Larry Persily

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.

Canadian producers unite in LNG export effort

It worked almost a quarter-century ago for several Western Canadian natural gas producers who were tired of not having enough access to markets when they joined together to build a $3.1 billion pipeline to reach U.S. buyers. Maybe it will work again, though this time the producers are looking overseas. “We as a group are very keen to see LNG off the West Coast,” said Darren Gee, president and CEO of Calgary-based Peyto Exploration and Development, which touts itself as Canada’s fifth-largest gas producer. Frustrated over low prices for their gas, exasperated over delays in new access to world markets and irritated that oil and gas majors seem in charge, Peyto and nine other companies announced in February that they will work together to see if they can get a second liquefied natural gas export terminal built on Canada’s West Coast. The group is “a collaboration amongst competing producers” that between them supply 20 percent of Canada’s gas and 40 percent of gas liquids such as propane, butane and ethane, said Greg Kist, former president of the canceled Pacific NorthWest LNG project in Prince Rupert, British Columbia, and who is working as a consultant to the group of 10 producers. “The producers want to deal with the challenge we have today with weak prices,” Kist said, as reported in Canada’s Financial Post on Feb. 20. The producers’ options include reviving Pacific NorthWest LNG or finding another project to adopt among the several unsuccessful West Coast LNG ventures. Of the more than a dozen proposals, the only large-scale project to go ahead so far is the Shell-led LNG Canada venture, which started site work in late 2018 in Kitimat, B.C., with a start-up planned by 2024. The 10 producers see a more profitable future selling their gas into overseas markets. Facing growing competition from U.S. shale gas producers in their traditional markets of eastern and mid-Atlantic U.S. and Canada, Western Canadian producers are suffering steep discounts relative to U.S. benchmark natural gas prices. Alberta’s AECO hub spot-market prices have been trading more than $1 per thousand cubic feet less than U.S. prices in February — about a one-third discount. At that discount, the markdown could cost Canadian producers almost $6 billion (Canadian) in lost revenue for a full year, Advantage Oil and Gas CEO Andy Mah told the Financial Post in December. Advantage is one of the companies that have joined forces to try putting together a second large-volume LNG project on the West Coast. The consortium hopes to have a project operating by 2026, though that would require permitting, assembling investors and customers and financing and then making a final investment decision in the next couple of years. The companies are predominantly players in the Montney shale in northeastern British Columbia and northwestern Alberta. Canada’s National Energy Board estimates the Montney’s potential reserves at 449 trillion cubic feet of marketable gas and 14.5 billion barrels of natural gas liquids. The players are looking at “controlling their own destiny” rather than relying on super majors like Shell and Chevron to build export projects, said Cameron Gingrich, director of gas services at Solomon Associates, a global energy consulting firm with offices in Calgary. “It’s great that it’s finally getting some traction,” Gingrich told the National Post. “The thing about energy (projects) is they are very large projects that require a lot of capital investment and infrastructure,” said Alan Boras, director of communications and stakeholder relations for Calgary-based Seven Generations Energy, a member of the consortium. “If you think about an LNG project, you need to have reserves in sizable amounts. You need transportation to a port and you need a liquefaction plant. And you need tankers and you need buyers,” Boras was quoted in the Financial Post on Feb. 20. “All of those pieces are very large and it takes a lot of coordination to bring them together.” The companies banding together to get their gas to market is similar to an initiative that started in the late 1980s and succeeded in building one of the longest and most expensive gas pipelines ever constructed at that time. The Alliance Pipeline went into service in 2000: 1,875 miles of 36-inch-diameter steel pipe from northeastern British Columbia straight to a connection point and a new gas liquids processing plant about 50 miles southwest of Chicago. The motivation then, as it is now, was money; the producers wanted better prices for their gas. They were frustrated that inadequate pipeline takeaway capacity forced the companies to compete with one another by dropping their price. “They believed the price they were getting for their gas at the wellhead was too low,” according to a 2011 report by the federal coordinator’s office for Alaska natural gas pipeline projects. “There wasn’t enough pipeline capacity to move the plentiful and growing production of Western Canada to higher-priced U.S. markets. They were stuck too often with the low prices of the glutted local market.” In 1992, two industry friends — a producer and a marketer — were talking in a Calgary pub, bemoaning the low prices caused by a lack of pipelines to U.S. markets. The marketer sketched out the pipeline route on a bar napkin. By 1995, there were 22 gas producers and marketers on board to take matters into their own pipeline. In spring 1998, a syndicate of 42 international banks agreed to lend money for construction. By the time Alliance started service in 2000, the ownership roster was down five companies, all of them in the pipeline business. “The gas producers that founded Alliance got out of the pipeline ownership business quickly, most selling their shares before construction started and retreating to their comfort zones,” the history report said. Alliance is now jointly owned by two Calgary-based pipeline companies: Enbridge and Pembina Pipeline. Its capacity of 1.6 billion cubic feet per day is fully subscribed by shippers. “That’s been very good for Canada,” Boras said of Alliance. His company, Seven Generations, is a shipper on the line. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC criticizes Mat-Su Borough for ‘factual and legal errors’

The state’s gas pipeline development corporation and the Matanuska-Susitna Borough continue debating the worthiness of the borough’s Port MacKenzie property for the proposed Alaska LNG Project, as the state’s latest filing with federal regulators accuses the borough of “factual and legal errors.” The borough’s most recent comments to the Federal Energy Regulatory Commission “simply nit-pick (erroneously, in many instances) around the edges,” the Alaska Gasline Development Corp. told federal regulators Feb. 13. The corporation has not strayed from its choice of Nikiski on Cook Inlet as the best site for the gas liquefaction plant and export terminal. The borough, however, is contesting the state-led project’s evaluation of Port MacKenzie at the entrance to Knik Arm, across from Anchorage, about 65 air miles northeast of Nikiski. Both AGDC and the borough are adding to the file at FERC, which is preparing the project’s environmental impact statement, or EIS. FERC is scheduled to release the draft EIS by the end of February, followed by public hearings and comments, along with comments from federal and state and municipal agencies, and then, if the environmental review stays on schedule, a final EIS in November. Federal law requires than an impact statement review economically feasible alternatives to a project developer’s preferred options to determine the “least environmentally damaging practicable alternative.” The Matanuska-Susitna Borough argues that AGDC has failed to give Port MacKenzie fair consideration. The proposed $43 billion project would move Alaska North Slope gas to a liquefaction plant for export. AGDC denies the borough’s assertion that its analysis is flawed. But even if the review of Port MacKenzie was inadequate, AGDC said in its Feb. 13 filing with FERC, “(the) Matanuska-Susitna Borough’s comments do not change the unavoidable conclusion that the significant environmental impacts and safety concerns associated with siting the Alaska LNG liquefaction facilities at Port MacKenzie render it an inferior alternative to AGDC’s proposed site at Nikiski.” Because of the considerable environmental issues of building at Port MacKenzie, AGDC told FERC, the regulators do not need to address every issue raised by the borough “to fulfill its obligations under the National Environmental Policy Act to examine alternatives.” The state corporation and the Matanuska-Susitna Borough, along with the Kenai Peninsula Borough in its defense of Nikiski, have all contracted with Washington, D.C., law firms that specialize in work at FERC. Neither AGDC, the Matanuska-Susitna Borough or FERC have raised any questions or added anything to the docket regarding the 7.0 earthquake that shook the Anchorage area on Nov. 30 and was centered about five miles north of Port MacKenzie. Separate from the debate over the borough property, AGDC still owes a substantial amount of data to FERC, along with answers to more than 100 detailed questions about engineering and safety systems for the LNG plant, the gas treatment plant at Prudhoe Bay and the 807-mile pipeline from the North Slope to Nikiski. The corporation has said it will be September before it provides all the answers. Federal regulators have not said if that timeline for the missing data will affect the EIS schedule. In its Feb. 13 filing, AGDC responded to the borough’s 145-page, Jan. 25 filing that listed why the municipal government believes the state project team shortchanged Port MacKenzie in its site consideration. The borough contends the state development team did not accurately map out and consider the “optimum site” proposed by the borough. “As a result,” the borough said, AGDC’s efforts “misidentify and overlook key features of Port MacKenzie.” The borough further contends, “Rather than assessing Port MacKenzie as a unique site, AGDC begins from the assumption that the same facilities specifically designed for Nikiski will be built at Port MacKenzie. This assumption is irrational and leads AGDC to overestimate the amount of construction necessary to site a liquefaction facility at Port MacKenzie.” Not true, AGDC told FERC on Feb. 13. Regardless of which exact site is mapped out at Port MacKenzie, there are multiple problems with building the LNG plant and marine terminal at the property. The state corporation restated its concerns over conflicts with more frequent vessel traffic in the navigation channel to Port MacKenzie (across from the Port of Alaska) than in Nikiski; more significant ice conditions than at Nikiski; restrictions on when construction delivery ships and LNG carriers could cross the Knik Arm Shoal; and the impacts and restrictions of building in the critical habitat area for endangered beluga whales. AGDC also took issue Feb. 13 with the borough’s analysis of berthing facilities, water depth, dredging and other issues at Port MacKenzie. And the state team told FERC that the existing haul road from the dock to the property is too steep to transport large modules to the upland construction site, regardless what the borough contends. “In short, the Matanuska-Susitna Borough’s attempt to substitute its erroneous analysis for AGDC’s rigorous analysis and conclusions as to berthing and other design elements needed to construct and operate the project facilities reliably and safely should be rejected,” the corporation’s lawyer wrote to FERC. The borough a year ago stepped up its complaints to federal regulators over AGDC’s analysis of Port MacKenzie as a potential site for the development. The borough charged that AGDC may have violated the National Environmental Policy Act and federal Clean Water Act by “improperly and intentionally excluding” Port MacKenzie as a “reasonable alternative” for the proposed LNG plant. The borough has long promoted its money-losing port for the LNG project and other industrial developments, with little success. Nikiski was selected as the preferred alternative from more than two dozen options in October 2013, when North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips were leading the project. The state took over the venture in late 2016 after the companies declined to proceed with spending significant sums of money on additional engineering, design and permit applications. The state applied to FERC in April 2017. “FERC has sufficient information to fulfill its responsibilities … to analyze Port MacKenzie,” the state corporation said Feb. 13. The borough’s suggestion that AGDC “should develop a site-specific design for Port MacKenzie … is unreasonable and not required for the commission to comply” with federal law, the corporation said. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Zero to 68: US set to join top 3 LNG exporters

It’s going to be a big growth year for U.S. exports of liquefied natural gas, with three more terminals set to start operations in 2019 and developers already this month committing to a $10 billion investment for another project. Plus, final investment decisions are anticipated on two or three more gas export terminals. “North America is set to lead an expected record year for LNG project sanctions,” Alex Munton, principal analyst for Americas LNG at energy consultancy Wood Mackenzie, said in a prepared statement. “The first half of 2019 will be an especially busy one for the United States.” By early 2020, U.S. LNG export capacity could total more than 68 million tonnes per year, or about 15 percent of global capacity, and boosting the United States to third place behind Qatar and Australia. That’s up from zero exports just three years ago, before Cheniere Energy in February 2016 shipped the first cargo from its terminal in Sabine Pass, La. At full production in early 2020, the six U.S. liquefaction plants could consume almost 10 percent of the country’s 2018 marketed gas production. Though U.S. LNG exports started 50 years ago in Alaska, the tremendous increase in shale gas production in the Lower 48 states over the past decade burst into the global LNG market by making seemingly unlimited supplies available at affordable prices. The small LNG plant in Nikiski — built by Phillips Petroleum and Marathon Oil in the 1960s — was the only North American export terminal in operation when it loaded its last cargo in 2015 and shut down amid strong global competition. ConocoPhillips sold the mothballed plant in 2018. Marathon now owns it and has not announced specific plans for the property. Most of the new U.S. LNG plants have been built on the Gulf Coast, with two East Coast exceptions: Cove Point, on Maryland’s Chesapeake Bay; and Elba Island, on the Savannah River in front of the Georgia city of the same name. Of the six export terminals that will be in operation by the end of this year, five were cost-efficient additions of liquefaction units, called trains, to existing but unused or significantly underused LNG import terminals. Originally an import terminal from the 1970s, Cove Point LNG, owned and operated by Virginia-based Dominion Energy, shipped its first export cargo in April 2018. Its liquefaction capacity is 5.25 million tonnes per year. Kinder Morgan’s Elba Island terminal is unique in that it will operate 10 small-scale, modular trains with a total capacity of 2.5 million tonnes per year. Federal regulators on Feb. 1 gave permission to start commissioning the first train. Kinder Morgan expects all 10 units to be in production by the end of the year. Elba Island started as a receiving terminal in 1978. Opened in 2008 as an import terminal, Cheniere’s Sabine Pass project in Louisiana was the first to add liquefaction and LNG exports. It now has four trains in operation, with a fifth scheduled to start production in the second quarter of 2019, bringing its total capacity to 22.5 million tonnes. In addition, Cheniere has signed up Bechtel as the engineering, procurement and construction contractor for a sixth train, with the final investment decision predicted in the first half of 2019. Cheniere’s second Gulf Coast export terminal — Corpus Christi, Texas — is the only one of the six that did not build on an unused import operation. Its first train started service in November 2018; commissioning is underway on a second train; and a third train is scheduled to enter service in 2021 — each at 4.5 million tonnes per year. Meanwhile, Cheniere is looking at adding up to seven mid-scale trains at Corpus Christi, boosting total output capacity to 23 million tonnes. Freeport LNG, owned by private investors, has three trains under construction at its Texas terminal, each at 5 million tonnes per year and scheduled to come online late 2019 through early 2020. A fourth liquefaction train is waiting on regulatory approval. San Diego-based Sempra Energy and its partners plan to start production by April from the first train at Cameron LNG in Hackberry, La. The next two trains are set to come online before the end of the year, bringing total capacity to 13.9 million tonnes per year. Sempra also is looking at building a new LNG export facility in Port Arthur, Texas, targeting late 2019 or early 2020 for an investment decision on the 11-million-tonne-per-year project. The Federal Energy Regulatory Commission issued its final environmental impact statement in late January. The newest entrant to the export trade, Golden Pass LNG, was given the go-ahead for construction Feb. 5 by its partners Qatar Petroleum (70 percent) and ExxonMobil (30 percent). The $10 billion project in Texas, across the river from Cheniere’s Sabine Pass operation, is planned for 15 million tonnes per year with start-up by 2024 at the site of an unused import terminal. “On a dollars-per-tonne basis, it’s still one of the lowest-cost opportunities for new large-scale liquefaction capacity anywhere in the world,” Wood MacKenzie’s Munton said of Golden Pass. It’s the only one of the bunch being developed by oil-and-gas producers. Virginia-based Venture Global is awaiting FERC approval — perhaps at the commission’s Feb. 21 meeting — for its Calcasieu Pass LNG in southwestern Louisiana. The company has hired Kiewit to build the 10-million-tonne-per-year, $8.5 billion project. Venture Global expects to make a final investment decision in the first half of 2019 and has signed 20-year offtake agreements with Shell, BP, Italy’s Edison, Portugal’s Galp, Spain’s Repsol and Poland’s PGNiG. Another new entrant, Houston-based Tellurian, also is targeting the first half of 2019 for an investment decision on its $16-billion Driftwood LNG project. FERC issued its final environmental impact statement in January, though the developer has yet to announce any binding offtake deals for Driftwood. Tellurian is planning as much as 27.6 million tonnes per year capacity at the plant on the west bank of the Calcasieu River, south of Lake Charles, La. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Alaska LNG still on schedule for February EIS draft

The Alaska Gasline Development Corp. has added to the list of information it will not submit to federal regulators until this summer, but there has been no indication that the absence of the mostly technical engineering data will delay the scheduled February release of the draft federal environmental impact statement for the proposed Alaska LNG project. The Federal Energy Regulatory Commission has not publicly amended its schedule for the project’s draft EIS, though it has not designated a specific date in February. However, as of Feb. 11, a federal website that tracks pending regulatory work shows Feb. 28 as the “current target date” for the Alaska LNG draft. The tracking website, named FAST-41 for Section 41 of the 2015 law that created the multi-agency effort, is not legally binding on agencies. Federal regulators have been working to prepare the draft EIS since the state in April 2017 submitted its application for the project to move North Slope gas down an 807-mile pipeline to a liquefaction plant and export terminal in Nikiski, on the eastern shore of Cook Inlet. The state-led project team on Feb. 4 responded to FERC’s most recent request, answering a Jan. 15 letter for further detailed information on fire safety, spill containment safeguards and hazard mitigation designs at the North Slope gas treatment plant, the liquefaction plant and liquefied natural gas storage tanks in Nikiski. Addressing the remaining 81 requests for information, AGDC said it would provide the answers in four batches, starting in April and running to July 26. That information is in addition to 76 technical engineering data requests FERC raised in December, which the state team said it will answer in March, May and June. Those requests cover specific engineering, safety and emergency system designs at the gas treatment plant and LNG plant. AGDC will need to complete all the work with a diminishing pot of money. The corporation had expected to end the state fiscal year on June 30 with $15 million to carry it through the entire EIS process — FERC is scheduled to issue its final EIS in November — but Alaska’s budget director said in January the governor wants to take back $5 million from AGDC to help balance state spending. The corporation was expecting to spend an average $3.6 million per month during the first six months of 2019, drawing down its account balance to $15 million by June 30 to carry it through to the end of the calendar year. Spending likely will slow down, however, as the corporation fulfills FERC’s information requests. Among the answers and data AGDC has said it will provide to FERC by March 1: • More information about where the pipeline crosses active earthquake faults, including the hazards and estimated vertical and horizontal offsets of active faults. • A more detailed route map of the 62-mile pipeline from the Point Thomson field to Prudhoe Bay and the pipeline from Prudhoe Bay to Nikiski, showing all seismic hazards within 5 miles of the pipeline and “areas requiring special treatment of permafrost” within a quarter-mile. An example of the technical nature of FERC’s questions is the request for additional information on the design of the piping on top of the LNG storage tanks in Nikiski and surrounding impoundment area for any tank spills, and more details on piping diagrams at the gas treatment plant at Prudhoe Bay. AGDC said it would submit those drawings in late June. AGDC also owes federal regulators more information about the project’s 27-mile underwater pipeline crossing of Cook Inlet. AGDC on Dec. 7 told FERC it would need until September to fully respond to more than a dozen of the questions about the Cook Inlet crossing, including: • Will tidal flow and other currents move debris and boulders across the pipeline? And how much movement is expected, particularly during tidal currents? • Does AGDC plan to use any additional weights or supports along the pipeline after construction to stabilize the line against tidal currents? • Will concrete mats be used to protect the pipeline after it is set on the seafloor? • Is there any site-specific geotechnical data to confirm that the bottom soil is firm enough so that the weighted 42-inch-diameter pipe “will not continue to sink,” placing high-strain loads on the pipe welds during construction and operations? The state project team proposes to bury the pipe near shore as it enters the water on the west side of Cook Inlet near Beluga, lay the concrete-coated pipe on the seafloor across the inlet, then bury it as it reaches shore on the east side for the last 14 pipeline miles to the LNG plant. It’s not unusual for FERC to continue asking for information as it works through its review — particularly engineering design questions about an LNG plant. Regulators can add information between the draft and final EIS. After North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips pulled out of the project in late 2016, citing market conditions, the state has covered 100 percent of the development costs, including regulatory approval at FERC. A legislative audit presented to lawmakers in January showed that since AGDC was established in 2010, the Legislature has appropriated $480 million for the corporation’s work on the Alaska LNG export project and the in-state-distribution-only Alaska Stand Alone Pipeline, a $10 billion project its supporters have promoted as a backup if the larger development fails to go ahead. The in-state line is closer to completing the regulatory process than the LNG project but it, too, lacks any state funding to proceed past permitting. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Mat-Su Borough keeps up fight over LNG site

The Matanuska-Susitna Borough on Jan. 25 added 145 pages to its ongoing argument that Port MacKenzie would be a better location than Nikiski for the Alaska LNG project’s natural gas liquefaction plant and marine terminal. The borough, which owns the property across Knik Arm from Anchorage, added additional comments, maps, charts and photos to the docket at the Federal Energy Regulatory Commission, which is scheduled to release its draft environmental review of the Alaska LNG proposal sometime in February. The borough has long been critical of the site selection, Port MacKenzie alternative analysis and answers provided by the Alaska Gasline Development Corp., the state-funded corporation that is leading the proposed $43 billion project. “Unfortunately, the approach to analyzing the alternatives employed by AGDC in its responses confuses, rather than clarifies, the differences between the alternatives of Nikiski and Port MacKenzie, and its responses could result in an inadequate analysis of alternatives to AGDC’s proposed action,” the borough said in its latest filing with FERC. The borough’s Jan. 25 filing was in response to the state’s answers turned in at FERC on Nov. 20 after federal regulators had asked AGDC for further analysis of Port MacKenzie. The project’s environmental impact statement is required to review any economically feasible alternatives to determine the “least environmentally damaging practicable alternative.” The borough a year ago complained to federal regulators that AGDC may have violated the National Environmental Policy Act and federal Clean Water Act by “improperly and intentionally excluding” Port MacKenzie as a “reasonable alternative” for the proposed LNG plant. Asserting a list of geographical advantages, the borough has noted that Port MacKenzie offers more developable land and is about 50 pipeline miles closer to Prudhoe Bay than Nikiski, which is farther south on the Kenai Peninsula. Building at the port also would eliminate the need for 27 miles of underwater pipe across Cook Inlet to Nikiski. The borough has long promoted its money-losing port for the LNG project and other industrial developments, with little success. Nikiski emerged as the preferred alternative among more than two dozen options in October 2013, when North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips were leading the venture. The state took 100 percent control of the project in late 2016 after the companies declined to proceed with spending hundreds of millions of dollars on additional engineering, design and permit applications. The state applied to FERC in April 2017. The Matanuska-Susitna Borough, the Kenai Peninsula Borough (defending its community, Nikiski), and the City of Valdez (also promoting its community as the best location for the LNG plant), have all signed on as intervenors in the project’s application at FERC. Intervenor status does not bestow any special privileges or additional consideration in preparation of the EIS. The only significant difference between an intervenor and anyone else submitting comments to the docket is that only an intervenor can challenge a FERC decision in court. The Mat-Su and Kenai boroughs and AGDC are each paying different Washington, D.C., law firms with experience in FERC issues. If FERC stays with its self-imposed timeline of the draft EIS in February — no specific date set — it is scheduled to release its final EIS in November 2019, assuming it encounters no roadblocks or delays during the public comment period for the draft and assuming AGDC submits all the information requested by federal regulators. The state team has said it will be September before it can answer all of FERC’s questions about the Cook Inlet pipeline crossing. Regardless whether the project can stay on schedule with its FERC review, AGDC lacks funding to go past the past EIS. The new administration of Alaska Gov. Michael J. Dunleavy has said it is time “to re-engage the Legislature” and talk with the North Slope producers. This is a “great opportunity to pause and see where we’re at,” Revenue Commissioner Bruce Tangeman said at the Alaska Support Industry Alliance annual Meet Alaska conference in Anchorage on Jan. 18. Absent any partners, the state has been paying 100 percent of the costs since the producers left two years ago. Among its objections to AGDC’s analysis, the Matanuska-Susitna Borough contends that the state development team did not accurately map out and consider the “optimum site” proposed by the borough. “As a result,” the borough said AGDC’s efforts “misidentify and overlook key features of Port MacKenzie.” The borough further contends in its Jan. 25 filing, that “Rather than assessing Port MacKenzie as a unique site, AGDC begins from the assumption that the same facilities specifically designed for Nikiski will be built at Port MacKenzie. This assumption is irrational and leads AGDC to overestimate the amount of construction necessary to site a liquefaction facility at Port MacKenzie. … Simply transposing plans developed for Nikiski onto a map of Port MacKenzie, as AGDC has done, will not fulfill FERC’s duty to analyze potential alternative sites.” “It appears that AGDC is justifying its preference for Nikiski over Port MacKenzie not based on technical feasibility and environmental impacts, but rather simply because AGDC has already completed design work for Nikiski but not Port MacKenzie,” the borough filing states. “While this need for additional design work might explain why AGDC prefers to site the facility at Nikiski, it is not relevant to FERC’s National Environmental Policy Act analysis and is not responsive to FERC’s data request regarding the specific differences in environmental impacts for each site.” The North Slope producers, before they left the project and AGDC since then, have consistently pointed to problems with the Port MacKenzie location, including stronger tidal currents and tidal ranges, more winter ice hampering operations, a narrower channel for vessel traffic, conflicts with other potential users at the port, and the significant regulatory problems of operating in critical habitat waters of the endangered Beluga whales. In a separate issue for the EIS, the state project team on Jan. 23 submitted hundreds of pages of data, maps, charts and tables to FERC, responding to questions from the U.S. Army Corps of Engineers about the project’s effects on wetlands. Among the data submitted to the Army Corps and FERC: • AGDC reported the project would permanently impact 10,412 acres of wetlands during construction, with an additional 8,731 acres temporarily affected during the work. About 3,500 acres would be impacted during project operations. The acreage includes the 62-mile pipeline from the Port Thomson gas field to the gas treatment plant at Prudhoe Bay, the gas plant, the 807-mile pipeline from Prudhoe to Nikiski, and the LNG facility and marine terminal. The Jan. 23 filing includes a detailed list of the wetlands locations. • Additional information on AGDC’s plans for digging the trench and laying the pipe in wetlands, including protection and restoration plans. • AGDC expects to provide a draft wetlands mitigation plan in the second quarter of 2019. • Reiterating its plans not to remove gravel fill placed in wetlands, the AGDC filing said the project “would not actively restore sites where gravel fill is placed, but rather would leave it in place to encourage thermal and physical stabilization. As stated previously, it is not practicable for AGDC to restore wetlands where gravel fill is placed.” • For areas not covered in gravel fill, “while some impacted areas would be converted to upland and revegetated, others would ultimately return to wetlands,” AGDC said. “The goal of restoration for the Alaska LNG project is to establish a right of way that is stable, both physically and thermally, and that maintains some of the ecosystem functions that were present prior to construction, where feasible.” • Additional details on dredging 800,000 cubic yards from Cook Inlet to accommodate vessel traffic at the barge landing and freight dock that would be used for construction in Nikiski. The dredged material would be dumped at approved sites in deeper water. • Clarification that while AGDC proposes pipe-coating and double-jointing pipeline yards in Fairbanks and Wasilla, it has dropped plans for a similar yard in Seward. • AGDC reported it does not have plans at this time for any additional gas offtake points along the pipeline for local distribution other than the previously disclosed offtake points in Fairbanks, the Matanuska-Susitna Borough and Nikiski. Though AGDC has long touted the availability of gas for local use from at least five offtake points, it has not publicly identified any additional economically feasible connection points. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC updates schedule for engineering data requests

The Alaska Gasline Development Corp. has told federal regulators it will be late June before the state-led project team can provide all the detailed engineering data requested in December for the proposed Alaska LNG Project’s gas treatment plant at Prudhoe Bay and gas liquefaction plant in Nikiski. AGDC on Jan. 15 responded to 76 technical engineering data requests submitted Dec. 26 by the Federal Energy Regulatory Commission, which is preparing the project’s environmental impact statement, or EIS. The state corporation answered five of the requests. It said it would provide responses to 43 of the questions by March 1, March 22, May 3 and the last six by June 28. However, that is not the end of the data requests. The same day as the state filed its response with FERC, the commission’s Office of Energy Projects issued an additional 20 pages of detailed engineering questions for AGDC covering the gas treatment plant, the liquefaction plant and LNG storage tanks, and hazard mitigation designs. The state has 20 days to answer the questions or provide a schedule for when it will. In addition to the December and January questions — which focused mostly on plant design, safety and emergency systems — AGDC still owes federal regulators more information about the project’s 27-mile underwater pipeline crossing of Cook Inlet. AGDC on Dec. 7, 2018, told FERC it would need until September 2019 to fully respond to more than a dozen of the questions about the Cook Inlet crossing. The state project team proposes to bury the 42-inch-diameter pipe near shore as it enters the water on the west side of Cook Inlet near Beluga, lay the concrete-coated pipe directly on the seafloor across the inlet, then again bury it as it reaches shore on the east side for the last 14 pipeline miles to the gas liquefaction plant site. In August 2018, FERC reported it would issue its draft EIS for the state-led $43 billion North Slope natural gas project this February. FERC did not provide a specific date for the release, nor did it address the schedule in its latest requests of AGDC for more information. It’s not unusual for the regulatory agency to continue asking for additional information as it prepares an EIS — particularly engineering design questions about an LNG plant — and FERC can add information to its review between the draft and final EIS. The February release date and scheduled final EIS in November 2019, however, are dependent on regulators having enough information to complete the review. FERC would issue a public notice if it makes any change in the schedule. Meanwhile, it will be tight for AGDC to cover its spending to the final EIS in November unless it receives additional state funding from the Legislature. The project team reported at the Jan. 10 AGDC board meeting that the corporation will end the current fiscal year on June 30 with just about $15 million available from past legislative appropriations — after spending an average $3.6 million per month for the first six months of calendar 2019. AGDC continues working toward making a global pitch to attract private investors for the project, according to a staff presentation at the board meeting. Selling off a stake in the project to private investors could be an alternative to additional state funding at this stage in the venture. A majority of the board has changed under the administration of Gov. Michael Dunleavy, who took office Dec. 3, and the new board dismissed AGDC President Keith Meyer on Jan. 10. He was replaced by Joe Dubler, who worked in commercial and finance roles at the corporation from 2010 to 2016. Dubler left AGDC about the same time that North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips declined to push ahead with project development and permitting, with the state taking over 100 percent of ownership and development costs. The state filed the project application with FERC in April 2017. Among the answers and data AGDC said it would provide to FERC by March 1: • More information about where the pipeline crosses active earthquake faults, including the hazards and estimated vertical and horizontal offsets of active faults. • A more detailed route map of the 62-mile pipeline from the Point Thomson field to Prudhoe Bay and the 807-mile pipeline from Prudhoe Bay to Nikiski, showing all volcanic and seismic hazards within 5 miles of the pipeline; all oil and gas wells and mines within a half-mile of the route; and “areas requiring special treatment of permafrost” within a quarter-mile. • A flare-sizing analysis in the event of a complete safety shutdown of the LNG plant and resulting gas release to relieve pressure on the piping and equipment. • Information on the type of piles (such as steel pipe or precast concrete) that would be used for the foundations at the LNG plant and marine terminal. • Whether AGDC plans to reroute an active 20-inch-diameter gas pipeline, owned by Hilcorp, that runs parallel to the Kenai Spur Highway at the proposed LNG plant site. If the project does not plan to reroute the pipeline, FERC wants to know how AGDC plans to protect the line during construction. On the list for answers by May 3: • More information on how the LNG plant, and its emergency response equipment, would be protected against winds in excess of 110 miles per hour. Federal regulations require such high-wind contingency planning. • How AGDC plans to protect sensitive equipment at the LNG plant from volcanic ash in the event of an eruption. • Additional details on AGDC’s plans to relocate part of the Kenai Spur Highway around the LNG plant site, specifically emergency access roads to the plant, and speed limits and turning lanes built into the new stretch of highway. • More information on firefighting water-coverage areas at the LNG plant and marine terminal, specifically the reach of water sprays. “FERC staff review identified several areas that were lacking adequate firewater coverage,” the regulators told AGDC. On the list for June 28: • Additional information on the design of the piping on top of the LNG storage tanks and the impoundment area for any tank spills. • More details on piping diagrams at the gas treatment plant at Prudhoe Bay. Among the data requests in FERC’s Jan. 15 letter to the state team: • Provide a table of all piping and ships that would be used in the project that could produce spills of at least 500 gallons of combustible, flammable or toxic liquids, including details on spill-impoundment areas. • More information on the risks and safety plans for a breach or failure of high-pressure carbon dioxide pipelines. • Identify fire protection coverage for all flammable and combustible gas and liquids that would be present at the gas treatment plant at Prudhoe Bay. • Provide more details on how the project design would protect against a spill from the LNG loading arm at the dock in Nikiski. • And provide an analysis of the impacts should the LNG pipe on the trestle to the loading dock fail and spill over the beach and waterway. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Texas, ND grapple with gas flaring

Though Alaska has strong laws against venting or burning off natural gas — flaring — except for safety and emergencies, the rules are far less stringent in the nation’s top two oil-producing regions. Blaming a lack of pipelines and processing facilities, oil and gas producers in North Dakota’s Bakken shale and the Permian Basin in Texas and New Mexico this fall flared more than 900 million cubic feet of gas per day. At that rate over a full year, it would be enough to fill almost 100 good-sized liquefied natural gas carriers. Overall, U.S. producers vented or flared 235 billion cubic feet, or bcf, of gas in 2017, according to the U.S. Energy Information Administration, or EIA. Alaska was responsible for 7.6 bcf, with Texas at 101 bcf and North Dakota second at 88.5 bcf. The Texas and North Dakota numbers are up almost 25 percent from 2016. Full-year totals for 2018 are not available yet. It’s gotten so bad that the Dallas Morning News, in a Jan. 10 editorial, commented: “Wasting this resource should depress all of us, because it has great value.” The gas could be used as heating fuel, to generate electricity, make petrochemicals or plastics. Instead, “discarding it is wasteful and potentially harmful to the environment,” the editorial said. Whether vented or burned, it adds to greenhouse-gas emissions. But without enough processing plants and pipelines to move the gas to market, it can be a worthless byproduct. Or worse than worthless when producers have to pay another company to take the gas. Gas prices in parts of the Permian Basin hovered near zero in November, while some trades cost producers a negative 25 cents per million Btu, according to price-reporting agency S&P Global Platts, which said it was the first time on record that gas traded for less than zero at the Waha hub in West Texas. The zero pricing could continue in the Permian this year, as more oil pipelines get built and companies ramping up their oil production get stuck with more associated gas. The EIA estimated December gas output would top 12 billion cubic feet a day in the Permian, up about 34 percent from a year earlier. Flaring reached record highs in the Permian in the third quarter of 2018, when companies lit up an average 407 million cubic feet per day, said Rystad Energy, an energy consulting firm. The resulting greenhouse gas emissions are equivalent to the daily exhaust of about 2.7 million cars, according to estimates from the World Bank and U.S. Environmental Protection Agency. In October, flaring in North Dakota averaged 527 million cubic feet per day — enough to heat 4.25 million average U.S. homes. That’s enough to have met the natural gas needs for all of North and South Dakota, including industrial and commercial demand, according to a report in the North Dakota Bismarck Tribune. The flaring represented more than 20 percent of October’s North Dakota gas production of 2.56 billion cubic feet per day. As oil production reached a record 1.39 million barrels per day, the additional associated gas overwhelmed processing and pipeline capacity — and ended up in smoke. Though 2018 was a bad year for flaring, it was still far short of North Dakota’s record in 2014, when producers burned off almost 130 bcf of gas; that’s more than any state ever in the EIA records that go back to 1967. It was a measly 1 bcf in 1982, a quarter-century before the Bakken shale boom. Industry is hopeful North Dakota will make significant progress on gas capture in 2019. Several gas processing plants and pipelines were announced or under construction in 2018, totaling more than $3 billion in investment, said Justin Kringstad, director of the North Dakota Pipeline Authority. But as oil and gas production continues to grow, more investment will be needed to move gas to market. “We’re probably going to need at least another $10 billion or more,” said Ron Ness, president of the North Dakota Petroleum Council. “Our productivity has just outpaced expectations.” Alaska statute prohibits “the waste of oil and gas” in production. State regulation, enforced by the Alaska Oil and Gas Conservation Commission, defines waste as “gas released, burned, or permitted to escape into the air,” with the exclusion of necessary emergency and operations-related emissions. North Dakota’s current gas-capture rules, adopted in 2014 and revised in April 2018, require operators to capture 88 percent of Bakken gas. That’s up from an 85 percent requirement earlier in the year and 76 percent in 2014. The North Dakota Industrial Commission, with much the same job as Alaska’s AOGCC, can require operators to restrict oil production if they fall below the gas-capture percentage, but the penalty is rarely imposed, the Bismarck Tribune reported in October. In August 2018, the industry captured less than 85 percent of its gas production for a fourth month in a row. For at least three of those months, the state declined to restrict production. North Dakota allows producers to flare as much gas as they want for the first year of a well’s production. After that, a producer may obtain an exemption on flaring limits if it can show “that connection of the well to a natural gas gathering line is economically infeasible at the time of the application or in the foreseeable future or that a market for the gas is not available and that equipping the well with an electrical generator to produce electricity from gas or employing a collection system … is economically infeasible.” The rules in Texas are more stringent than in North Dakota, and the increase in flared volumes is a result of the boom in Permian shale oil production, which grew from 1 million barrels per day in 2010 to almost 3.8 million by the end of 2018. Texas allows producers to seek a 45-day permit for flaring of associated gas, with extensions allowed to 180 days. Anything longer requires a full hearing by the Texas Railroad Commission, which governs oil and gas production. State law requires a cost-benefit analysis for a permanent exemption. The 45-day permits are easy to get. As of the end of November, state regulators hadn’t denied a single permit request in more than five years, the Wall Street Journal reported in December. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Mozambique aims to take spot among global LNG leaders

Mozambique’s first liquefied natural gas export project is under construction, two much larger developments are targeting final investment decisions in 2019, and the impoverished African nation of 30 million people could go from zero to the sixth-largest LNG producer in the world by the mid-2020s. The two mega-projects — one led by ExxonMobil and Eni and the other led by Anadarko — have a combined development cost of $55 billion and would bring 28 million tonnes of annual liquefaction capacity on stream by 2025, Paul Eardley-Taylor, head of oil and gas for Southern Africa at Johannesburg-based Standard Bank, told a London audience Nov. 22. Those two ventures, plus the smaller floating LNG project under construction and scheduled to enter service in 2022, also led by Italy’s Eni, would total almost 32 million tonnes annual capacity. That would put Mozambique just behind 35-year LNG exporter Malaysia and world leaders Qatar, Australia, the United States and Russia. Eardley-Taylor gave the keynote presentation at the Africa Petroleum Club’s annual fundraiser dinner for wildlife and conservation projects: “Mozambique, Gas Supplier to the World?” Global LNG trade is predicted to grow twice as fast as gas demand overall, the banker said, showing a chart of 12 different LNG demand forecasts stretching out as far as 2040. Starting with actual demand in 2017 of almost 300 million tonnes per year, the forecast average approaches 500 million tonnes by 2030. Mozambique, with offshore gas discoveries of 150 trillion to 200 trillion cubic feet since 2010, is well positioned to serve the growing Asian market, Eardley-Taylor said. The expectations for Mozambique go beyond start-up of the two onshore LNG plants, with the bank forecasting that expansions are likely. “We expect four or five additional onshore (liquefaction) trains could be operational by 2029-2030.” The first project to come online will be Coral South, which Standard Bank put at $10 billion for the all-in cost. Construction of the floating liquefaction and storage unit started in a South Korea shipyard after Eni, the project operator, and its partners made the final investment decision in 2017. BP has a 20-year contract to take 100 percent of the output from the 3.4-million-tonne-per-year project. Of the onshore plants, Anadarko is the lead for the Mozambique LNG project, at 12.88 million tonnes per year, with the company committing to make an investment decision in the first half of 2019. The bank estimated the all-in development cost at $25 billion. Anadarko is working to sign up enough LNG customers to sell its decision to project-finance bankers. As of mid-November, the company had announced sales to gas suppliers and utilities in Japan, Thailand, France and the U.K., totaling more than half the plant’s output, though not all the contracts have been finalized. Talks also are underway on LNG sales to Shell, Total and China National Offshore Oil Corp., the Natural Gas Daily reported Dec. 4. The project already has started resettling residents to prepare the site for construction, according to the bank’s presentation in London. India’s state-run Bharat Petroleum Corp. is a partner in the Anadarko project and will invest as much as $800 million equity for its 10 percent stake — the company’s largest investment in an upstream project overseas — Indian news media reported in October. Other partners with Anadarko include companies from Japan, India and Thailand. At an initial capacity of 15.2 million tonnes and a $30 billion all-in price tag, the ExxonMobil/Eni-led Rovuma LNG project looks to take bids in the first quarter of 2019 for engineering, procurement and construction, the bank said. ExxonMobil’s country manager in Mozambique has publicly confirmed that the company expects to make a final investment decision mid-2019. Partners in the development also include China National Petroleum Corp., Korea Gas and Galp Energia of Portugal. By selling some of the plant’s output to their own affiliates, the partners could speed up financing for the development, the bank said. “We expect sufficient interest from affiliate buyers to launch the project and support the financing,” ExxonMobil spokesperson Julie King told Reuters in July. The company took over the lead role in the joint venture this summer for construction and operation of the LNG plant, while Eni will manage gas field development. To reduce production costs, ExxonMobil has decided to build the largest liquefaction trains in the world outside Qatar, at 7.6 million tonnes each. Mozambique’s National Hydrocarbons Co. is a partner in both onshore projects and will need to borrow $2 billion to finance its participation, according to news reports in October. The country’s minister of economy and finance said the government wants to issue a sovereign guarantee for the $2 billion loan and has put it into its draft 2019 state budget. However, the return of Mozambique to international capital markets will not be easy. Rating agencies classify Mozambique as in “selective default” because in 2013 and 2014 the government issued sovereign guarantees, also for about $2 billion, for loans taken out from European banks by three newly created security-related companies. All three companies are now effectively bankrupt, and the government has defaulted on the loan repayments, arguing that creditors must agree to restructure the loans. Mozambique reached an agreement with creditors to restructure some of the debt, including extending maturities and sharing future revenues from the LNG projects, the finance ministry said Nov. 6. Under the deal, creditors would receive 5 percent of Mozambique’s future revenues from the gas projects, with payments capped at $500 million. Mozambique is one of the world’s poorest countries, having suffered through a 15-year civil war that ended in 1992, according to Standard Bank. The country hopes that production of its offshore gas resources will provide increased supplies for domestic needs and spur development of fertilizer and petrochemical manufacturing plants along with construction of gas-fired power plants and pipelines to serve industry and households. South Africa’s Sasol has been producing gas in Mozambique since 2004, sending most of it by pipeline to power plants in South Africa. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

FERC denies state request for cooperating status in EIS

The law doesn’t allow the Alaska Department of Natural Resources to participate as a cooperating agency in the federal environmental impact statement for the state-led Alaska LNG project, U.S. regulators said. The department had promised not to share any information with the project developer, the Alaska Gasline Development Corp., but that wouldn’t solve the legal problem, said the Federal Energy Regulatory Commission. “Even with a firewall, both agencies would nevertheless be accountable to advancing the interests of the state of Alaska in getting the project approved,” Jim Martin, a branch chief at FERC’s Office of Energy Projects, said in a Dec. 14 letter to the Natural Resources commissioner’s office. The department in July asked if it could formally join the FERC-led team preparing the environmental impact statement for the state-led North Slope gas development. The federal regulator is scheduled to release its draft EIS for the project in February, assuming it receives all the information it has requested from the state corporation. “The state of Alaska cannot participate in the proceeding in the dual capacity of both applicant and cooperating agency,” FERC stated, adding that its rule “does not provide an exception for having off-the-record communications with one part of a state … while walling off another part of a state … The Office of General Counsel has informed us that such an arrangement could result in significant due-process issues.” And regardless if FERC’s rules accepted such a firewall or administrative screen for blocking communications between state agencies, “it would still not resolve the conflict of the state of Alaska acting as an applicant while also seeking to act as an assistant to the decision maker through its status as a cooperating agency,” Martin wrote in his letter. “Although we are not able to grant the state’s request for cooperating agency status, the state may nevertheless communicate its special expertise on the record,” Martin said. There are no restrictions on the Department of Natural Resources or any other state agency submitting public comments to FERC’s docket for the Alaska project. Federal offices with permitting authority over a project are required to assist as cooperating agencies, and FERC’s rules allow non-federal agencies to participate as cooperating agencies in preparing an EIS if they have “special expertise with respect to the environmental impact of the proposal.” The state Office of Project Management and Permitting submitted the July request to FERC. The office coordinates between multiple state agencies with environmental permitting expertise and “routinely enters into agreements with the lead federal agency as the single point of contact for state regulatory agencies … participating in the deliberative process and compiling state agency comments,” the request said. What’s different with the gas line project, however, is that the state is the developer of the proposed $43 billion venture to pipe North Slope gas more than 800 miles from Prudhoe Bay to a liquefaction plant and export terminal in Nikiski on Cook Inlet. In addition to working toward FERC approval, the state development corporation is trying to line up customers, partners and financing for what would be one of the most expensive energy projects in North American history. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC’s continued responses to FERC cover Cook Inlet crossing, health impacts

In filings with the Federal Energy Regulatory Commission last month, Alaska Gasline Development Corp. provided further details of its plan to tunnel and/or trench the buried pipeline from the west side of Cook Inlet. The plan is to tunnel far enough out in the water so that the pipe-laying barge could take over and set the concrete-coated pipeline on the seafloor to reach the other side, where trenching and/or tunneling would resume to bring the pipe ashore at Nikiski. AGDC said it prefers open-cut trenching for pipeline installation in the transition zones on both sides of Cook Inlet but could change the plan to tunneling as it learns more during the project’s detailed engineering stage. In its data request to AGDC, federal regulators noted that the project did not conduct geotechnical soil borings in the full transition zone on either side of Cook Inlet, limiting the data available to decide between tunneling and open-cut trenching. The pipeline would be buried with a minimum soil cover of three feet in the shoreline approach up to a water depth of 12 feet below mean lower low water (the average height of the lowest tide). In deeper water, where the pipeline is on the seafloor with no soil cover, AGDC said the 3.5 inches of concrete coating would protect the steel pipe from any damage from fishing gear, anchors or boulders. “The pipeline is safe without burial,” AGDC said. Separate from the FERC-led EIS, approval of the pipeline construction plan across Cook Inlet will be up to the U.S. Pipeline and Hazardous Materials Safety Administration and its regulations. Health impact assessment is wide ranging AGDC on Nov. 19 provided federal regulators with the project’s health impact assessment, which looks at how construction and operations could affect the health of Alaskans — including subsistence lifestyle and food nutrition. The filing is 170 pages long. “The presence of outside workers could exacerbate social problems or stress and impact mental health … particularly in smaller communities,” the assessment said. “Households impacted would be expected to adapt with some difficulty but could maintain pre-impact level of health with support from community, regionally based and existing federal support of Native health, public health programs. … Potential construction impacts to subsistence during the construction phase are expected to be temporary in duration,” the assessment said. “Potential concern related to subsistence resources during construction is the possibility that workers might compete with subsistence users resulting in either diminished harvests or greater subsistence effort. The project will prohibit workers from hunting or fishing while on the job or when company transportation has been used to bring them to a remote site.” The assessment’s subsistence section also raised the issue of invasive species. “The introduction of invasive species (both fish and/or aquatic plants) could impact fish habitat and/or productivity and impact fish availability to subsistence users. … The introduction of invasive species could become a long-term impact if their spread is uncontrolled, thus potentially signaling a long term reduced fish availability for subsistence users and users downstream of the impacted areas.” In another section, the assessment said Railbelt and highway communities “would be expected to be impacted by the increase in traffic during construction, which could cause mental stress and anxiety regarding the real or perceived issues of safety and environmental health associated with the increased rail and truck traffic.” Though it added, “Employment opportunities could alleviate family stress by improving family income, and the local economy during construction.” And the assessment noted that local fire departments and emergency medical service squads could see higher call volume during construction, while also facing the potential loss of staff and volunteers moving to Alaska LNG project construction jobs. Payments to municipalities under the project’s proposed impact aid grant program could help cover any added costs, AGDC told federal regulators. However, the project has yet to negotiate an impact aid program with the state and affected municipalities. Other responses AGDC’s November filings with FERC covered multiple other issues, including: • AGDC defended its plan to use gravel fill for work areas in wetlands during construction. In answer to questions from FERC, the state team said timber mats, wood chips or protective mats made of composite material would be too costly and impractical to deploy during construction. Wood or composite mats would cost two to four times as much as gravel fill, AGDC said. • “Typically, gravel fill would be placed as a protective cover over thaw-sensitive areas along the right-of-way during construction and would not be removed during restoration because it would be difficult to avoid disrupting the thermal regime of adjacent, undisturbed areas,” AGDC reported to FERC. • The project’s gravel sourcing and reclamation plan covers development of new sources of sand, gravel and fill for construction, along with plans to store or dispose of unsuitable materials that would be removed from the site such as unusable topsoil, overburden or frost-susceptible material. • A revised table lists locations of potential deep and shallow landslides, slope creep, rock falls, rock avalanches, debris flows and snow avalanches based on the project’s recently updated onshore geohazard assessment methodology and results summary. • “If warming continues for the next 30 years, it could change local permafrost and groundwater conditions sufficiently to result in mechanically weaker soils,” AGDC told FERC. “In these areas, significant precipitation events as well as earthquakes might have substantial impact on soil stability and, thus, pipeline integrity.” The state team was responding to FERC’s Oct. 2 comment that “AGDC’s proposed mitigation for soil liquefaction … and does not take into account areas that could become prone to liquefaction due to climate change and permafrost degradation.” The project responded that it would monitor and “apply mitigation techniques to minimize potential impacts from permafrost degradation along the pipeline.” • “It is unlikely permafrost would be thermally affected” by blasting for pipeline trenching, AGDC said. “Blasted trench areas are easily controlled to limit the disturbed materials to within the frozen trench walls and accordingly would not result in a shift in soil makeup and the permafrost profile.” • Thaw-sensitive soils cover a total of about 500 miles of the main pipeline route from Prudhoe Bay to Nikiski and the line from Point Thomson to Prudhoe. • Traffic on a 5-mile stretch of the Parks Highway outside the Denali National Park and Preserve would be limited to one lane September through May during pipeline construction, with brief closures (“hours, not days”) of both lanes. “Construction within this window would coincide with the off-season for tourism.” The project would try to limit the complete shutdowns to evening hours. • AGDC presented its plans to monitor commercial, domestic and public-supply water wells within 150 feet of the project — most of those wells are near the LNG plant site. The state team said it would test public water wells before and after construction to determine if the work affected the wells. Private wells would be tested at the landowners’ request. • Pile driving would occur 12 hours a day, 7 days a week at the LNG plant construction site, while pile driving at the compressor station and heater station construction sites along the pipeline route would occur 24 hours per day. Dredging for the marine offloading terminal at the Nikiski site would occur 24 hours a day, 7 days a week. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.


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