded together aboard a pipe-laying barge and the string continuously lowered into the water, putting stress on the steel pipe, concrete coating and welds. Federal regulators asked AGDC if it had a plan to ensure that the weight of the pipe and strong currents would not damage the line during the pipe-laying operation. “Initial analysis indicates that pipelay … will not result in stress loads sufficient to result in pipe buckling or concrete crushing,” AGDC said. The state corporation further explained that the exact tensions on the pipe would be specific to the vessel used for the operation. “Therefore, such issues will be re-examined when contractor equipment is known.” The project team expects the pipe-laying barge would move at 0.5 to 1 knot a day, with the entire operation from shore to shore scheduled for just short of three months when the inlet is ice-free. The underwater pipe would link up on the west and east sides of Cook Inlet with shorter segments trenched and buried through shallower water. In its analysis of seafloor conditions along the crossing route, AGDC relied on 22 soil corings, conducted in 2016 before North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips left the project and turned over management to the state. The companies at that time did not believe market conditions warranted proceeding with the FERC application and spending more money on permitting and design. Those 2016 soil corings were taken every 1,000 feet along the route where the pipeline would be buried or trenched near shore, and every 3 miles where the pipe would be laid uncovered on the bottom of the inlet. Federal regulators asked AGDC if it had collected sufficient site-specific data to confirm that the seafloor soil would be firm enough to support the heavily weighted pipeline, without the line sinking and putting high-strain loads on the pipe and welds. The state team referred to its 22 soil corings as a “preliminary assessment of bottom soil strata properties and strengths,” adding that “further evaluation will be conducted” if the project goes to the detailed design stage. Near to shore, the pipe would be buried in a trench. In the very nearshore, about 600 to 800 feet from landfall, the trench would be immediately backfilled to protect and hold the line in place, AGDC said. Farther out, “natural fill is expected to occur” to cover the pipe trench. The state team is scheduled to file its last responses to FERC’s environmental and engineering data requests later in June and in July. Those last answers are not expected to delay release of the draft environmental impact statement, or EIS, in June. Allowing for public hearings around the state, a public comment period and review by federal agencies participating in the EIS, federal regulators are scheduled to release the project’s final EIS in March 2020. FERC commissioners would be required to take up Alaska LNG’s project application no more than 90 days after the final EIS, putting a decision into June 2020. The state has been paying all of the permitting and design costs since the North Slope producers left the project 2½ years ago. AGDC expects to have about $22 million left in its account as of the end of the fiscal year on June 30, which could be tight to finish the effort at FERC while continuing to market the project to potential investors and customers and work on design issues in hopes of putting together an economically viable development. Though potential customers have expressed interest in Alaska LNG, none have signed a binding commitment or invested in the development, which would require billions of dollars in equity and tens of billions in long-term financing. BP and ExxonMobil have agreed to help the state finish its work at FERC. Each company will contribute $10 million to the effort, according to an announcement by Alaska Lt. Gov. Kevin Meyer at an oil and gas industry conference in Anchorage on May 30. The Alaska Legislature this session provided no additional state funding for AGDC but did grant the corporation the authority to deposit and spend the producers’ contributions. With the producers’ funding, the state corporation does not have to worry about shutting down later in 2020 for lack of money. Alaska Gov. Michael J. Dunleavy has been critical of the state leading the costly project. AGDC interim President Joe Dubler was quoted in March: “We’re trying to find potential partners to get the state out of the driver’s seat and get other people in.” ^ In other answers submitted to federal regulators in multiple filings in late May, AGDC reported: • Additional details of its fire-suppression and spill-prevention systems at the gas liquefaction plant, storage tanks and marine terminal in Nikiski and at the gas treatment plant at Prudhoe Bay that would remove carbon dioxide, water and other impurities from the gas stream before it starts its 807-mile journey to the LNG terminal. • Updated details for direct microtunneling to run the pipe under five waterway crossings, including the Tanana River. The filing includes plans for any inadvertent release of drilling fluids or other contaminants during the tunneling. In microtunneling, a laser-guided machine is lowered into a pit to dig its way under the waterbody. • Preliminary site-specific plans for each of the 24 gas pipeline crossings beneath the Dalton Highway, which runs from north of Fairbanks to Prudhoe Bay. • Further details for the 12 locations where the gas line would cross the trans-Alaska oil pipeline. For crossings where the oil line is buried, AGDC proposes to construct the gas line in a berm crossing over the oil line. The berm would provide a minimum of 3 feet of cover around the gas pipeline. Where the oil line is elevated, the gas line would be buried at least 4 feet underground. • The project’s air transport plan, detailing how AGDC proposes to move construction workers by aircraft along the project route. The busiest airport, according to the plan, would be Fairbanks, with up to a dozen flights a day, each carrying between 77 and 144 people. Other hub airports would be Anchorage, Deadhorse and Kenai. FERC also had asked how construction and operation of the pipeline and LNG terminal would affect salmon setnetters on the west and east sides of Cook Inlet. The state team said it “will work with setnetters and the Alaska Department of Fish and Game to estimate measurable loss of harvest, if any, related to construction activities. … Mitigation compensation would be based on the estimated lost harvest, as agreed to by both parties.” AGDC acknowledged that commercial salmon setnetters with leases at the LNG plant site and marine terminal “will lose fishing opportunity at those specific sites due to plant construction and operation. … AGDC will work with impacted setnetters and the State of Alaska to provide reasonable alternate beach access locations and alternate fishing sites. If no reasonable alternative can be identified, AGDC will work with individual setnetters to determine the appropriate amount of monetary compensation for salmon harvest loss or loss of access to a shore fishery lease.” Several factors will be considered to determine “the appropriate compensation including individual permit harvest history, terms of the shore fishery lease, and whether the damage is temporary or permanent,” AGDC said. In its May filings, AGDC provided FERC with a list of permits and authorizations required for the project, with anticipated receipt dates for the approvals. Most of the major approvals are expected later in 2020, such as the U.S. Army Corps of Engineers Clean Water Act permit, Environmental Protection Agency, Bureau of Land Management and U.S. Fish and Wildlife Service approvals. The state project team said it expects to file permit requests in the third quarter of 2020 with the North Slope, Fairbanks, Denali, Matanuska-Susitna and Kenai Peninsula boroughs. Those would include land-use, waste-disposal, utility, floodplain management, gravel sites and right-of-way permits. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

LNG export capacity keeps expanding

There were lots of big numbers last week for the U.S. liquefied natural gas industry. The country’s fourth LNG export terminal loaded its first cargo while work is underway on four more export projects, with two scheduled to come online this year and the other two planning start-up in three to five years. The eight plants will have a total nameplate capacity of more than 86 million tonnes of LNG per year, making the United States the world’s largest LNG producer until Qatar completes its expansion and retakes the title around 2024. U.S. gas going through the liquefaction plants this month is cheap, at least compared to the past 20 years. The June 1 benchmark price was less than $2.45 per thousand cubic feet. It hasn’t averaged that low for an entire year since 1999. But not everyone wants to be in the U.S. LNG business. Toshiba, which in 2013 signed a 20-year contract to take 2.2 million tonnes of LNG per year from the Freeport project in Texas, is bailing out even before its contract kicks in next year. The company signed the deal 2½ years after the 2011 tsunami and Fukushima nuclear plant meltdown forced Japan to shut down all its nuclear power plants, driving a steep spike in LNG demand and prices. But global supply has more than caught up with demand and prices have fallen. Toshiba decided it could not afford the risk of paying for liquefaction capacity at Freeport and maybe not finding enough buyers every year willing to pay the price to take all that LNG. So, the company, which has other financial problems and has decided to focus on its core businesses, last week struck a deal to turn over its Freeport LNG obligation to French oil and gas major Total. Freeport is expected to start up this year, and Toshiba’s contract is scheduled to start next year. In a reversal of the normal practice when a company sells an asset, Toshiba essentially is selling a potential liability and is paying Total $800 million to take over the contract. Toshiba has been quoted as predicting it could have lost billions of dollars over the life of the contract, depending on LNG market conditions. Total, the world’s second-largest LNG trader among the oil majors, is bulking up its gas portfolio, particularly in North America, adding the Freeport supply to its offtake contracts with two LNG export terminals in Louisiana. Of the two U.S. Gulf Coast export terminals just starting construction, one developer, Virginia-based Venture Global LNG, has lined up a $1.3 billion equity investment from New York investment firm Stonepeak Infrastructure Partners to cover about 30 percent of the predicted cost of its Calcasieu Pass project in Cameron Parish, La. Venture Global, which reported May 28 it already has spent more than $250 million on site preparation, engineering, equipment purchases and fabrication, said it plans to start production in 2022. To hold down construction costs, the company plans to use mid-scale, modular, factory-fabricated liquefaction trains for the plant’s annual LNG capacity of 10 million tonnes. Among those projects getting close to a final investment decision, Houston-based NextDecade on May 28 awarded a pair of construction contracts worth nearly $9.6 billion to San Francisco-based Bechtel for engineering, procurement and construction services for Rio Grande LNG in Brownsville, Texas. The start of work is contingent on NextDecade winning Federal Energy Regulatory Commission approval, anticipated in July, and then a final investment decision by the company. The contracts with Bechtel reportedly call for the LNG terminal to start up in 2023, eventually reaching 17.6 million tonnes annual capacity. Also in Texas, Freeport LNG, which is expected to start operations later this year from the first of three liquefaction trains under construction, already is looking toward an expansion and in May lined up FERC approval and Department of Energy export authorization for an additional 5 million tonnes of LNG per year. The fourth train, which the company said could come online by 2023, would boost the plant’s capacity to 20 million tonnes a year, the second-largest in the United States. Another Texas project made the news in May when Saudi Aramco agreed to a 20-year LNG deal to take 5 million tonnes per year from San Diego-based Sempra Energy’s proposed development in Port Arthur. Saudi Aramco also will take a 25 percent equity stake in the development. Sempra plans to make a final investment decision on Port Arthur in the first quarter of 2020. It would be the company’s second Gulf Coast export terminal. Its Cameron LNG project in Louisiana shipped its first cargo May 31. While Aramco wants to develop its own gas resources for power generation, it also is looking to buy into LNG developments in the United States, Russia, Australia and Africa as it starts to get into the business, the Wall Street Journal reported. “It’s unclear what the final destination of Saudi Aramco’s (Port Arthur) LNG will be. There continues to be a long-term expectation that, in time, Saudi Arabia will import LNG to be used for power generation,” said Giles Farrer, Wood Mackenzie’s research director. Though it wants to reduce its reliance on oil revenues, Saudi Arabia also wants to make more oil available for export by burning natural gas — either its own or imported gas — instead of oil for power generation. In 2015, Saudi Arabia held the world’s sixth-largest gas reserves, but producing that gas is tricky, and the country has large gaps in its power needs, according to a report in The Wall Street Journal. Multiple analysts said the Saudi deal to buy into low-cost U.S. LNG makes sense. “The investment in gas … is a way to secure a commodity it will itself demand as well as a hedge against a murky future for its main source of income (oil),” the Journal “Heard on the Street” columnist wrote. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

LNG exports slammed amid US-China trade battle

China’s increased tariff on U.S. liquefied natural gas is making it harder for project developers to negotiate sales into Asia’s largest economy, though it’s uncertain whether the trade fight will inflict long-term damage on the country’s growing gas export industry. “Chinese investment in U.S. LNG export projects will remain at a standstill, in our view, with Chinese offtakers likely waiting on a trade deal,” analysts at Barclays said just a couple of days after China announced it would boost its tariff on U.S. LNG to 25 percent from 10 percent on June 1. “This is going in the wrong direction,” said Charles Riedl, of the industry group Center for Liquefied Natural Gas in Washington, D.C. “Increasing tariffs … could have real long-term impacts on the pace of U.S. LNG export project development.” U.S. gas exports to China went into a steep decline after the Chinese government retaliated with a 10 percent tariff in September 2018, following on President Donald Trump’s decision to impose tariffs on Chinese goods. After sending an average of almost three cargoes per month to China in 2017 and the first half of 2018, U.S. LNG deliveries fell to one per month in the second half of 2018 and only three ships so far in the first five months of 2019. “I expect they will have a hard time landing a tanker carrying U.S. LNG in China,” Jack Weixel, senior director at IHS Markit’s PointLogic analytics arm, was quoted by Reuters the day after China ordered the 25 percent tariff. As if it wasn’t already hard enough. Low spot-market prices in Asia of around $5 per million Btu “already killed most of the commercial reasoning for U.S. sales to China,” said Ira Joseph, head of global gas and power analytics at S&P Global Platts. “The tariff is the knockout blow.” Weak demand and new supplies coming online this year have brought down prices. Feed gas flowed into six U.S. LNG terminals on May 15, a little more than three years after the first Gulf Coast terminal started operations in Sabine Pass, La. At $5, a cargo of U.S. LNG falls about $2 or $3 below recovering its full costs. But carriers still load up at U.S. terminals. The liquefaction fee, generally around $2.50 to $3 per million Btu, is a fixed cost that contracted offtakers must pay regardless of market prices — even if they don’t want to take the gas. They might as well sell the LNG and get what they can. And some of the LNG is delivered at higher prices under long-term sales-and-purchase agreements. Not for lack of trying, but U.S. project developers have not had a lot of success in getting Chinese buyers to sign long-term contracts — even before the dueling tariffs. Spot-market sales and third-party deliveries have been the main source of U.S. LNG supplies to China, though project developers would prefer long-term contracts to lock in the revenue stream needed to finance new capacity. That’s especially true for the maybe 10 or so additional LNG terminals proposed along the U.S. Gulf Coast, at various stages of permitting and trying to line up customers and investors. “Most of these projects need to secure long-term contracts in order to get financing,” said Sindre Knutsson, senior analyst on the gas market team at Rystad Energy, a Norwegian-based energy consultancy. “China will be one of the biggest contributors in sponsoring new LNG projects over the coming years, and there will be reluctance to signing new deals with U.S. projects as long as this trade war persists,” Knutsson said. Long-term contracts are essential for most project developers, which want to show investors and lenders they can cover debt and make money. “Such 10- to 20-year contracts require stability of terms for both sides,” said Edward Chow, of the Center for Strategic and International Studies in Washington, D.C. Even worse for U.S. developers, Knutsson said, “China’s decision to impose tariffs on U.S. LNG will make projects outside of the U.S. more attractive.” Just in the past few weeks, China National Offshore Oil Corp., or CNOOC, signed a long-term offtake deal for the Anadarko-led Mozambique LNG project, while CNOOC and China National Petroleum Corp. — two of the big three national oil companies — each took a 10 percent equity stake in Russia’s next multibillion-dollar gas project, Arctic LNG-2. Deliveries from Arctic LNG-2 are four years away, but a more immediate supply of Russian gas to China is scheduled to start flowing in December through the “Power of Siberia” pipeline. At full capacity in 2023, the line should be able to deliver 3.6 billion cubic feet of gas per day, equal to almost 15 percent of the country’s total gas consumption in 2017. In the first quarter of this year, China’s gas imports broke down as about 60 percent from LNG deliveries and 40 percent by pipeline, mostly from Central Asia. “The longer the tariff war continues, the more the United States will hand advantages to new rival producers in countries such as Russia and Mozambique, and help make the business case for existing major producers such as Qatar and Australia,” Reuters energy columnist Clyde Russell wrote the day China announced the higher tariff. “Projects that are under development that cannot sell LNG to China are at a competitive disadvantage — there is no doubt about that,” Nikos Tsafos, a senior fellow at the Center for Strategic and International Studies wrote May 14. But that statement comes with asterisks, Tsafos explained. “For one, Chinese buyers have never been major customers for U.S. LNG — the tariffs merely solidify an unfavorable reality.” Regardless of the trade fight and lack of Chinese offtakers, success for U.S. LNG project developers “still depends on finding a diverse customer base.” And there is a longer-lasting concern than any temporary tariff fight, he said. “It signals the extent to which energy relations and trade are becoming politicized … undermining confidence in an open market for energy and LNG.” Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

State nearing the end of project information owed to FERC

The Alaska Gasline Development Corp. continues to whittle down the information it owes federal regulators for the Alaska LNG Project’s environmental impact statement, which is due out as a draft sometime in June. The state-funded public corporation submitted three batches of responses to the Federal Energy Regulatory Commission on May 3 — totaling more than 300 pages — answering dozens of requests from this winter for additional technical information about the project. AGDC expects to send another package of information to FERC by the end of May, answering two-thirds of the remaining questions in that filing. The last responses are planned by the end of June and end of July. Among the last filings will be answers to regulators’ questions about the project’s 27-mile underwater pipeline crossing of Cook Inlet to Nikiski. FERC wants more geotechnical data about the seafloor and how AGDC proposes to stabilize and protect the pipeline against tidal currents and boulders. FERC had planned to release its draft environmental impact statement, or EIS, for the proposed Alaska LNG project in February, but postponed publishing the document until June. The commission did not provide a specific reason in February for the delay, though the five-week federal government shutdown that ended Jan. 25 interfered with the work of other agencies involved in helping to prepare and edit the draft EIS. FERC is under no legal requirement to issue the draft in June, though it would need to notify the applicant and public of any change in the schedule. The commission plans a nine-month work period which includes public and agency comments, public hearings, review and revisions to the draft, with the final EIS scheduled for March 2020. Under FERC regulations, the commission would be required to issue its decision on the Alaska LNG project application by June 2020. Already this year, the commission has issued final impact statements and project approvals for several U.S. Gulf Coast LNG ventures as developers are racing to meet growing market demand for the fuel amid an anticipated tightness in global supply sometime in the mid-2020s. The State of Alaska has been the sole developer of the Alaska LNG project for two and a half years since North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips declined to spend the substantial sums of money required for permitting, final engineering and design. The Alaska LNG project, estimated by the state to cost $43 billion, would remove carbon dioxide and other impurities from the gas stream at a North Slope treatment plant, then pipe the methane 807 miles to a liquefaction plant at Nikiski on the east side of Cook Inlet. AGDC has enough money left over from previous legislative appropriations to cover its work on the EIS this year. In case one or more of the North Slope oil and gas companies or other investors want to help start paying the bills toward further development efforts, the Alaska Legislature is considering giving the corporation “receipt authority” to deposit any checks AGDC might receive so that it could spend the money on the project. The state capital budget, which unanimously passed the Senate May 8, includes authorization for AGDC to receive and expend up to $25 million of non-state funds in the fiscal year that starts July 1. The bill still requires approval by the the House and then the governor. Without that receipt authority or additional state funds, AGDC would essentially run out of money sometime next year. Legislators generally have been supportive of AGDC using its available funding to at least complete the EIS. “There’s value in having a permit,” Sen. Bert Stedman, R-Sitka, co-chair of the Finance Committee, was quoted in the Anchorage Daily News on May 5. The AGDC board of directors is scheduled to meet May 22. The corporation continues to talk about commercial opportunities for selling Alaska LNG in the growing Asia market, while acknowledging that it first needs to determine the project’s economic competitiveness and then find partners, investors and customers for the gas. The corporation’s May 3 filings with FERC covered mostly safety systems and procedures at the Nikiski LNG facility and Prudhoe Bay gas treatment plant, such as the coverage area of firefighting water-spray apparatus, the use of firefighting foam equipment, emergency shutdown systems and protection of air intakes from volcanic ash. The filings also included a draft ballast water management plan for vessel traffic in Cook Inlet and Prudhoe Bay, and a marine mammal monitoring and mitigation management plan. For example, the marine mammal management plan explains that humpback whales, beluga whales, killer whales, sea otters, harbor porpoises and harbor seals “may be encountered near the construction activities” in Cook Inlet. If a marine mammal is spotted in the area during construction, pile driving would stop until the area is clear of the marine mammals, according to the management plan. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Oil market weighs OPEC output, Iran sanctions

President Donald Trump has the global oil market speculating whether he will allow last-minute waivers for countries to import Iranian crude, at the same time as oil buyers are waiting to learn whether OPEC and its allies will extend their production cuts past June. Each of the two decisions could either restrict oil output and drive up prices, or the opposite. Doing their part to boost supply, U.S. oil producers hit a record 12.3 million barrels per day during the last week of April. Texas, alone, is outproducing every OPEC member except Saudi Arabia. The collective uncertainty of too much oil, too little or just the right balance is bringing instability to prices at the same time as other events are affecting the market: • Russia temporarily cut back its oil production by a reported 10 percent after discovering it was shipping tainted crude to domestic and foreign refiners, Reuters reported May 3. • U.S. crude stockpiles are at their highest level since September 2017, according to the U.S. Energy Information Administration. Just a couple of weeks ago, the market was expecting that further reductions in Iranian oil exports, along with continued production declines due to civil unrest in Venezuela and Libya would help keep prices on the rise as buyers worried about supply. Brent, the global benchmark, had climbed from near $51 per barrel on Christmas Day last year to almost $75 on April 22. Alaska North Slope crude followed a similar climb, averaging about $74 the week of April 22. Alaska crude continues to track the global benchmark, separate from the U.S. pricing point for West Texas Intermediate crude, which traded under $62 per barrel last week. The strong growth in shale oil production is holding down U.S. prices, but a lack of pipeline capacity to move that surplus crude to the West Coast allows Alaska oil to earn a better price. However, it seems every time oil markets pick up amid fears that supply might not keep up with demand, something happens to steer prices the other way. The market fell by about $4 per barrel last week, sliding to their lowest point in a month, as supply fears eased. “Oil prices are under pressure,” said Rob Haworth, senior investment strategist at U.S. Bank Wealth Management. “Growing U.S. oil production and the weaker trend to global growth have helped moderate the impact of OPEC production cuts and U.S. sanctions on Iran and Venezuela,” he was quoted in The Wall Street Journal on May 3. A lot of the market uncertainty is focused on U.S. sanctions against Iran and whether Trump will allow some countries to import Iranian crude despite his decision to halt sanction waivers as of May 2. “The U.S. is saying they’re going to … take away those waivers again, and the oil price is clearly drifting up because of that,” BP CEO Bob Dudley told CNBC during an interview at the Milken Institute Global Conference in Beverly Hills, California, on April 30. “I think the key — the wild card key — is will the U.S. at the last minute give some more waivers or not?” The answer to that question will influence whether oil prices rise or fall, he said. Trump’s threats last fall to impose tough sanctions on Iran — with no waivers — drove up the price for Brent crude to $85 per barrel in early October. But then prices dropped into the low $50s when he approved waivers in November for Iranian crude buyers. Now faced again with rising oil prices, the president has called on Saudi Arabia and its OPEC colleagues to boost production to help cover for the loss of Iranian oil in the market. A big problem for the Saudis, however, is that they need higher oil prices to cover the nation’s spending. Saudi Arabia needs Brent at about $88 per barrel to balance its budget, according to calculations by The Wall Street Journal. The United Arab Emirates needs $72 oil, while Angola and Algeria are at $83 and $84, respectively. OPEC+, which includes Russia, is scheduled to meet June 25 to 26 to decide whether to continue their self-imposed curbs on output, though Saudi Arabia and other producers reportedly plan to meet May 19 to discuss the question of boosting output to help cover for the loss of Iranian oil in the market. By playing host for the May 19 technical session, the Saudis “fear Trump will be fixated by the meeting,” The Wall Street Journal quoted a source May 3. The president said he called OPEC on May 3 and told them to pump more oil to help reduce prices. “You’ve got to bring them down,” he said. Earlier in the week, however, Saudi Energy Minister Khalid al-Falih said there is no need to produce more oil, though he added that the country may do so if customers ask for more supplies. Within days, Bloomberg reported that Asian refiners were asking Saudi Arabia for more crude in June and July to cope with supply disruptions from Iran and Venezuela. But with OPEC still recovering from last year’s slide to the $50s, some analysts expect the organization to move cautiously. Complicating the president’s call on OPEC — Saudi Arabia, in particular — to protect the market for any supply loss from U.S. sanctions on Iran is the doubling of American shale oil production in the past five years, threatening OPEC’s dominance in the business. It’s a tug of war, Gordon Gray, head of oil and gas research at HSBC, was quoted by The Wall Street Journal. And it’s a war where U.S. producers have a price advantage against the $88 or so that the Saudi government needs to cover its budget. “The U.S. oil price needed for shale oil to be profitable is around $53 a barrel or above,” said Roy Martin, an analyst at consulting firm Wood Mackenzie. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Tokyo Gas signs gas deal linked to coal prices

Natural gas is increasingly promoted as a cleaner-burning option to coal for power generation, and liquefied natural gas is the answer for buyers without access to gas pipelines. Which makes it ironic — but sensible in a competitive energy market — that a long-term LNG contract would be linked to coal prices. Tokyo Gas this month signed a heads of agreement with Shell for a 10-year supply of LNG starting in 2020, at 500,000 tonnes per year. That’s about seven or eight full cargoes per year in conventional LNG carriers. Some of that supply — the companies are not saying how much — will be indexed to coal prices. It appears it’s the first time a Japanese buyer is using a coal-based pricing index in an LNG contract, Reuters reported. The explanation is that Japan’s second-biggest LNG buyer is stepping up its efforts to diversify supply sources and pricing while it works to reduce costs. The volume not based on coal will be priced to conventional gas- and oil-linked indexes, a Tokyo Gas spokesman said April 5. Traditional oil-linked LNG pricing, which goes back decades, is roughly based on the energy-equivalency of gas to oil. Burn one or the other, the price is similar. It’s the same logic for coal-indexed LNG pricing. “Coal indexation in LNG contracts will be particularly relevant for Japanese buyers, not least because coal is an integral part of Japan’s power-generation mix,” Abhishek Kumar, head of analytics at Interfax Energy in London, told Reuters. Integral and equal to gas in market share, the target for the country’s 2030 energy mix is 26 percent coal and 27 percent LNG, according to Japan’s Ministry of Energy, Trade and Industry. “Coal remains the largest competitor to gas in the power sector in Asia. If the index is competitive, this could be an important step for enabling LNG and utilities to better compete with coal,” Nicholas Browne, a Wood Mackenzie analyst, told Reuters. Coal-indexed LNG pricing is a smart “risk management strategy” for a company that competes with coal-fired generation, said Christopher Goncalves, chair of the energy practice at Berkeley Research Group. The Tokyo Gas deal with Shell underscores how Asian buyers are pushing hard for price diversification, which will increasingly influence LNG contract negotiations and renegotiations, S&P Global Platts reported. “We are in a stage of experimentation with non-oil indexation,” Craig Pirrong, professor of finance at the University of Houston, was quoted by Platts. The traditional oil indexation is one of three fronts in LNG contracts on which Asian LNG buyers have pushed back in recent years. The other two being destination restrictions to prevent buyers from redirecting or reselling cargoes, and contract durations. Japan’s energy ministry has advocated for abolishment of destination clauses for years. Asian buyers have also gained traction in cutting contract durations, with the market structure moving in favor of shorter-term contracts. Oil indexation, however, has been tougher to dislodge. The deal with Shell “is an example of diversification of pricing, in line with Tokyo Gas’ previously stated strategy,” Hiroshi Hashimoto, senior gas group analyst at the Institute of Energy Economics of Japan, told S&P Platts. But some analysts see the coal-linked deal as not that big of a deal. It’s a long-overdue step but unlikely to represent a major shift in the market, a Reuters’ columnist reported April 10. Buyers and sellers could easily see oil market pricing, and it made sense over the years to stick with that proven formula to provide a reasonable level of revenue certainty for developers of multibillion-dollar LNG export projects, columnist Clyde Russell said: “Crude also made more sense than coal, given that 40 years ago the crude futures market was significantly more advanced — and still is — than the market for trading thermal coal.” The Tokyo Gas deal makes sense in Japan, where LNG and coal are effectively competing fuels, Russell said. By linking the prices, Tokyo Gas can hedge against competitors that use coal for power generation. “While this recent innovation makes sense in Japan, it may not have too much relevance in other countries in the region,” the April 11 column said. Spot-market pricing or short-term deals linked to LNG or natural gas indexes are likely to hold more appeal outside Japan than coal-indexed pricing, Russell said. Those other pricing mechanisms offer enough flexibility and don’t require strong knowledge of the workings of coal markets. Regardless whether the Tokyo Gas deal with Shell is a trendsetter or just an outlier, coal still is a big player in Asia’s energy mix. China has decided to allow 11 provinces and regions to resume building coal-fired power plants. It’s a clear sign that the world’s largest energy user is far from finished with the most-polluting fossil fuel. Bloomberg News reported April 19 that China’s National Energy Administration forecasts that the 11 provinces — which previously had been labeled as overcapacity for power generation — no longer have too much capacity and can now start adding new coal plants. The decision underscores how dependent the world’s second-largest economy still is on coal, Bloomberg reported, even as China invests hundreds of billions of dollars in cleaner energy sources such as natural gas, wind turbines and solar panels. And while coal’s share of China’s energy consumption fell slightly last year, the volume of coal burned increased as the country’s total energy demand grew. China is not alone in keeping coal around. Pakistan has fired up its first major power plant fueled by one of the world’s 20 largest coal reserves, the country’s Thar desert, S&P Global Platts reported. The new power plant will allow coal to compete head on with imported LNG in the country’s power mix. Pakistan has battled severe power shortages for years and expects to ramp up the share of coal in its electricity mix to 30 percent by 2030 from as little as 1 percent in 2014, driven mainly by its Thar coal fields, S&P Platts reported. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Spending for US LNG approaches $80B by year-end

Spending commitments since 2012 for liquefied natural gas export projects on the U.S. Gulf and East coasts could total more than $80 billion by the end of this year, with an additional $30 billion or more possible in the next year. When the construction dust settles by the mid-2020s, the United States could be No. 1 or No. 2 in the world in LNG export capacity, depending whether Qatar completes its expansion before then. The $80 billion will buy close to 100 million tonnes a year of U.S. liquefaction capacity, about five times the volume of the proposed Alaska LNG Project. It’s been a busy early spring for U.S. LNG project developers: Calcasieu Pass Construction work has started on Louisiana’s third LNG export terminal. Venture Global’s co-CEO announced April 4 that work had started on the Calcasieu Pass project, at 10 million tonnes of annual capacity. It’s only the second U.S. Gulf or East Coast LNG export project not built at the site of an unused or underused gas import facility. Golden Pass The partners in Texas’ third export terminal made a final investment decision in February to proceed. ExxonMobil and Qatar Petroleum’s $10 billion Golden Pass LNG export project will have almost 16 million tonnes of annual capacity. Start-up is planned for 2024. Magnolia The Louisiana hopeful has cut its price for liquefaction services to attract customers. Australia’s LNG Ltd. is offering liquefaction contracts for as little as $2.35 per million Btu, about 20 percent below the prevailing rate as it works to sign the first long-term contract for its $6 billion Magnolia LNG project, CEO Greg Vesey said April 2 in an interview of the LNG2019 conference in China. At the current U.S. price for feed gas, that would put Magnolia’s output at $5.74, plus shipping. “It’s very tough right now on the commercial front,” Vesey told S&P Global Platts. Driftwood The developer signed up French major Total for a $700 million investment as it tries to put together financing for its LNG project in Louisiana. Total invested $500 million in the parent company, Driftwood Holdings, and bought $200 million of stock in Tellurian, developer of the $30 billion LNG terminal. Total also signed a non-binding agreement to take 2.5 million tonnes a year from Driftwood LNG for 15 years. The gas will be priced off the Japan-Korea Marker for Asian LNG, a fast-developing spot-market benchmark and the first use of the price index for a U.S. project. Tellurian has said it plans to make a final investment decision this year, with phased completion between 2023 and 2026. Rio Grande This developer became the first to sell U.S. LNG pegged to global oil prices instead of Gulf Coast natural gas prices. Developer NextDecade said April 2 it had signed a 20-year deal to supply Shell with 2 million tonnes of LNG per year from the proposed $17 billion Rio Grande LNG export project in Brownsville, Texas. Three-quarters of the LNG will be indexed to Brent crude oil prices, and the rest will be indexed to domestic U.S. gas price markers. Houston-based NextDecade was founded in 2010 and now has 36 employees. It has no operations and is funded by investors. The company has not announced a final investment decision for Rio Grande LNG. With multiple LNG projects in the United States and elsewhere vying for financing amid a crowded market, developers are competing to offer flexible pricing options to potential offtakers. With most Asian LNG contracts priced off oil, U.S. projects that can offer a diversity of price indexation beyond U.S. gas prices may be able to capture more market, Saul Kavonic, an analyst with Credit Suisse, was quoted by Reuters on April 1. However, Total CEO Patrick Pouyanne said he doesn’t understand the logic of linking U.S. LNG to oil prices. “Continuing to price gas linked to oil is somewhat old world,” Pouyanne told Bloomberg News. “I was most surprised to see new contracts linked to Brent, especially from the U.S. Someone will have to explain this to me.” One more project in Louisiana and another in Texas report that they, too, are moving toward final investment decisions, though both are still working on signing up enough customers for a go-ahead. That includes Sempra Energy’s proposal in Port Arthur, Texas, which would be the company’s second Gulf Coast project. Its Cameron LNG terminal in Hackberry, La., is scheduled to start shipping before June. 30. Outside the United States — in a move away from LNG contracts linked to global oil prices or natural gas prices — Japan’s Tokyo Gas said April 5 it had signed a 10-year deal for LNG supplied from Shell’s global supply portfolio, partly using a coal-linked pricing formula. It’s believed to be the first time a Japanese buyer is using a coal-based pricing index in an LNG contract, industry observers said. “Coal remains the largest competitor to gas in the power sector in Asia. If the index is competitive, this could be an important step for enabling LNG and utilities to better compete with coal,” Nicholas Browne, a Wood Mackenzie analyst, was quoted by Reuters. “Coal indexation in LNG contracts will be particularly relevant for Japanese buyers, not least because coal is an integral part of Japan’s power-generation mix,” said Abhishek Kumar, head of analytics at Interfax Energy in London. It’s “a risk management strategy for somebody who is competing with coal-fired generation,” said Christopher Goncalves, chair of the energy practice at Berkeley Research Group. And while developers are trying different pricing structures to attract buyers and reach their investment decisions, one area of agreement is that banks are largely unwilling to finance new U.S. LNG capacity without developers having commercial deals in place. “My favorite model is the one where I take the least amount of risk and get the highest rate of return,” Roberto Simon, a managing director at French investment bank Societe Generale, told S&P Global Platts on April 4. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Russian producers press forward in face of sanctions

Russia’s big gas producers, Gazprom and Novatek, have been busy with plans for new liquefied natural gas projects, expanding their market reach and attracting foreign investment. If it all comes true, Russia could enter the mid-2020s with capacity to make almost 70 million tonnes of LNG a year, more than 20 percent of last year’s global demand. Russian gas is well positioned to reach new markets in Asia and the Atlantic Basin, a Shell executive said March 20 at an LNG conference in Moscow. Stuart Bradford, Shell’s senior deal lead, said Russian supplies could come from the Arctic, the Far East and Baltic Sea. Shell, the world’s largest seller of LNG at 22 percent of the market last year, is a partner with Gazprom in LNG export projects in the Baltic and Far East. The proposed Baltic terminal would be in the northern Leningrad region, with capacity of 10 million tonnes per year. The plant would get its feed gas from West Siberia. The cost is projected at slightly more than $11 billion — at the lower range of the global per-tonne average. Start-up is tentatively planned for 2023, depending on a timely investment decision. The 10-year-old Shell/Gazprom Sakhalin-2 terminal in the Far East, with Japanese partners Mitsui and Mitsubishi, has a nameplate capacity of 9.6 million tonnes per year. The owners want to add a third liquefaction train at 5.4 million tonnes per year, at a cost of $5 billion to $6 billion, but they still need to resolve gas-supply issues. In addition to investing in LNG capacity, Shell said in February it had created a new 50-50 venture with Gazprom to use Shell LNG’s expertise to develop Russian technology for liquefying gas. The venture would help insulate Russia from any new U.S. sanctions on LNG technology. Also in the Far East, ExxonMobil and state-controlled Rosneft, Russia’s largest oil producer, are moving closer to building their own liquefaction plant, Sakhalin-1, on the same 589-mile-long island as the Shell/Gazprom terminal. Reuters reported March 20 that ExxonMobil’s Russia unit may make a decision this year to start front-end engineering and design work for the gas project with partner Rosneft. Sakhalin-1 has been producing oil and reinjecting its gas since 2005. The companies reportedly are looking at a $15 billion project. Gazprom/Shell, however, would prefer that Rosneft/ExxonMobil ship or sell their gas to Sakhalin-2 instead of building a new terminal, but they have not succeeded in those negotiations. Russia’s largest non-state-controlled gas producer, Novatek, is focused on the Arctic, where it led a consortium with Chinese and French partners that started up the $27 billion Yamal LNG project in December 2017. Novatek is moving toward an investment decision this year on its next Far North gas project, Arctic LNG-2. At 19.8 million tonnes annual capacity, it would be larger than Yamal’s 16.5 million tonnes, but reportedly would cost 10 percent to 20 percent less to build with modular components towed into place. The company will be able to deliver Arctic LNG to Europe at half the cost of U.S. Gulf Coast cargoes, Novatek Chief Financial Officer Mark Gyetvay said in February. The company would build equipment and technology in Russia to protect itself. “We will not hold ourselves hostage to U.S. sanctions,” Gyetvay told the International Petroleum Week event in London. China, which helped finance almost half the cost of Yamal, also is looking at investing in Arctic LNG-2, as are Saudi Aramco and Japanese companies. France’s Total already has signed on as a 10 percent partner. “Arctic LNG-2 fits into our strategy … based on giant, low-cost resources primarily destined for the fast-growing Asian markets,” Total CEO Patrick Pouyanne said March 5. The Japanese government is pushing Mitsui and Mitsubishi to decide whether they want to take a stake in Arctic LNG-2, according to a March 4 report in the Nikkei Asian Review. The Japanese government sees it as an opportunity to make progress on a long-running territorial dispute with Russia over a set of islands annexed by Moscow after World War II. While the trading houses understand the project’s significance as a new source of LNG, U.S. gas is starting to arrive in Asia and the companies also could decide that expanding Sakhalin-2 is a better investment. Expanding its partnership reach to the Middle East, Novatek CEO Leonid Mikhelson said he has been talking with Saudi Arabia Oil Minister Khalid al-Falih about an investment in Arctic LNG-2. “I think we will get something concrete in the coming months,” Mikhelson was quoted by Reuters on March 17. Currently, Yamal LNG travels directly to Asia aboard expensive ice-class gas carriers when sea ice allows transit through the Northern Sea Route. But when that’s not possible — even with icebreaker escorts — the gas heads to Europe for sale or reloading aboard conventional LNG carriers for the longer voyage to Asia. Novatek would like that to change. “Our plan is to keep the Northern Sea Route open 12 months a year by 2023-2025 with 100-megawatt-hour nuclear icebreakers,” Chief Financial Officer Gyetvay told delegates at an energy conference in Moscow. He did not provide further details. Rather than competing, Gazprom and Novatek should develop an integrated strategy against challenges from other suppliers, Tatiana Mitrova, director at the Skolkovo Energy Center in Moscow, said at an LNG conference in Moscow on March 16. The global market is a “cruel battlefield,” she said, naming Qatar, the United States and Australia as Russia’s competitors. Gazprom holds a monopoly on pipeline gas exports from Russia, while Novatek sells its LNG into the same European market. Mitrova gave that as an example where the companies could work together, perhaps with pipeline gas providing baseload supply and LNG meeting demand peaks. Meanwhile, Gazprom said it is on target to start deliveries to China in early December through its new Power of Siberia pipeline. The plan is to start at 500 million cubic feet per day next year, ramping up to full capacity of 3.6 billion cubic feet per day by 2025. At full capacity, the pipeline would about equal China’s pipeline gas imports from Central Asia, mostly Turkmenistan. Those combined pipeline imports would about equal the amount of gas imported as LNG last year. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC stays on schedule with latest batch of answers to FERC

While cutting back on overall spending to preserve its money to last into 2020, the Alaska Gasline Development Corp. continues answering questions and providing additional information to federal regulators, submitting on March 1 the first of six batches of information it is scheduled to submit through September. The information will be included in the Federal Energy Regulatory Commission’s safety review and final environmental impact statement, or EIS, but not necessarily in the draft EIS that is scheduled for release in June. The March 1 packet answered about 60 of FERC’s information requests from January, dealing mostly with fire safety, equipment and procedures, including trucking fuel to the facilities; mapping fault lines, unstable slopes and other geologic hazards; and plans for a temporary access road during construction that would cross over existing buried pipelines at Prudhoe Bay. The state-led Alaska LNG project team had told FERC it would answer the remaining questions about fire safety, spill-containment safeguards, hazard mitigation and other design issues in monthly batches March through July. The requested information covers various details of the North Slope gas treatment plant at Prudhoe Bay, and the liquefaction plant and liquefied natural gas storage tanks in Nikiski. It will be September, however, before AGDC provides federal regulators with more information about the project’s 27-mile underwater pipeline crossing of Cook Inlet to Nikiski. FERC wants more geotechnical data about the seafloor. It also wants to know if AGDC expects tidal flow and other currents will move debris and boulders across the pipeline, and how the project proposes to stabilize and protect the line against tidal currents and boulders. If all goes according to schedule between the state project team, FERC and other federal agencies involved in preparing the EIS, the final impact statement is scheduled for release in March 2020. That allows nine months for public and agency comment, public hearings, review and revisions between the June 2019 draft and the final EIS. The single EIS will be used by all federal agencies involved in regulatory oversight of the proposed Alaska LNG project, which includes a gas treatment plant at Prudhoe Bay to remove carbon dioxide and other impurities, 807 miles of large-diameter high-pressure steel pipe to move gas to the liquefaction plant and LNG export terminal in Nikiski. Though the state corporation expects to end the current fiscal on June 30 with about $20 million still available to spend, it could run out of funds about the same time that FERC finishes work on the EIS according to a staff financial presentation at the March 6 AGDC board meeting. The corporation is cutting back on its leased office space in Anchorage, closing its Houston office and taking other steps to stretch out its available funding. Interim AGDC President Joe Dubler told the board March 6 that the corporation also has been able to reduce its legal and contractual spending this year. The Alaska Legislature is now working to put together the state budget for fiscal year 2020, which starts July 1, but there was no request before lawmakers as of March 11 to appropriate additional funds to AGDC. Many legislators have said they are looking for evidence that the estimated $43 billion project is commercially viable before proceeding past the EIS. Gov. Michael J. Dunleavy has said he opposes state control of the project — with the state taking all the risk — and he wants to see the North Slope producers back on board. “AGDC will only pursue Alaska LNG if the project viability is assured,” Dubler told the board March 6. “AGDC will seek third-party support from qualified, experienced LNG project owners and operators to build, own, and operate the project.” The state took over the project more than two years ago after North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips — citing market conditions — declined to spend the billion-plus dollars that would be required to complete permitting, final design and engineering. The state, anxious to see the project continue at a faster pace, took over 100 percent funding of the application to FERC and the environmental impact statement. AGDC has not contracted for construction-ready final engineering and design work, which could cost as much as $2 billion, Dubler told the board March 6. While working to finish the EIS, the state corporation continues talking with potential investors and customers, looking to determine if the project can pass the economic-viability test. While continuing its quest for the large-volume Alaska LNG project, the state corporation has completed its original 2010 assignment when the Legislature created AGDC: Obtain regulatory approval for a smaller-volume backup project to deliver North Slope gas to Alaskans. The U.S. Army Corps of Engineers and federal Bureau of Land Management on March 4 signed a joint record of decision for the Alaska Stand Alone Pipeline, or ASAP, also known as the in-state project and the bullet line. The 733-mile pipeline would move North Slope gas south through the state, ending at a connection point near Big Lake, north of Anchorage, to ENSTAR’s gas distribution system for Southcentral Alaska. The project, estimated by AGDC several years ago at $10 billion, does not include a liquefaction plant or any other export component. The line’s maximum capacity would be 500 million cubic feet of gas per day, far less than the LNG project that is designed to handle 3.5 billion cubic feet per day at the entrance to the gas treatment plant at Prudhoe Bay. ASAP was intended to meet in-state needs for natural gas, in particular providing gas to Fairbanks and potential mining projects. The line’s capacity would be more than double the average daily demand of all Southcentral gas users. The state paid 100 percent of the cost of permitting to reach the federal record of decision, but there is no money available for final engineering and design. And, like the LNG venture, the economics of the backup project are questionable. The Legislature has appropriated about $480 million in state funds to AGDC for the two projects since 2010. The final EIS and record of decision on the backup line are helpful to AGDC and the larger gas pipeline project, particularly the decision by the Army Corps to allow construction in wetlands, with mitigation as required. “Because ASAP and Alaska LNG share a common path for 80 percent of Alaska’s LNG pipeline route, this permit and the underlying data will help the Alaska LNG project efficiently advance through the federal permitting process,” AGDC said in a prepared statement. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Jones Act leaves New England out of LNG boom

Western Canada, the U.S. Gulf Coast, West Texas and Appalachia are all overflowing with natural gas. So much so that prices are down and occasionally have turned negative in some areas, when producers actually had to pay someone to take their gas. Too bad there is no easy way to move more of that gas to the U.S. East Coast, New England and Canada’s Maritimes provinces, where natural gas customers are paying the highest prices in North America. The obstacles are by land and by sea. There is not enough pipeline capacity to reach the Eastern Seaboard. And a 99-year-old federal law, the Jones Act, requires that only U.S.-built and U.S.-flagged ships can move cargo between U.S. ports. The problem is, no such liquefied natural gas carriers exist. Examples of too much supply in gas-producing regions and too little of it reaching the gas-consuming coast are economically painful. Next-day natural gas prices at the Waha hub in the Permian Basin in West Texas tumbled to their lowest on record Nov. 27 because of limits on the amount of gas that could move out of the region by pipeline, Reuters reported. Prices fell to an average of 25 cents per million Btu that day. Even worse than a measly quarter, traders said small amounts of fuel were sold at negative prices as producers struggled to get rid of their gas. That compares to the U.S. benchmark price at Henry Hub, Louisiana, which averaged about $4 per million Btu in November. The Permian is the biggest oil-producing shale basin in the country, and because gas is associated with much of the oil coming out of the ground, it is also the nation’s second-biggest shale gas region, behind Appalachia. Permian drillers want the oil, which is much more valuable than gas, so they deal with the gas as best they can. New pipelines are being built or planned to move Permian gas production to the Gulf Coast, where a growing number of liquefaction plants can turn it into LNG for export, and to Mexico, which needs U.S. gas to cover its own production shortfall. But until the new lines are up and running, West Texas producers will have to take what they can get. The imbalance is just as noticeable in Canada, where last May 3 spot prices at Alberta’s AECO pricing hub closed at just 5 cents per million Btu, about $2.50 less than the U.S. benchmark price that day. Then in October, gas prices in Western Canada went into a freefall as a ruptured pipeline limited producers’ ability to get their gas to market. With one less conduit to move Canadian gas to customers south of the border, spot prices at Alberta’s AECO trading hub fell to 8 cents per million Btu on Oct. 19. At the other end of the price spectrum in November, gas prices at the New England trading hub rose to $13.70 per million Btu for Nov. 21, about triple the year-to-date average, Reuters reported. And when gas costs more, so does electricity. Next-day power prices in New England on Nov. 21 were about four times the national average. When winter hits New England, power and gas prices can spike quickly because most consumers use gas to heat their homes and businesses, and most of the region’s electricity usually comes from gas-fired power plants. Companies have tried to build more pipelines to bring gas from the Marcellus shale basin in Pennsylvania and other plays, but they have encountered objections from residents in Virginia, Massachusetts and New York, and denials of state permits in New York. Pipeline developers, however, are not giving up. Calgary-based operator Enbridge will continue to push federal, state and local regulators to allow new gas pipelines that could serve New England with production from nearby Appalachian basins, CEO Al Monaco said Feb. 15. “It’s never been more clear that we need additional gas infrastructure and nowhere is that more evident than in the U.S. Northeast,” Monaco said during a conference call with analysts to discuss fourth-quarter financial results. “This is actually an unbelievable irony when the Marcellus is sitting right next door to this market,” Monaco said. The LNG story in New England is just as ironic. The U.S. shale boom keeps breaking records, producing more gas than the country needs and triggering billions of dollars of investments in export terminals. LNG carriers are leaving the docks for Europe, South America, Asia, even Canada this month. But without a U.S.-flagged LNG carrier, there is no way to move affordable Gulf Coast LNG to the East Coast. Instead, New England has to import LNG from overseas to meet peak winter demand. The LNG import terminal in Boston harbor received about 24 cargoes in 2018, with all but one coming from Trinidad and Tobago. The other cargo was Russian LNG. Dominion Energy’s Cove Point, Md., terminal took in a Nigerian cargo in December 2018. And then this month, a load of U.S. gas left the dock at Cheniere Energy’s export terminal in Sabine Pass, La., headed to the Canaport LNG import terminal in New Brunswick. It was the first delivery of U.S. LNG to Canada, where the Atlantic seaboard provinces have become a customer for U.S. gas to replace domestic supplies since the Sable Offshore Energy Project ceased production in December 2018 after 19 years of serving the region. The Canadian Maritimes “will transform from being an exporter of domestic gas to being an importer of gas from the U.S.,” said Canada’s National Energy Board. Before the U.S. cargo, Canaport received six LNG deliveries in 2018 from Trinidad, Norway and elsewhere. And like New England, there is not enough pipeline capacity to move prolific supplies of U.S. shale gas or Western Canadian gas into the Maritimes. Which means high prices for consumers. Maritimes’ consumers already pay the highest average residential gas bills in Canada, according to the National Energy Board, with bills averaging $160 a month, roughly double British Columbia, Alberta and Saskatchewan. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Draft EIS for Alaska LNG Project pushed back four months

Citing the state’s timeline for answering federal regulators’ questions and fulfilling data requests, the Federal Energy Regulatory Commission has extended by four months its scheduled release date for the Alaska LNG project’s draft environmental impact statement, or EIS. In a notice issued Feb. 28, FERC said it now plans to issue the draft EIS in June. The commission did not specify a date in June. The scheduled release date had been February. The delay in the draft EIS also adds four months to FERC’s schedule for the state-led project’s final EIS. In its Feb. 28 notice, the regulatory commission said the final EIS would be issued March 6, 2020, instead of November 2019. But March 2020 depends on the Alaska Gasline Development Corp. answering all of FERC’s questions in full this summer. “The revised schedule for the EIS is based upon AGDC meeting its commitment to provide complete responses to outstanding data requests on the dates it has identified,” FERC said in its notice. “Staff has revised the schedule for issuance of the final EIS based on an issuance of the draft EIS in June 2019.” FERC explained that its previous schedule of a draft EIS in February and final impact statement in November “was based upon AGDC providing complete and timely responses to any data requests.” The commission has always advised AGDC — the same as for any other project — that an EIS schedule is dependent on full information from the applicant. In its filings in January and February, the state project team reported it would submit answers and additional technical data to more than 150 of FERC’s most recent questions in several batches, starting in early March and ending in July. In a statement provided to the Alaska Journal of Commerce, AGDC spokesman Tim Fitzpatrick said, “FERC’s comprehensive analysis of Alaska LNG now includes more than 150,000 pages of environmental and engineering data, including responses to more than 1,700 FERC queries submitted since AGDC initiated this permitting process twenty-two months ago. Previous FERC scheduling changes accelerated the permitting calendar, and we believe that today’s revision does not affect the prospects for Alaska LNG. We look forward to working with FERC to complete this process and obtain the permits required to bring Alaska’s North Slope natural gas to market.” The state has been talking the past two years with potential lenders, partners and customers in China and elsewhere in Asia, but has not reached any firm deals. The state has spent close to $500 million the past several years on the Alaska LNG project and a smaller, backup project, the Alaska Stand Alone Pipeline, as hopes continue that someday a pipeline will deliver North Slope gas to Alaskans and overseas markets. “Our current plan is to step back and evaluate technical and commercial aspects of the project,” AGDC’s interim President Joe Dubler told a state Senate budget subcommittee in Juneau on Feb. 27 as quoted in an S&P Global Platts report. “If it is viable we are going to solicit world-class partners for FEED, which is front-end engineering and design.” If FERC issues its final impact statement in March 2020, the deadline for commission action on the Alaska LNG project application would be June 4, 2020, 90 days after issuance of the final EIS. Federal regulators have been working to prepare the draft EIS since the state in April 2017 submitted its application for the estimated $43 billion project to move North Slope natural gas down an 807-mile pipeline to a liquefaction plant and export terminal in Nikiski, on the eastern shore of Cook Inlet. AGDC has been working to answer hundreds of questions and data requests from FERC and other federal regulatory agencies participating in the single federal EIS for the project. The proposed Alaska LNG development, which the state took over from North Slope oil and gas producers in late 2016, also includes a gas treatment plant at Prudhoe Bay to remove carbon dioxide and other impurities from the gas stream and a 62-mile pipeline to deliver gas from the Point Thomson field to the treatment plant at Prudhoe. AGDC still owes FERC information on fire safety, spill-containment safeguards and hazard-mitigation designs at the gas treatment plant, liquefaction plant and LNG storage tanks in Nikiski. In addition, federal regulators are waiting for information from the state on pipeline crossings at active earthquake faults, and a more detailed route map showing all seismic hazards within 5 miles of the pipelines. The state team also owes FERC more information about the project’s 27-mile underwater pipeline crossing of Cook Inlet, including addressing whether tidal flow and other currents would move debris and boulders across the pipeline and, if so, how much movement is expected. The regulator also wants to know if AGDC plans to use any additional weights or supports along the underwater pipeline after construction to stabilize the line against tidal currents, and whether the seafloor is firm enough to prevent the weighted 42-inch-diameter pipe from sinking into the seabed and straining the pipe welds during construction and operations. The state gas development corporation reports it has enough funding left over from prior legislative appropriations to last through the EIS process, assuming lawmakers this session approve AGDC’s $10 million operating budget plan for the fiscal year that starts July 1. Moving past the EIS, however, would require at least several hundred million dollars for final engineering and design, which the corporation does not have. It also would require investors, binding gas-supply contracts with the North Slope producers, bankable contracts for customers to take capacity on the pipeline and through the liquefaction plant, and buyers for the LNG. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Pages

Subscribe to RSS - Larry Persily