Larry Persily

As oil and gas prices spike, global investment lags behind demand

Fears of a global oil and gas shortage are pushing up prices, leading to a painful spike that is hitting many companies and consumers in their pocketbooks. The high prices have prompted multiple pleas for the industry to invest in new production. But outside of the Middle East and a few spots elsewhere around the world, including Russia, the hundreds of billions of dollars that would be needed to grow supply this decade isn’t showing up in new leases, drilling rigs, production facilities and pipelines. “The industry will need to spend significantly more, especially if oil and gas demand keeps climbing beyond pre-pandemic levels through 2025,” Moody’s Investors Service analysts wrote in a report released Oct. 7. Though oil and gas companies are expected to spend $352 billion on drilling and other activities worldwide this year, Moody’s said, the report recommended $542 billion in spending — the highest since 2015. “Our analysis demonstrates that upstream companies will need to increase their spending considerably for the medium term to fully replace reserves and avoid declines in future production,” Sajjad Alam, a vice president and senior analyst at Moody’s, said in the report. While U.S. natural gas prices have more than doubled this year, liquefied natural gas prices in Asia and Europe have hit record highs, and crude oil has climbed by more than 50% in price, drilling outlays are forecast to increase only 8% globally, Moody’s said. “The upstream energy sector continues to invest well below pre-pandemic levels despite the sharp turnaround in oil and natural gas prices in 2021. Exploration and production companies are signaling continued spending restraint in 2022,” the report cautioned. Boosting profits and dividends to please investors and worries about the long-term future for oil and gas are holding back companies from pouring more money into exploration and production. But the lack of drilling sets up the market for even tighter supply scenarios, Alam wrote in the report. The top official of the Organization of the Petroleum Exporting Countries said: “Don’t blame us.” Speaking at the online Energy Intelligence Forum on Oct. 6, OPEC Secretary General Mohammad Barkindo said: “The energy transition is not being handled properly. … And hence we are beginning to see the fallout.” The problem lies with the “hysteria” that has overtaken global thinking about how and how quickly to move away from fossil fuels to cleaner energy, he said. That rush and unrealistic planning is shrinking much-needed investment in new production, he said. In an interview with The Wall Street Journal a few days before his remarks at the energy forum, Barkindo said consumers should brace for more energy shortages unless the world boosts investment in oil and gas development. “The energy crisis in Europe and many parts of the world is a wake-up call,” he said. “It all comes back to the issue of investment across the oil and gas industry.” Saudi Aramco plans to invest in an additional 1 million barrels a day of new production by 2027, adding more than 8% to its current maximum output, CEO Amin Nasser said at the same online energy forum. “We still expect growth in oil demand,” he said, contrary to predictions of peak global oil demand as soon as 2030 or early next decade. The Saudis see cleaner oil and gas in the future rather than a lot less of the fuels, differing from the view that renewables and greener fuels soon will take over the market. Abu Dhabi National Oil, the main oil producer in the United Arab Emirates, plans to spend tens of billions of dollars this decade to boost its oil production capacity to five million barrels a day, up from about four million today. Neighboring Qatar, which leads the world in LNG production just as Saudi Arabia is a leader in oil, has a similar view of what the energy transition means to demand for fossil fuels. “For me to just come out and say net-zero 2050 would be very sexy,” Saad Al-Kaabi, Qatar’s energy minister, said at an event in Doha on Oct. 11. “But it’s not the right thing.” Many politicians “are just throwing it out there without a plan,” he said. Banking on strong demand for LNG in the decades ahead, Qatar is going ahead with a $30 billion project to boost its LNG production capacity by 50% in the next six years. Don’t blame high prices on the transition to clean energy, said the chief of the Paris-based International Energy Agency. “Well managed clean energy transitions are a solution to the issues that we are seeing in gas and electricity markets today, not the cause of them,” Fatih Birol said at a meeting of the European Parliament’s energy and environment committees last month. Multiple factors, including inadequate natural gas stockpiles in Europe, supply disruptions and a faster-than-expected economic recovery from the pandemic created the supply-and-demand imbalance, driving up prices, Birol told the committees. “A lot less product is available to meet this now-rapid growth we’re seeing,” ExxonMobil CEO Darren Woods said in virtual remarks at a conference in Russia on Oct. 13. “If we don’t balance the demand equation and only address the supply, it will lead to additional volatility.” Regardless of the reasons, the high prices for oil and gas are driving utilities in Europe, China, India, Pakistan and elsewhere around the world to turn to the old reliable power-generating fuel — coal — and driving up greenhouse gas emissions. “This is the revenge of the fossil fuels,” Thierry Bros, an energy expert and professor at the Paris Institute of Political Studies, told Bloomberg last week. “Energy importers have two options,” Clyde Russell, a longtime energy reporter and columnist with Reuters, wrote Oct. 5. “Namely to increase investments in fossil fuels in order to ensure that they always have sufficient supplies, or go down a path of boosting investment in renewables and energy storage in order to reduce reliance on foreign fuels.” Larry Persily is a former Alaska journalist and state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

As LNG prices soar, a lesson that timing is everything

An LNG trader with some extra of the heating and power-generation fuel to sell in Asia this month could make $100 million more than what it was worth less than 18 months ago. The $100 million is not a month’s worth of deliveries; that’s one standard-size 975-foot-long LNG carrier with a full load in its insulated tanks. In this fall’s lucrative and rapidly escalating Asian spot market, the gas is worth more than half as much as the entire ship cost, brand new. There appears no question that natural gas producers and liquefaction plant developers failed to fully anticipate the heavy demand for the fuel this fall and winter, or the resulting gas supply shortages that are causing record-high prices and economic pain across much of Asia and Europe. While producers and traders have some spare gas to sell, not bound under fixed-price contracts, those same companies needed to have invested tens of billions of dollars years ago if they were going to cash in even bigger during the price spike, which has seen liquefied natural gas on the Asian spot market sell for an unprecedented, unworldly and unaffordable $34.47 per million BTU last week. That’s almost 20 times the low of $1.85 set in May 2020, when the world was shutting down for the COVID-19 pandemic, and just a month after crude oil prices had averaged less than 50 cents a gallon. Unlike OPEC and its allies, which have significant spare oil production capacity that can ramp up in weeks or months as the global economy recovers, additional natural gas doesn’t move that easily. The industry needs years and at least $10 billion, often double that, to build the complex liquefaction plants to produce new supply for buyers. Therein lies the challenge — and the risk — of judging the market for a long-term investment that will not start delivering until the market may have changed. Examples of bad bets are plentiful. In the first decade of the 21st century, several gas producers, developers and traders saw high natural gas prices in the U.S., declining production from mature basins and rising demand, and decided the country would become a major LNG importer. They spent billions reactivating unused receiving terminals from the 1970s and building new LNG import facilities. They thought they were going to get rich. Then some smart gas producers figured out how to drill and market prodigious amounts of shale gas, overwhelming U.S. demand. The imperative to import the fuel disappeared within a few years. The owners of those unused import terminals later spent billions more to turn the facilities into export projects, so they could reverse course and profit from selling much of that surplus U.S. gas overseas. A happy ending, but only after heavy losses for years. More recently, Norway’s Equinor and Russia’s Gazprom, which together supply about 60 percent of Europe’s natural gas, found themselves cashing record-size checks for pipeline gas deliveries to the continent. The European Union had liberalized its gas market years ago, shifting away from long-term contracts at fixed prices, often linked to oil, moving to short-term or flexible contracts that worked to their advantage during a long period of low natural gas prices. Europe’s luck ran out this year as the tight market and multiple other factors drove up prices by 300 percent, without contracts to protect buyers. “The rapid increase in gas prices happened at the best historical time possible for Equinor,” company economist Eirik Waerness told Reuters last month. In Asia, buyers that were traditionally bound under oil-price-linked LNG purchase contracts clamored for more flexibility and better terms when oil was above $100 a barrel 10 years ago. Many switched to shorter-term contracts or spot purchases as new LNG supply flooded the market, driving down prices. As in Europe, buyers in Asia enjoyed low prices, but only until the market reversed course. Now, as the spot-market is at record highs amid tight supplies, those oil-linked contract LNG cargoes are less than one-third the cost of spot buys. Timing is everything, and prices seem to always look better on the other side of the forecast. Meanwhile, it’s getting more complicated. In addition to knowing whether ample supply will hold down prices for years, or whether short supplies will drive up prices and profits, gas producers and investors now have to calculate how much renewable energy will cut into their market share in the years ahead. It’s made many of them cautious. No sense building a fossil-fuel project that needs 20 years for payback if green energy will take over the electric meters of the future. Unless renewables don’t, in which case LNG suppliers will be happy to oblige at a profit, as long as they are willing to risk the investment years ahead of time. As is Qatar, the world leader in LNG production and exports, which is proceeding with a multibillion-dollar, 40 percent expansion of its output capacity this decade. This year’s record-high gas prices are “due to the market not investing enough in the industry,” Qatari Energy Minister Saad al-Kaabi said on the sidelines of the Gastech industry conference last month in Dubai. The lack of investment in new supply, either due to risk aversion or fear that renewables will dominate the future, is not good for anyone, he said. “We don’t want these high prices, we don’t think it is good for the consumers. We don’t want $2 and we don’t want $20, we want to have a reasonable price that is sustainable,” Reuters quoted al-Kaabi. All those years of low gas prices, while comforting for buyers, are part of the reason for today’s tight market, said a U.S. LNG developer. “The world was kind of lulled to complacency because (gas) prices were low for five years so no one felt an urge to plan and everyone got very religious on environmental protection and it is wonderful,” said Charif Souki, co-founder of Tellurian, which wants to build an LNG export terminal in Louisiana. “But we should look at what things actually work rather than simply what we hope for,” he told Reuters last week. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

Russia plows ahead on oil, natural gas

While the rest of the energy world deals with reluctant lenders and insurers, activist investors and pension funds turning away from fossil fuels, politicians and citizenry pushing to accelerate the transition past oil and gas — less so Russia. An example of how friendly the government remains to oil and gas development — which provided close to 45 percent of the government’s annual revenue pre-pandemic — was seen in a press release Sept. 8 by Novatek, the country’s largest independent natural gas producer. The company had won an auction — in which it was the only bidder — for licenses to explore, develop and produce from Arctic fields holding an estimated 2.9 billion barrels of oil equivalent, which includes 14.6 trillion cubic feet of gas. Novatek paid about $180 million for the 27-year licenses, or about 6 cents per barrel of potential, though certainly not all of the 2.9 billion barrels will be pumped from the ground. The fields are on the Yamal Peninsula, where Novatek in 2017 started up the country’s largest liquefied natural gas production and export terminal; where the company is building a second, even larger LNG project; and where it wants to add a third gas facility. Designs plans for the third plant, originally targeting LNG production, were switched this summer to ammonia, hydrogen and methanol production, which all require natural gas. To meet its feed gas needs — in particular to reach a final investment decision on the third plant — Leonid Mikhelson, the CEO and major shareholder at Novatek, earlier this year told the government his company needed access to more gas resources. The request was granted. Russia wants to become an even bigger player in the global LNG market, in particular profiting from export sales to Asia just as it does with its dominant position as a supplier of pipeline gas to Europe. The Warsaw Institute, a Poland-based geopolitical think tank with a focus on energy issues, reported earlier this year: “Mikhelson … has friendly ties with the Kremlin. (Russian President) Vladimir Putin has for years asked state authorities to favor the company.” But there was a problem in the area that Novatek wanted access to develop. The deposits are within the boundaries of a natural reserve, where industrial activities, including oil and gas drilling, are prohibited. According to Interfax, an independent news agency in Russia, Mikhelson asked the Kremlin to instruct the area’s regional government to change the reserve’s boundaries. The regional government obliged in May. The borders of the Yamalsky Reserve, at almost 10 million acres, frequently have been adjusted over the years following requests from oil and gas companies, according to a website of Russian government actions and as reported by the independent Barents Observer newspaper, published out of Norway. With the boxes checked off for additional gas and government support, Novatek continues to look for partners to share in the risks and help provide capital, and raise financing. Lacking access to U.S. and European lenders, due to western sanctions against Russia and banks pulling away from fossil fuel financing, particularly in the Arctic, Novatek is turning to Japanese and Chinese banks for more help. Already most of the equity partners in the Novatek-led Arctic LNG-2 project, which is under construction with a 2023 start-up date, are from China and Japan: China National Petroleum Corp., 10 percent; China National Offshore Oil Corp., 10 percent; and the Japan Arctic LNG consortium, comprised of Mitsui and state-owned JOGMEC, formally known as Japan Oil, Gas and Metals National Corp., at 10 percent. French major TotalEnergies also owns a 10 percent stake. Novatek holds 60 percent. Seeing a lack of support from European government export credit agencies, Mikhelson earlier this month said Chinese and Japanese lenders may step in where Europe is backing out, and Russian banks could boost their share to 60 percent of the debt, he said. Normally, government export credit agencies help finance projects when some of the contracts and jobs benefit their country. Shareholders in Arctic LNG-2 earlier this year approved external financing of $11 billion for the $21 billion development, with the partners to come up with their respective shares of the rest. In addition to financing from Japanese and Chinese lenders, Novatek is in talks with India’s top energy companies, Petronet LNG and ONGC Videsh, about buying a stake in Arctic LNG-2. The Indian government is pushing the country to burn a lot more gas than coal or oil to help clean up its air, and the two companies are in talks about acquiring a joint 9.9 percent stake in the venture, according to a Bloomberg news report Sept. 6, leaving Novatek at 50.1 percent. Adding partners in India to its LNG ambitions would be a smart play for Russia’s efforts to establish itself as a key supplier of the fuel in the region. Building partnerships is about sharing the wealth, and Novatek has given some of the business for the $20 billion Arctic LNG-2 project to a Chinese shipyard. The first gas liquefaction module was built at Wison Offshore &Marine’s Zhoushan shipyard in China and arrives this month at Novatek’s construction yard north of Murmansk, where it will be installed atop a large gravity-based structure before it is towed to the project site on Ob Bay in Siberia. There are analysts, however, who question the wisdom of Russia’s bet on long-term profits from fossil fuels. The Oxford Institute for Energy Studies in the U.K. published a paper in February titled, “Is This Russia’s Kodak Moment?” “In 2003, Kodak was over 100 years old, had one of the world’s most recognized brand names, employed 145,000 people, and had a turnover of US$13 billion. The company believed that digital photography would remain a niche product and decided to stick to traditional photographic film,” the paper said. “Nine years later, Kodak filed for bankruptcy.” “Is Russia similarly failing to see the accelerating changes in the global energy system brought on by climate policy and energy technology learning curves? Is it prepared for the impact of these changes on demand for Russian fossil fuel exports? As the world’s largest fossil fuel exporter (oil, gas and coal), Russia will be affected by the energy transition more than any other country.” Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

Oil price forecasts scrambled by COVID-19 uncertainty

Oil-price forecasters mostly focus on two things: supply and demand. They watch the Middle East, follow global politics, track industrial activity and other economic indicators. All of which can affect supply and demand. Now they also watch medical charts for COVID-19 infection rates. The market players of oil producers, buyers, traders and investors worry that rising infection rates could slow down the world economy and knock down the recovery in consumption of crude oil. That would shift global oil supply — which OPEC+ is steadily increasing — out of balance if demand pulls back. That worry of too much crude and not enough demand led to a 10 percent drop in oil prices in mid-August, before the market took its temperature again, felt better and recovered by the end of the month to around $70 per barrel for Brent crude. Since then, the resurgence of COVID-19, particularly in Asia, has prompted renewed nervousness as OPEC+ continues with its plan to bring back 400,000 barrels per day of production every month through fall 2022. And now, the latest reports from the Organization of the Petroleum Exporting Countries and the International Energy Agency are adding to the market skittishness. OPEC analysts presented a report Aug. 31 that said global markets could run a supply surplus next year. Due to weakening demand projections, the analysts forecast supply could exceed demand as soon as January, adding more barrels back into storage which the OPEC+ alliance has been working all year to reduce. The OPEC base case now shows global crude stockpiles building to 3.2 billion barrels by the end of 2022, about 10 percent greater than the 2015-19 average. An even more pessimistic scenario from the analysts of COVID-induced lower demand shows 3.6 billion barrels in storage by December 2022, or the most in several years, other than 2020 when storage tanks filled up and crude was parked aboard tankers at sea. The OPEC analysts forecast global supply exceeding demand by more than 100 million barrels per month January through May 2022, then continuing at a lower level the rest of the year. “Unless oil demand turns out much stronger, or production outside the OPEC+ group much weaker than OPEC’s analysts predict, the time will soon come when the members will again have to contemplate cutting, rather than raising, output,” Julian Lee, an oil strategist for Bloomberg, wrote in a commentary Sept. 4. Lee previously worked as a senior analyst at the Centre for Global Energy Studies, a think tank headquartered in London. “When that happens,” Lee said of the prospect of production cutbacks, “expect the old (and new) divisions (within OPEC+) to emerge again,” and the alliance returning to “long and difficult” meetings between the 23 producing nations led by Saudi Arabia and Russia. The International Energy Agency sees it the same as OPEC analysts. The IEA has cut its oil demand forecast for this year, and predicts supply may outpace demand by next year. The agency said global oil demand “abruptly reversed course” in July due to “the worsening progression of the pandemic.” The spreading Delta variant of the coronavirus — coinciding with OPEC+ continuing its plan to bring back production — will eliminate “lingering suggestions of a near-term supply crunch,” the IEA said. “Growth for the second half of 2021 has been downgraded more sharply, as new COVID-19 restrictions imposed in several major oil-consuming countries, particularly in Asia, look set to reduce mobility and oil use,” the IEA said in its monthly report. “We now estimate that demand fell in July as the rapid spread of the COVID-19 Delta variant undermined deliveries in China, Indonesia and other parts of Asia.” It was just two months ago that Goldman Sachs and others were predicting oil would reach $80 per barrel by the end of this year. That’s looking less likely. “The scale could tilt back to surplus in 2022 if OPEC+ continues to undo its (production) cuts and producers not taking part in the deal ramp up in response to higher prices,” the IEA said in its report. OPEC+ is prepared to pause or even reverse its scheduled output increases if necessary to keep supply and demand in balance, Saudi Energy Minister Prince Abdulaziz bin Salman said in August. One number that may help OPEC+ avoid any change in its production plans is that the alliance is actually pumping about 10 percent less than its overall quota as some members — notably Angola and Nigeria, and somewhat Russia — are having problems fulfilling their allocations due to deteriorating production capacity from a lack of investment or technical disruptions. Still, some OPEC nations are concerned. “The markets are slowing. Since COVID-19 has begun its fourth wave in some areas, we must be careful and reconsider this increase. There may be a halt to the 400,000 increase,” Mohammad Abdulatif al-Fares told Reuters on the sidelines of a government-sponsored event in Kuwait City just two days before OPEC+ decided Sept. 1 to proceed with the scheduled production boost. The oil-producing nations should be cautious about oversupplying the market, Fares said. OPEC+ last year implemented a record output cut of 10 million barrels per day, equating to about 10 percent of world supply, when energy consumption plunged because of travel restrictions and national lockdowns to counter the spread of COVID-19. The alliance has been slowly restoring production and is scheduled to bring back all of the crude output by fall 2022. Unless COVID changes the plan. “It feels like the Delta variant has gained control of the oil market and the narrative here,” said analyst Patrick O’Rourke, with ATB Capital Markets in Calgary. “We were on the cusp of the economy reemerging and the beginning of international travel. And the brakes have been completely pumped on that,” he was quoted in the Calgary Herald on Aug. 21. “The OPEC+ group faces a real challenge in the months ahead from needing to reduce supply just as many members are itching to open their oil taps some more,” Bloomberg’s Lee wrote in his commentary last week. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

Natural gas projects face new scrutiny from FERC

The rules have changed from a year ago. Between court orders and election-induced policy changes at the White House and Federal Energy Regulatory Commission, natural gas pipelines and liquefaction plants will need to pass stricter regulatory reviews of their greenhouse gas emissions. It’s still uncertain how FERC will determine which projects pass and which fail. The Department of Energy will do much the same for liquefied natural gas exports. In a victory for opponents of two proposed LNG export terminals at the Port of Brownsville, Texas, a federal appeals court on Aug. 3 ruled that FERC must further analyze each project’s potential impacts on climate change. The panel of the U.S. Court of Appeals for the D.C. Circuit was unanimous in its ruling that FERC violated the National Environmental Policy Act, or NEPA, with “deficient” environmental analyses. The court did not vacate FERC’s authorization of either project, but did direct the commission to try again and do a better job. “This decision clearly demonstrates that the commission has the authority and obligation to meaningfully analyze and consider the impacts from (greenhouse gas) emissions and impacts to environmental-justice communities,” FERC Chairman Richard Glick, who had dissented when the commission approved the projects in 2019, said in a statement after the court decision. The court ruled that the commission “had not adequately justified its finding that the projects are in the public interest under the Natural Gas Act,” FERC reported on its website. Also in August, the Environmental Protection Agency advised FERC to begin incorporating the social cost of carbon into its environmental reviews of natural gas infrastructure projects. The EPA said such work could help the commission put a dollar value on harm caused by project emissions. In addition, FERC should consider attaching conditions to its orders to reduce climate change impacts from gas projects, the environmental agency said. The commission this year has expanded its reviews with supplemental environmental reports to consider climate change impacts of gas projects, though commission staff has said in at least two reports that they are unable to calculate the lifetime impacts of emissions from gas production to consumption by end-users. “Commission staff conclude that construction and operation of the project would not result in significant environmental impacts, with the exception of climate-change impacts, where FERC staff is unable to determine significance,” a draft environmental review in June for a Louisiana gas pipeline said. Glick, who took over as FERC chairman in January, has pushed to include consideration of climate impacts in gas pipeline reviews. At a congressional hearing in July, he answered that federal courts on “numerous occasions” have told FERC that if environmental concerns are significant enough to outweigh benefits, and if those impacts could not be mitigated, then FERC could reject a project. “I think we will start to see greater accounting for greenhouse gas emissions in the FERC process,” Samuel Reynolds, an energy finance analyst at the Institute for Energy Economics and Financial Analysis, said at a conference hosted by the group in June. In March, the commission issued an order that said it will “consider all appropriate evidence regarding the significance of a project’s reasonably foreseeable GHG emissions and those emissions’ contribution to climate change.” That’s a big change from a year ago, said an analysis by law firm Jones Day. “This is a significant departure from FERC’s previous restrained stance on considering GHG emissions, in which it held that it was unable to make that assessment,” the firm said. “What this means for the natural gas industry is still unresolved.” A National Law Review report described the order as “a sea change” for FERC’s approach to emissions and its obligations under NEPA. “Additional changes to FERC’s approach are likely … but the order leaves little doubt that the GHG impacts of pipeline proposals will receive closer scrutiny from the commission than they have in the past,” the report said. Though court decisions in 2017 and 2019 directed FERC to pay attention to climate change impacts in its gas project reviews, “FERC continued to be restrained in its consideration of GHG emissions throughout the remainder of the Trump administration,” Jones Day said in its May analysis. That changed with the election, with a new majority on FERC and court rulings. “FERC will now consider a project’s GHG emissions … when determining whether a project is required by the public convenience or necessity,’” Jones Day said. “FERC views this analysis as part of its obligation under NEPA to take a ‘hard look’ at a project’s environmental impacts.” What the change means for the natural gas industry is uncertain. In its March order, expanding its review of climate change impacts, FERC was careful to note that “the evidence on which the commission relies to assess significance may evolve,” Jones Day said. At a July hearing of the U.S. House Energy and Commerce Committee’s energy subcommittee, Ohio Republican Rep. Bill Johnson asked Glick how FERC would consider climate change impacts from U.S. LNG exports, including the benefit that consuming nations might use cleaner-burning gas than dirtier fuels to generate electricity. “Courts have told us that’s for the Department of Energy, not FERC,” Glick responded. That’s exactly what is happening to the proposed Alaska LNG Project. The state corporation managing the project was told in late June that the U.S. Department of Energy has ordered a supplemental environmental review of the full lifecycle of greenhouse-gas emissions from production on the North Slope to consumption by overseas buyers. Referring to executive orders issued in the first week of the Biden administration, the department determined “it was appropriate to further evaluate the environmental impacts” of exporting LNG from the proposed Alaska project. In a footnote to its June 28 order, the department said it would consider emissions from the entire LNG supply chain, “from the ‘cradle’ when natural gas is extracted from the ground, to the ‘grave’ when electricity is used by the consumer.” Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

Analysts weigh in on Pikka after merger

Most people in Alaska would have paid little attention to last week’s announcement that two Australia-listed, publicly traded oil and gas corporations were going to become one, the combined company moving into the Top 20 among the world’s oil and gas producers. That’s if not for the fact that the smaller one, Oil Search, which accepted a buyout offer from the larger one, Santos, holds a 51 percent interest in the undeveloped Pikka unit on Alaska’s North Slope. Pikka and ConocoPhillips’ Willow development underpin hopes that Alaska’s oil production could enjoy a strong boost in crude flowing through the Trans-Alaska Pipeline System later this decade. Neither Santos nor Oil Search mentioned the Alaska prospect in their Aug. 2 announcements of the deal, though that did not stop speculation by industry analysts thousands of miles away from the North Slope about what the combined company would do with Pikka. Their comments started the day the deal was announced. Tom Allen, an analyst with UBS, told the Australian Financial Review that he expects a merged Santos-Oil Search will consider divesting itself of Pikka. Allen is head of Australian Energy and Utilities Equity Research at UBS, a Swiss-based multinational investment bank. Allen said he expects the combined company will focus its integration efforts in Asia, where Oil Search and Santos both hold interests in Papua New Guinea natural gas assets, including the ExxonMobil-led liquefied natural gas project in the island nation. The LNG project, developed at a cost of $19 billion, has been producing since 2014, often exceeding its nameplate capacity and generating healthy profits for its owners, which are looking at an expansion. Oil Search and Santos hold a combined 42.5 percent stake in Papua New Guinea LNG. Oil Search also owns a share of another proposed LNG project, led by French major TotalEnergies, that targets first production in Papua New Guinea in the second half of the decade. Santos holds an extensive gas portfolio in Australia, including stakes in the Gladstone LNG export facility in Queensland and the Darwin LNG plant in the Northern Territory. Pikka, near the Colville River and west of the Kuparuk River and Prudhoe Bay fields, is certainly a geographic outlier in the two companies’ Asia-focused assets portfolio. Another Australia-based analyst, Gordon Ramsay, said he sees the deal as “all about PNG.” Ramsay is a director and lead energy research analyst with RBC Capital Markets, part of the Royal Bank of Canada. Though he sees the gas as the main draw for the deal, Ramsay views diversification into Alaska as “a good counter-balance” to Oil Search’s overreliance on Papua New Guinea gas. He suggested Santos may retain Pikka. “We view Alaska as a ground-floor opportunity for Santos to become involved in a potentially very material asset with a substantial and growing reserve base,” Ramsay told the Australian Financial Review’s energy reporter. In public presentations, Oil Search has projected that Pikka’s first-phase development, estimated at $3 billion, would have capacity to produce up to 80,000 barrels per day. The company has said production could reach 120,000 barrels per day with additional investment in second and third phases. Oil Search and its 49 percent partner, Repsol, both have been looking to sell off a portion of their stakes in Pikka to reduce risk and help share the burden of development costs. Oil Search last year put some of its field work on hold as the pandemic was approaching its worst and oil prices were near their lowest. Several companies have expressed interest in buying into Pikka, then-CEO Keiran Wulff said in April at a conference in Australia. He said Oil Search had succeeded in cutting costs to the point that Pikka could return 10 percent on capital with oil at $40 per barrel. The company’s goal — not a deadline — has been a final investment decision on the first-phase development by the end of this year, with first oil production in 2025. Oil Search bought into Alaska in 2018 when it negotiated a $400 million purchase of North Slope leases from Armstrong Energy and GMT Exploration. It has kept busy since then with exploratory drilling, gravel road building and permitting. “We will work with our partner Repsol on achieving an appropriate funding structure for our Alaska project, prior to committing to FID,” Oil Search said in a July 19 briefing on the departure of the company’s CEO. “That includes the work we are currently doing on a possible joint selldown of equity in the (Pikka) project, consideration of the sale of midstream infrastructure within the project and reviewing relevant markets for an appropriate level of debt financing to support the project,” the company’s acting CEO Peter Fredricson said on the call. “It’s very much a matter of how and when we fund it to a point to go forward.” CEO Wulff resigned in July for health reasons, while on the same day the board strongly criticized his behavior and management style. In the context of financing future developments, combining Oil Search and Santos makes sense, Wood Mackenzie research director Andrew Harwood wrote in a commentary on the global consulting company’s website. “At current commodity prices, the combined entity will generate significant free cash flow through 2021 and 2022,” he wrote. “Combining with Oil Search would immediately increase Santos’ production by over one-third, to around 290,000 barrels of oil equivalent per day.” The merged company will be able to proceed with its efforts to take in new partners in Alaska and offshore Australia “from a position of strength,” he added. Less encouraging than Hardwood or Ramsay in his description of the Santos-Oil Search deal was Saul Kavonic, a Zurich-based analyst at Credit Suisse. Noting that Oil Search had rejected the first buyout offer from Santos, later saying yes to a richer deal, Kavonic told the London-based Financial Times that Oil Search was in a weak bargaining position to say no a second time. “Oil Search’s board has raised the white flag, having been weakened in the wake of management churn and governance concerns, and pressured into a merger by increasingly frustrated investors,” he was quoted the day the deal was announced. “The acceptance of the offer can essentially be viewed as a capitulation by Oil Search that their Alaska asset is not worth what they hoped it would be.” The merger agreement is to conditions including Oil Search shareholder approval and Papua New Guinea government approval. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

Saudis, UAE want to cash in while the world still runs on oil

Though OPEC members earlier this month settled their latest dispute over how much and how fast to bring back shuttered oil production, the longevity of the peace could be influenced by an emerging attitude at two of the cartel’s top three producers. Saudi Arabia and the United Arab Emirates reportedly want to pump as much crude as they can while prices are good and the world is still running on petrol, before the predicted decline in consumption really takes hold as countries accelerate the shift to cleaner energies. It makes sense from a business perspective: maximize income while buyers want the product. But it also seems an acknowledgement that buyers will not want as much oil in the decades ahead. “Stranded assets” is not a term that oil producers want to add to their financial statements. In June, at a private event organized by Bank of America Corp., as reported by Bloomberg news service on July 21, Saudi Energy Minister Prince Abdulaziz bin Salman said: “We are still going to be the last man standing, and every molecule of hydrocarbon will come out.” That’s a lot of molecules for the Middle East powerhouse, 297 billion barrels, according to BP’s Statistical Review of World Energy, issued in June and based on 2020 numbers. The Saudis’ storehouse is more than four times U.S. proved reserves and almost three times those of Russia; the three countries are the top oil producers in the world. The holdout that delayed the latest OPEC+ production deal, the UAE, is no slouch in the oil reserves charts. Its 98 billion barrels is far ahead of the U.S. and close to Russia. The UAE’s pre-pandemic production of 4 million barrels per day in 2019 put it in third place among OPEC member nations. But why settle for No. 3 when you could be No. 2? The UAE’s state-owned Abu Dhabi National Oil Co. announced in 2020 it would spend more than $120 billion as part of a plan to boost its production capacity to 5 million barrels per day by 2030, passing Iraq into the No. 2 spot. “This is the time to maximize the value of the country’s hydrocarbon resources, while they have value,” The Wall Street Journal this month quoted a person briefed on the UAE strategy. “The aim of the investment is to generate revenue for the diversification of the economy, both for investment in new energy and, as importantly, in new revenue streams.” “Market share is a key factor here,” a senior UAE oil executive told the newspaper. “We want a bigger market share, to monetize as much as we can from our reserves, especially when we have spent billions developing them.” The country’s energy minister called the constraints on its output “totally unfair.” The UAE’s plan to boost production followed by a few months a Saudi Aramco announcement that it planned to invest billions to add 1 million barrels per day to its output capacity. It sure looks like an impending fight over market share, especially as both the UAE and Saudi Arabia have money to invest in more capacity, along with low per-barrel production costs, while much of their competition, particularly U.S. and European companies, are holding back from large projects. Oil majors BP and Shell already have announced plans to reduce oil production as part of a global shift to cleaner energies. The UAE is “in the race for market share ahead of peak demand,” Robin Mills, chief executive of Dubai-based consulting firm Qamar Energy and a former manager in the Emirati oil industry, told The Wall Street Journal. “Saudi Arabia is not in a comfortable position,” Karen Young, a senior fellow at the Washington-based Middle East Institute was quoted by Bloomberg. “There will be customers for oil in 10 and 20 years from now. But (every oil producer) is going to be competing for a smaller and smaller number of buyers.” Neither country sounds too worried about a sudden drop in demand. They expect their customers will buy crude for a long time, but less of it longer term. Until then, selling as much as they can, at strong prices, can help the Saudis and UAE as the world moves away from oil. Leaders in both countries have talked of building post-oil economies. Which means turning all that crude underground into cash for whatever comes next. “The historic alliance (because the UAE and Saudi Arabia) is being tested,” Christyan Malek, who is in charge of global energy at JP Morgan &Chase, told The Wall Street Journal. “The rivalry is no longer just in the oil market, but for the post-oil economy.” The UAE succeeded in winning higher production numbers in the latest OPEC+ deal, but they will not kick in until April 2022. It was a compromise, averting a potential price war while stemming a steep rise in oil prices that was squeezing buyers and causing anguish for the leaders of consuming nations. Meanwhile, Russia is always ready to produce and export more oil in its own quest for market share. The country has been among the strongest advocates of substantial increases in production quotas for the 23-member OPEC+ alliance. In addition to the UAE, Russia also gained higher production limits under the July agreement, as did Kuwait and Iraq. Analysts surveyed by Bloomberg said Russia could boost output by between 500,000 and 950,000 barrels per day within six to 12 months. That could return the country to near its post-Soviet record of 11.25 million barrels a day, reached in 2019. “Russian producers have repeatedly proven that they can add back idle production on very short notice,” Ron Smith, a senior oil and gas analyst at BCS Global Markets, told Bloomberg in June. “I think the market may be underestimating Russia’s ability to raise output.” Speaking at a press conference after OPEC+ announced its latest agreement, the Saudi oil minister said: “What bonds us together is way beyond what you imagine.” The desire for strong prices may bind the countries, but that binding could stretch as global consumption heads down and the big players don’t want to be left holding a bag of unproduced crude. Larry Persily can be reached at [email protected]

Energy Department orders lifecycle review of Alaska LNG emissions

The U.S. Department of Energy has ordered a supplemental environmental review of the full lifecycle of greenhouse-gas emissions from production on the North Slope to consumption by customers for the proposed export of liquefied natural gas from Alaska. Referring to executive orders issued in the first week of the Biden administration, the department determined “it was appropriate to further evaluate the environmental impacts” of exporting LNG from the proposed Alaska Project. The department issued a notice June 28 that it will prepare a supplemental environmental impact statement, or EIS, for the project. The review “will include an upstream analysis of potential environmental impacts associated with natural gas production on the North Slope of Alaska.” The supplemental EIS, which will be prepared by the department’s National Energy Technology Laboratory, will include a lifecycle calculation of greenhouse-gas emissions, “taking into account unique issues” in the production of North Slope gas; pipeline transport more than 800 miles through Alaska; liquefaction at the gas plant proposed for Nikiski, on Cook Inlet; and marine transport, primarily to Asian buyers. A footnote to the June 28 order explained that lifecycle analysis “is a method of accounting for cradle-to-grave” greenhouse-gas emissions. The department considers emissions from the entire LNG supply chain, the footnote said, “from the ‘cradle’ when natural gas is extracted from the ground, to the ‘grave’ when electricity is used by the consumer.” The order to prepare a supplemental EIS comes 15 months after the Federal Energy Regulatory Commission, as the lead agency for environmental analysis of the Alaska project, issued its final EIS for the project in March 2020. The Department of Energy adopted that final EIS 10 days after FERC, as has been customary in recent years for the department to adopt the commission’s environmental analysis. Both agencies later issued final authorizations for the project: FERC governs construction and operation of the pipeline, LNG plant and other facilities; the Department of Energy regulates exports of U.S. natural gas. Under new leadership, FERC also is attempting to measure lifecycle emissions in reviewing natural gas pipeline projects. The FERC and Energy Department authorizations are held by two different entities. The state-owned Alaska Gasline Development Corp. holds the FERC authorization. The corporation proceeded with the expensive project application and EIS process on its own after North Slope producers in 2016 decided not to spend more money on the economically challenged $38 billion project and dropped out of the application process. The export authorization for the gas is held by Alaska LNG LLC, a consortium of ExxonMobil, ConocoPhillips and Hilcorp Alaska. The original application for exports was filed in 2014, with BP one of the partners. Hilcorp bought up BP Alaska last year, giving it the same one-third stake in Alaska LNG LLC as ExxonMobil and ConocoPhillips. The producers hold no interest in the state corporation, and the state is not a party to the export authorization. The notice of a supplemental EIS had been anticipated after the department on April 15 granting a rehearing filed by the Sierra Club and determined that it would proceed with the additional environmental review of the Alaska project. After the supplemental review is completed, the department may “reaffirm, modify or set aside the Alaska LNG (export) order,” according to the April 15 decision. The department said June 28 it will issue a notice in the Federal Register when the draft supplemental EIS is released, dates of “one or more online public hearings” on the draft, and instructions for submitting public comments. The department will pay for the supplemental EIS, an official reported July 6. The FERC and Energy Department authorizations for the Alaska LNG Project have been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by the Sierra Club and other opponents of fossil-fuel projects. “Those lawsuits are ongoing and are currently subject to various pending procedural motions,” according to the Energy Department order for a supplemental EIS. For its additional review of upstream production issues, the department has “tentatively identified the following resource areas for analysis (although the following list is not intended to be comprehensive or to predetermine the potential impacts to be analyzed): land use and visual resources; geology and soils; water resources; air quality and noise; ecological resources; cultural and paleontological resources; infrastructure; waste management; occupational and public health and safety; socioeconomics; transportation; and, environmental justice.” Those are the same areas covered in the FERC-led EIS, which took three years to complete after the state corporation submitted the last of its required reports. For the lifecycle analysis, the Energy Department said it will “examine the global nature of GHG emissions associated with exports of LNG from Alaska.” One of the presidential executive orders referenced in the department’s June 28 notice directs all federal agencies to “immediately review all regulations, orders and other actions issued after January 20, 2017,” that may increase greenhouse-gas emissions or affect climate change.” The second calls to “organize and deploy the full capacity of [federal] agencies to combat the climate crisis,” according to the department’s footnote, requiring the federal government to assess, disclose and mitigate “climate pollution and climate-related risks in every sector” of the U.S. economy. Larry Persily can be reached at [email protected]

FERC denies requests for rehearing of Alaska LNG approval

Without comment, the Federal Energy Regulatory Commission on July 22 declined to take up two requests that it reconsider its June 6 approval of the state-sponsored Alaska LNG project. Under federal law, such requests for rehearing are deemed denied if FERC declines to act on the motion within 30 days. The Matanuska-Susitna Borough filed its objections to the project approval on June 19, followed on June 22 by a motion for rehearing from the Center for Biological Diversity and Earthjustice. The clock ran out July 22 without FERC acting on the requests. “In the absence of commission action on the requests for rehearing within 30 days from the date the requests were filed, the requests for rehearing (and any timely requests for rehearing filed subsequently) may be deemed denied,” FERC said in its July 22 notice. The next step — should either the borough or the environmental groups choose — would be to challenge the FERC authorization in federal court. The borough believes its property at Port MacKenzie, across Knik Arm from Anchorage, would be a better location for the proposed gas liquefaction plant and marine terminal than the project’s preferred site 60 miles to the southwest in Nikiski, on the Kenai Peninsula. The environmental groups in their 142-page request for a rehearing argued that the federal environmental impact statement was deficient, particularly in how it addressed air emissions and damage or loss of wetlands. Though the federal agency had no comment in declining to act on either appeal, the Alaska Gasline Development Corp., which has been leading the venture the past four years, in a July 17 filing with FERC referred to the Center for Biological Diversity’s claims as “overbroad and unsupported … where intervenors mischaracterize the record and/or the law.” In the same filing, AGDC said the Matanuska-Susitna Borough “misconstrues facts” in its challenge to the federal decision. The final environmental impact statement, released in March, affirmed the project team’s preferred option to build the LNG terminal in Nikiski. FERC commissioners on May 21 authorized the Alaska LNG project, adopting all of the findings and decisions in the final EIS. Separate from legal maneuvering by challengers to the FERC decision, the AGDC board is working with a new price tag for the project, estimated at $38.7 billion following a 14-month review by a third-party engineering and construction firm. The latest cost estimate, presented to the board June 25, is down about $5 billion from the previous number but is still substantially higher per tonne of output capacity than most other LNG projects proposed worldwide. Multiple Alaska North Slope natural gas development projects have been in various proposal and permitting stages for 50 years, all failing to advance due to no viable market for the gas or uneconomic project numbers. The state took over the latest LNG project in 2016 when North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips cited weak economics in withdrawing as participants. The project, as authorized by FERC, would include 62 miles of pipeline from the Point Thomson field to Prudhoe Bay, a gas treatment plant at Prudhoe to remove carbon dioxide from the gas stream for reinjection into the reservoir, and 807 miles of pipeline through the state and across Cook Inlet to the liquefaction plant and marine terminal in Nikiski. The AGDC board is looking to get the state out of the role as project leader for the economically challenged venture. The board does not support the state continuing as the sole project sponsor past Dec. 31, and plans to “put the Alaska LNG project assets up for sale” in a formal bidding process if no one steps up to take over as lead developer. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

AK LNG economics still challenged at lower cost

An updated cost estimate for the state-led Alaska LNG Project has trimmed about $5 billion from the construction price tag, down to $38.7 billion. Though the new estimate, released at the Alaska Gasline Development Corp.’s June 25 board meeting, is 12 percent less than the number of several years ago, it’s still significantly higher per tonne of output capacity than most other proposed LNG developments around the world. At $1,900 per tonne for the project’s designed capacity of 20 million tonnes per year, the cost is higher than Qatar’s expansion plans to add almost 50 million tonnes per year to its world-leading output (at $1,000 per tonne), Russia’s Arctic LNG projects (around $1,100 a tonne, with substantial government assistance), expansion of Papua New Guinea’s capacity (under $1,500), or either of three LNG export projects in the works for Mozambique ($1,500 to $2,000). In addition, building a North Slope gas treatment plant, an 807-mile pipeline through the state, and a liquefaction plant and marine facilities at Nikiski would be substantially more expensive per tonne of output than any of the export terminals in operation, under construction or proposed for the U.S. Gulf Coast, generally running $500 to $1,000 per tonne. The cost depends whether the export terminal is an add-on to an underused LNG import facility, expansion of an existing liquefaction and export terminal, or a greenfield project. Capital costs, along with price of feed gas, operating expenses and shipping, drive the economics of LNG export ventures in a highly competitive global market. Some of the LNG projects built over the past decade have come in higher than Alaska’s latest cost estimate, such as the Ichthys project, a gas field offshore Australia that sends its production through a 553-mile subsea pipeline to an onshore LNG plant. Delays and cost overruns drove the cost per tonne to more than $2,000 by the time the first cargo left the dock in 2018. But a significant economic salvation for the Japanese-led project is that at peak production, Ichthys will produce 150,000 barrels a day of high-value condensate and liquid petroleum gas (butane and propane) from the field. The flow from Alaska’s Prudhoe Bay field, which would feed three-quarters of the gas for the project’s initial supply, would be dry gas, as most of the rich liquids have been stripped out and shipped down the Trans-Alaska Pipeline System over the decades, adding to producer and state revenues. Where Alaska has a cost advantage over several other LNG suppliers is its shorter shipping distance to North Asia markets. It’s about 5,000 sea miles from Nikiski to Tianjin, China, the country’s busiest import terminal this year, versus 6,500 miles from Qatar, about 7,300 miles from Mozambique, and 10,000 miles with a Panama Canal crossing from the U.S. Gulf Coast. The state-owned Alaska Gasline Development Corp., which has been leading the development since North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips cited weak economics in withdrawing as participants in late 2016, has worked the past 14 months with contractor Fluor Corp., and with help from BP and ExxonMobil, to refine its plans toward reducing construction costs. Texas-based Fluor is experienced in LNG plant construction. It’s part of a joint venture that was awarded the engineering, fabrication and construction contract for the $30 billion (U.S.) Shell-led LNG Canada project under construction in Kitimat, British Columbia, about 100 miles southeast of Alaska’s southern border with Canada. The Kitimat project is estimated to cost just more than $2,000 per tonne for its first phase, with tentative plans for a lower-cost expansion that would improve the project’s overall economics. The development includes a 416-mile pipeline to deliver gas from producing fields in the far northeastern corner of British Columbia. The Alaska LNG cost estimate does not include the additional expense of building out gas production at Point Thomson, which would feed about one-quarter of the project’s initial gas supply. The field operator, ExxonMobil, has not publicly disclosed the development costs for expanding Point Thomson beyond its current capacity of up to 10,000 barrels a day of condensate while reinjecting the gas into the reservoir. Designing and building multibillion-dollar LNG projects can be a risky business for contractors. McDermott International, which built the Cameron LNG project in Louisiana for a Sempra-led venture, filed for bankruptcy protection in January. Its financial struggles included cost overruns and delays at Cameron, which shipped its first cargo last year. Houston-based KBR, with contracts in hand to build proposed LNG terminals in Texas, Louisiana and Nova Scotia, announced June 22 it will exit most of its LNG construction business, focusing instead on the financially safer work of government contracting. It will “no longer engage in lump-sum … construction services,” KBR said, adding that the COVID-19 pandemic accelerated its decision to leave fixed-contract energy projects. Looking to get the state out of the role of project leader for the cost-challenged Alaska project, the AGDC board at its April meeting adopted a strategic plan that calls for finding a private developer or team of developers to take over from the state as lead on the venture. The board of directors “does not support” the state continuing as the sole project sponsor past Dec. 31. LNG in Asia has been selling at record lows of less than $2 per million Btu on the spot market this spring and early summer, about one-third the peak of last winter and far below the cost of gas supply and transport for U.S. Gulf Coast LNG to make any money. Those prices would have to more than triple to cover the cost of LNG from Alaska. And though prices in Asia were close to that level at their high point last winter, improved prices would help every other proposed LNG development worldwide, not just Alaska. Additional supplies from projects on the Gulf Coast and Australia, along with weakened demand due to the worldwide coronavirus-induced economic slowdown, have left the market awash in too much gas, with analysts speculating when demand might return and when new supplies might be needed. If the state corporation cannot find someone interested in taking over the venture, it would “put the Alaska LNG project assets up for sale” in a formal bidding process, according to the staff presentation at the April 9 board meeting. AGDC staff told the board at the June 25 meeting that the cost savings under the updated estimate came from lower market prices for equipment, better strategies for contracting, more efficient liquefaction technology and reduced risks that allow a smaller contingency. Staff also told the board that if the old $44 billion estimate were adjusted for inflation to match the 2019 dollars of the new $38.7 billion projection, the comparable savings would be slightly more than $8 billion. Staff further explained to the board June 25 that additional cost savings in annual operating expenses could be achieved by reducing the project’s payments to cities and boroughs promised in lieu of property taxes. Federal loan guarantees could lower the cost of borrowing money to build the project, staff said, though congressional approval would be required if the intent is to amend a 2004 law that provided such guarantees only for an Alaska project that delivered gas to the Lower 48 states. While confronting the economic realities of Alaska’s decades-long dream for a North Slope natural gas project, AGDC also faces two challenges to its federal authorization for the LNG project. The Matanuska-Susitna Borough on June 19 filed a request for a rehearing with the Federal Energy Regulatory Commission, which approved the Alaska project on June 6. The borough has spent the past several years advocating that its property at Port MacKenzie, across Knik Arm from Anchorage, is a better site for the LNG plant than Nikiski, about 60 air miles to the southwest on the Kenai Peninsula. The Matanuska-Susitna Borough has asked FERC to rehear its action and order a supplemental environmental impact statement to correct alleged errors in the review that unfairly handicapped consideration of Port MacKenzie. The project team selected Nikiski in 2013, a decision which the borough has criticized as based on bad information. Three days after the Mat-Su filing, the Center for Biological Diversity and Earthjustice filed a 142-page request for a rehearing, alleging “FERC approved the project without properly considering whether it is in the public interest and without properly examining its numerous harmful environmental impacts.” The environmental groups filed the request on behalf of the Sierra Club, the Northern Alaska Environmental Center, and the Chickaloon Village Traditional Council. Among the issues cited in the filing, the groups criticized FERC for not considering the project’s impacts on North Slope gas production and the greenhouse gas emissions from increased production and consumption of natural gas. The environmental groups and the Matanuska-Susitna Borough are official intervenors in the FERC docket, and only intervenors can request a rehearing and, if unsuccessful, take the matter to federal court. Under FERC regulations, if the commission fails to respond to a request for a rehearing within 30 days, the request is denied. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

Mat-Su Borough keeps up fight over LNG site

The Matanuska-Susitna Borough has asked the Federal Energy Regulatory Commission to redo the final environmental impact statement and reconsider its decision for the proposed Alaska LNG Project, correcting what the borough alleges are factual errors and deficiencies that prevented fair consideration of municipally owned Port MacKenzie property for the gas liquefaction plant and marine terminal. “The order is based on a procedurally and substantively deficient final environmental impact statement, is in violation of the National Environmental Policy Act … and therefore does not provide the commission or the public with all relevant information for the Alaska LNG Project,” the borough said in its June 19 motion for a rehearing, filed by the municipality’s contract attorneys in Washington, D.C. The final EIS “does not contain a full analysis of the environmental impacts associated with the Port MacKenzie alternative,” said the borough, which has long promoted the property across Knik Arm from Anchorage for industrial development. The borough asked FERC to prepare a supplemental EIS and then, after a fair review of the Port MacKenzie alternative for the LNG terminal, issue an amended order based on the updated EIS. The final EIS, issued March 6, accepted Nikiski, on the Kenai Peninsula, as the project’s preferred site for an LNG terminal at the end of an 807-mile gas pipeline from the North Slope. On May 21, FERC issued an order granting authority to the Alaska Gasline Development Corp. to proceed with the development after numerous other permits and regulatory requirements have been met. The Matanuska-Susitna Borough is one of several intervenors in the FERC docket, along with the Kenai Peninsula Borough, which has defended the choice of its own community, Nikiski, and the city of Valdez, which has promoted its community as the better alternative for the LNG terminal. Only an intervenor may file a motion for a rehearing with FERC. If an intervenor is not satisfied with the outcome of a rehearing request, its next option would be to file in federal court. The municipalities are arguing over a state-led multibillion-dollar development effort that lacks equity partners, construction financing and LNG customers, with uncertainty over whether the project is even economically viable. AGDC, the state corporation created 10 years ago to support development of North Slope natural gas resources, is looking for someone else to take over the project that it has shouldered alone for almost four years after ExxonMobil, BP and ConocoPhillips elected not to proceed with the FERC application. AGDC filed the project application with FERC in April 2017. After receiving the final EIS, the corporation in April adopted a strategic plan that calls for removing the state as the sole project sponsor by Dec. 31. If AGDC cannot interest anyone in taking over the lead and helping to pay the bills, the corporation plans to “put the Alaska LNG project assets up for sale” in a formal bidding process, according to a staff presentation at the April 9 board meeting. The corporation has the authority under state law to sell the project assets. In the past decade, AGDC has spent about $460 million toward engineering and permitting work for the LNG export project and the smaller, so-called “backup” plan of a $10 billion North Slope gas project to serve Alaska, without an LNG component. The corporation board is scheduled to meet June 25 and is expected to review updated cost projections for the project, last estimated three years ago at $43 billion for the gas liquefaction plant and marine terminal, a treatment plant at Prudhoe Bay to remove carbon dioxide and other impurities from the gas stream, the main pipeline to Nikiski, and 62 miles of pipeline from the Point Thomson field to Prudhoe Bay. Though global demand for LNG had been on the upswing, the coronavirus pandemic and subsequent economic shutdowns worldwide have cut deeply into demand for the fuel, with 2020 expected to come in below 2019 levels. It would be the first year of demand shrinkage in more than a decade. Even before the coronavirus shutdowns, an oversupply of LNG had brought down prices to record lows in Asia and Europe this year, with investment decisions postponed for several projects on the U.S. Gulf Coast, in Mozambique, Canada and elsewhere. “We don’t see any additional North American export capacity getting sanctioned in the next decade,” Ross Wyeno, an LNG analyst at S&P Global Platts, said last month. In its motion to FERC, the Matanuska-Borough said the EIS “erred by defining the project’s objectives so narrowly that only the applicant’s preferred site for the liquefaction facility (Nikiski) could fulfill them.” The borough alleged, “As a result, the commission did not take a ‘hard look’ at the Port MacKenzie alternative or any other liquefaction facility site alternative.” The borough has battled with AGDC for the past three years, arguing that the state corporation failed to adequately consider Port MacKenzie. In December 2017, the borough alleged that AGDC and FERC 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 LNG plant. The project leadership team selected Nikiski in 2013, when the venture was led by the three major North Slope producers. In its June 19 filing with FERC, the borough again reiterated its past claims that the EIS “contains substantive errors and selective data gaps,” in particular overstating the volume of dredging required for vessel traffic to access the site across from Anchorage, and misrepresenting issues of air quality, wetlands, winter ice conditions, pipeline connections for gas distribution in Alaska, and whether building the LNG plant at Port MacKenzie instead of Nikiski would cause shipping delays. “The order is based upon a ‘bald assertion’ that ‘the Port Mackenzie alternative would not provide a significant environmental advantage over the proposed Nikiski site,’” the borough said. In the case of pipeline interconnections to pull out gas for use in Alaska, the borough argues that could be accomplished with the Port MacKenzie alternative and “there is no inherent reason why one of these interconnections needs to be located” at the Nikiski site. The borough’s motion concluded: “At a minimum, FERC must revisit its analysis of the Port MacKenzie alternative and include all information necessary to understand how its environmental impacts compare to Nikiski. Failure to do so not only violates the National Environmental Policy Act, but also would constitute an arbitrary and capricious decision.” While the borough continues its fight at FERC, other federal regulatory agencies are continuing their review of the project and issuing opinions of environmental impacts. The U.S. Fish and Wildlife Service on June 17 issued its Endangered Species Act biological opinion of the project’s impacts, matching up with the analysis in the final EIS. “The service has determined the proposed action may affect, but is not likely to adversely affect Alaska-breeding Steller’s eiders, short-tailed albatross, northern sea otters, or designated critical habitat for Steller’s eiders and northern sea otters. The service has also determined the proposed action may adversely affect spectacled eiders and polar bears. “Following review of the status and environmental baseline of spectacled eiders and polar bears, and analysis of potential effects of the proposed action to these species, the service has concluded the proposed action is not likely to jeopardize the continued existence of spectacled eiders or polar bears, and is not likely to destroy or adversely modify designated polar bear critical habitat.” ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He can be reached at [email protected]

State seeks new sponsor for AK LNG, or it will sell off the assets

The state corporation that has been leading the proposed multibillion-dollar Alaska North Slope natural gas project since late 2016 wants someone else to take over the development effort. The corporation’s plan assumes that an economic analysis currently underway determines the project is economically viable. If no one steps up to take over from the state, which has been paying just about all the bills the past four years, the Alaska Gasline Development Corp. board of directors appears ready to sell off the project’s assets — which could include permits, studies and engineering work — in a formal bidding procedure. The first step in the unfolding process is an update to the 3-year-old $43 billion cost estimate for the Alaska LNG project that would transport North Slope gas through more than 800 miles of pipeline to a liquefaction plant and marine terminal in Nikiski. Fluor, a 108-year-old global engineering and construction company, is under contract to AGDC to prepare the update. The state corporation expects to receive Fluor’s numbers later this month and, after review by its own team, will present them at its June board meeting. Fluor, based in Texas, is experienced in LNG plant construction. It’s part of a joint venture that was awarded the engineering, fabrication and construction contract for the $30 billion Shell-led LNG Canada project under construction in Kitimat, British Columbia, about 100 miles southeast of Alaska’s southern border with Canada. The AGDC board on April 9 approved a resolution adopting a strategic plan to direct state involvement in the Alaska LNG project through June 2021. The document itself is confidential, but the board reviewed in public session the underlying assumptions of the plan. • The updated cost estimate is complete by June. AGDC has been working — with help the past year from BP and ExxonMobil — to reduce construction costs in hopes of making the project economically viable, and has talked up Fluor’s upcoming estimate as potentially validating its work. Project construction and operation costs, and the price of gas going into the liquefaction plant, are the biggest drivers of the final sales price for the LNG. • The next assumption is that the cost update and economic analysis show the project “has a potential to deliver LNG to markets at a competitive price.” The state has been looking to Asia as the best market for Alaska gas. Though current spot-market and long-term contract prices in an oversupplied Asian market are far below break-even costs for an Alaska LNG venture, they could increase later this decade if demand returns to a strong growth rate. But competition from other suppliers will be intense. • The plan assumes that whichever partner(s) step forward to take over as lead sponsor will “recommend moving forward with further development of the Alaska LNG project.” • The Federal Energy Regulatory Commission stays on schedule and approves the Alaska project. The commission issued its final environment impact statement in March and is due to vote in early June on AGDC’s application to construct the gas treatment plant at Prudhoe Bay, the pipeline, LNG plant and marine terminal. FERC does not consider a project’s economic viability — only its environmental impact and safety issues. The assumptions that went into the strategic plan also included a timeline for the state to get out as lead sponsor of the project. That included: • AGDC will continue looking for partners, and a transition to a new project sponsor will be underway by Jan. 1, 2021, as the AGDC board of directors “does not support” the state continuing as the sole project sponsor past Dec. 31, 2020. • The board, working with the Legislature and the administration of Gov. Mike Dunleavy, “will define an acceptable role, if any,” for the state in the project. • If “there is not sufficient interest from strategic parties” to lead the development effort, AGDC will publicly solicit interest from others to take over the project. • And if that doesn’t attract a new leader for the project, “AGDC will put the Alaska LNG project assets up for sale” in a formal bidding process, according to the staff presentation at the April 9 board meeting. The corporation has the authority under state law to sell the project assets. The approximately 600 acres for the LNG terminal in Nikiski, however, is not owned by AGDC. ExxonMobil, BP and ConocoPhillips bought the privately owned parcels several years ago — when the companies were leading the effort — and the state never reached a deal to take control of the property. After the three major North Slope oil and gas producers declined in late 2016 to spend more money on the Alaska LNG project, AGDC took over as lead, funding the application process and environmental review at FERC. The producers cited economic reasons in their decision to opt out of the development effort. In the past decade, the Alaska Legislature has appropriated almost $480 million toward the LNG project and the smaller, so-called “backup” plan of a $10 billion North Slope gas project to serve Alaska, without an LNG export component. Most of the state money was spent on engineering and permitting for that Alaska Stand Alone Pipeline, or ASAP. Between the two projects, the corporation has spent about $460 million of the state appropriations. ExxonMobil and BP have been contributing to the Alaska LNG effort the past year, limiting their spending to no more than $10 million each toward finishing the FERC process and other work. As the work on the FERC-led environmental statement is nearing its finish, AGDC’s spending has slowed down. The corporation spent about $9.5 million in the first nine months of the fiscal year that ends June 30. The corporation has legislative authorization to use its available funds through the end of the next fiscal year in June 2021. Dunleavy, now about 18 months into his four-year term, has steadfastly advocated that the state step away from leading the effort and look for private companies to take over the LNG project. Just as the larger, export-driven project has been unable to pass the economics test in a highly competitive global marketplace, so too has the ASAP line proven to be unaffordable for the small in-state market. Among the assumptions that went into AGDC’s strategic plan is the statement that the ASAP project “has been determined to not be economically viable.” The Legislature created the state corporation in 2010 in hopes of developing a North Slope gas project (the ASAP line) to reduce Southcentral Alaska’s dependence on Cook Inlet natural gas supplies, which had become uncertain as producers stopped exploring for new supplies. Legislators’ hopes also included getting North Slope gas to Fairbanks. Since then, Cook Inlet legacy producers pulled out of the basin and sold their assets to Houston-based independent Hilcorp, which invested heavily in production to meet local needs and now produces more than 80 percent of Southcentral Alaska’s gas supply.

GUEST COMMENTARY: State-owned oil company is a bad idea

Watching the collapse in oil prices, the gaping hole in state revenues, the cutbacks in oil company spending on new production — and the likelihood that Alaska’s future will suffer under all of the above — some suggest state government should step up to the drilling rig, put on a hard hat and get to work. It’s time that the state become a real owner, they say, just like ExxonMobil and ConocoPhillips. Just like BP has been for almost 60 years on the North Slope. The low-price opportunity awaits Alaska, they say. Watching Hilcorp struggle to raise the billions it needs to buy up BP’s Alaska assets while the collateral for the loan — the oil in the ground — isn’t worth nearly as much as it was last year, some say the state should step in front of Hilcorp, borrow and invest to pick up BP Alaska on the supposed cheap. Haven’t we learned anything in 40 years of well-intentioned but ill-conceived state investments based on the unproven theory that if we own it, the profits will come? Does anyone think this time will turn out any different? Supporters of state investment, state ownership and state control like to point to Norway, which is rich beyond Alaska’s wildest dreams. But the Norwegian government poured billions of dollars into covering its equity stake, its share of exploration and development expenses for years before ever starting to earn a serious profit a decade later. Can Alaska afford to gamble today, betting that profits may flow in 2025, 2030 and beyond? Does the state have any money to invest? Oil companies, such as ConocoPhillips and Oil Search, both active in North Slope exploration, use their profits from ongoing operations to fund new developments. They spend today’s cash flow for tomorrow’s investments. If you look at the state checkbook, there’s not enough cash coming in these days to cover next year’s schools much less investments in next year’s drill pipe. And why, if Hilcorp, with hundreds of thousands of barrels a day of actual oil and gas production spread across several fields in several states, and with years of profitable operations, is having trouble signing the deal with hesitant bankers, what makes Alaskans think that the state, with years and years and years of budget holes, with no general tax revenues, with constant political pressure to pay out an unaffordable dividend to its residents, would be able to raise billions of dollars against the same devalued oil in the ground. The state’s credit rating is OK for now, but only because the rating agencies believe we will do the right thing and raise new revenues, protect the Permanent Fund and not overspend. Turning around and borrowing billions on a bet that the state knows more than anyone else which way oil prices are heading, that the state knows the future of oil production, and that the state knows a good deal when it sees one, is sure to cause the rating agencies to wonder whether a piece of drilling pipe fell on our heads. Sure, instead of borrowing all the money to buy up BP Alaska, the state could write a check on the Permanent Fund. But due to investment losses from the crashing stock market, the fund’s earnings reserve already is in danger of falling too low to help pay for schools and other public services next year. This is not the time to overdraw the account. Instead of doubling and tripling down on oil as the sole savior of Alaska’s finances, the state should be looking to diversify our public revenues. Or we could play the slots in Vegas. Makes as much sense as an overly oil-dependent state betting solely on oil, more oil and nothing but oil. No offense to oil. Larry Persily is a longtime Alaska journalist, with breaks for federal, state and municipal service in oil and gas and taxes, including deputy commissioner at the Alaska Department of Revenue 1999-2003.

Global oil storage capacity shrinks amid supply glut

As Saudi Arabia and Russia — and even U.S. shale producers — pump more oil than the world needs, the price for crude is dropping while the price for storing all that excess oil is rising. There are worries that demand for storage will overwhelm capacity. “I don’t see how you don’t exhaust global storage capacity, if this goes on until summer at the production numbers talked about,” Jeffrey Currie, head of commodities research at Goldman Sachs Group told Bloomberg. “We believe … the market will soon come to realize that it may be facing one of the largest supply surpluses in modern oil-market history in April,” said Bjornar Tonhaugen, head of oil markets at Rystad Energy, an Oslo-based research and business intelligence company. Until supply and demand come back into balance, the oil will keep stacking up worldwide. Traders and buyers are storing cheap crude for consumption when they need it later, or in hopes of an eventual profitable resale. The price for a barrel of Brent, the global benchmark crude (which North Slope oil tracks), has crashed from about $68 at the start of the year to about $28 at the start of trading March 23 as Russia and Saudi Arabia out-produce to see which one wins. Global supply was already expected to exceed demand this quarter by 3.5 million barrels per day, according to the International Energy Agency. And that number will get a lot bigger after March 31, when OPEC member nations further boost their output as production limits expire. “We could have global market oversupply of over 10 million barrels per day. Which is insane and unprecedented,” Abhi Rajendran, director of research at Energy Intelligence, told CNBC on March 16. IHS Markit, a global energy research and analysis firm, forecasts the same oversupply of up to 10 million barrels per day, adding as much as 1.3 billion barrels to storage by the end of June. Bloomberg has an even bigger number. If the market fight between Russia and OPEC continues, and the COVID-19 world economic collapse extends into later in the year, Bloomberg calculated that global crude inventories could grow by 1.7 billion barrels. Don’t look for Saudi-led OPEC to blink first. “Any large political power sometimes needs to remind its adversaries and competitors of its might. We believe Saudi Arabia seeks to teach the market a lesson,” Rystad’s Tonhaugen said in a posting on the company’s website March 18. Global oil storage could fill up within four months, Antoine Halff, the chief analyst of Paris-based consultancy Kayrros, told The Wall Street Journal. Kayrros tracks global storage by using satellite imaging. About 65 percent of the world’s total 5.7 billion barrels of oil storage is currently in use, according to Kayrros. At current fill rates, oil could reach the top of the tanks and caverns in just over a year, the company estimates. “The fill rate that we are experiencing now is totally unprecedented,” Halff said. The oil hub in Cushing, Oklahoma, is home to about 15 percent of the U.S. commercial storage capacity, or almost 80 million barrels. The tanks were about half full a week ago — and filling up. Storage rates at Cushing doubled over the past month and were running as high as about 50 cents per barrel per month, Reuters quoted two traders. “Everyone and their mother is scrambling to fill up tankage,” a trader said. The federal government’s Strategic Petroleum Reserve in salt caverns in Texas and Louisiana can hold about 750 million barrels and was storing about 635 million barrels as of early last week. Though 115 million barrels may sound like a lot of spare capacity for U.S. shale oil production, it’s not. About two-thirds of the Strategic Petroleum Reserve capacity is designated for sour crude — with a sulfur content greater than 0.5 percent. But the crude pumped from the shale rock of West Texas and other shale basins has very low concentrations of sulfur, if any, and the sweet crude is not suitable for blending with sour crude. Different caverns are designated for the different crudes. The caverns for low-sulfur, or sweet crude, had room a week ago for about 25 million barrels, while the sour-crude caverns had room for an additional 95 million barrels. Other countries, notably South Korea, also have large onshore oil storage tank farms. But those are filling up, too, pushing traders and buyers to look to sea to park their crude. Reuters reported March 10 that tanker rates are surging as traders need a place to store their cheap oil. The cost of renting a very large crude carrier, or VLCC, which can hold 2 million barrels of crude, was quoted March 10 at more than twice what it was a month ago, ship brokers told Reuters. Other news sources were reporting even steeper rate hikes last week. “We are seeing several deals being negotiated for short-term (6 to 12 months) charters. … The fall in oil prices has made floating storage more attractive, although the margins are still relatively thin,” shipbroker and consultancy Poten &Partners said in a research note. The margin being whether buyers can pay the costly storage fees and still turn a profit. As the charter rate climbs for the biggest ships — whether for storage or to deliver cheap Middle East crude to refineries — a growing number of Asian oil buyers are looking to smaller vessels to save money. Bloomberg reported that the rate hikes for smaller tankers were much less than the boost in VLCC rates. Too much oil and not enough capacity to move it to market has been a growing problem in landlocked Alberta, with its growing oil sands production is outpacing the ability to get new pipelines built. The provincial government has been limiting oil production the past year in an effort to hold down oversupply and boost prices, and now says it might mandate further cuts if rising supplies and falling prices threaten the survival of companies. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Price war sends oil plunging amid virus selloff

If oil company executives don’t get sick from the coronavirus, the feverish drop in prices is likely causing them aches, pains and chills anyway. The good old days were not much more than two years ago when Brent crude, the global benchmark, was at $85 per barrel in October 2018, its highest point in six years. The bottom of the barrel started leaking and then completely fell out the past few days. Brent lost almost 10 percent on March 6 and then went into a freefall on March 9, losing an additional 24 percent — its steepest one-day slide since 1991 — closing at less than $35. The back-to-back days of double-digit drops are due to a progressive series of events: The economic hit from the coronavirus is reducing global demand for oil; the 3-year-old production-curbing deal between OPEC nations and Russia collapsed; and Saudi Arabia announced on March 8 it was boosting production and curbing prices, launching a price war with Russia. The Saudis are cutting prices by $6 to $8 per barrel for sales to Europe, the Far East and the U.S. in an effort to entice refiners to buy their crude instead of other supplies. “That’s the oil market equivalent of a declaration of war,” Bloomberg quoted a commodities hedge fund manager. “Saudi Arabia is now really going into a full price war,” Iman Nasseri, managing director for the Middle East at oil consultant FGE, told Bloomberg. Analysts see the Saudis wanting to inflict pain on Russia and other producers to bring them back to the negotiating table for production cuts. Meanwhile, Alaska North Slope crude is no longer commanding the $10 premium to U.S. benchmark West Texas Intermediate that it earned in late 2018 and early 2019. As world prices tank they are taking Alaska crude along with it, and North Slope oil is back around its more traditional $2 or $3 bump from WTI, which closed March 9 at about $31 per barrel. Alaska crude generally competes on the West Coast against foreign imports, not U.S. oil, due to the lack of pipelines to deliver the bounty of mid-continent shale over the Rockies to the coast. If the steep fall in prices holds throughout the year, the state of Alaska could lose out on several hundred million dollars of tax and royalty revenues. But there’s not much Alaska can do about it. Prices will depend mostly on Russia, OPEC, the coronavirus and its hit to the global economy. Moscow last week rejected a Saudi Arabia-led proposal to impose cuts of an additional 1.5 million barrels per day on the so-called OPEC+ member nations, on top of the current reduction of 2.1 million barrels per day that is due to expire at the end of March. The combined cutback would have taken about 3.6 percent of the world’s oil supply offline. Russia has less of an incentive to cut production to boost prices as its economy is more diversified and its treasury can get by on $50 oil, whereas the Saudis need significantly higher prices to cover their government spending. In response to Russia’s refusal to join the effort to further limit production, OPEC refused to extend the existing cuts past March 31. “We are in another period of true turmoil,” said Daniel Yergin, vice chairman of global energy analytics firm IHS Markit. Deciding whether and how much to cut supply during the coronavirus virus “really splintered the (OPEC+) alliance,” he said in a CNBC interview March 9. “This is an unexpected development that falls far below our worst-case scenario and will create one of the most severe oil-price crises in history,” Bjoernar Tonhaugen of Rystad Energy, was quoted by Reuters. “This is going to get nasty,” Doug King, a hedge fund investor who co-founded the Merchant Commodity Fund, told Bloomberg. “OPEC+ is going to pump more, and the world is facing a demand shock. $30 oil is possible.” But why stop the depressing predictions at $30 oil? “We’re likely to see the lowest oil prices of the last 20 years in the next quarter,” Roger Diwan, an oil analyst at consultant IHS Markit and a veteran OPEC watcher, told Bloomberg. It was just more than 20 years ago that Brent last fell to less than $20 per barrel. Though Russia did not signal any reconciliation, OPEC said it is willing to talk. “Hopefully they’ll come back,” said Suhail Al Mazrouei, United Arab Emirates’ energy minister. Adding to the supply-and-demand imbalance are continuing gains in U.S. oil output. Annual production in the U.S. set another record in 2019, surpassing 12 million barrels per day for the first time, a gain of 10 percent over 2018. U.S. output has more than doubled since the fall of 2012, due to booming shale production. The U.S. Energy Information Administration predicts 2020 will average more than 13 million barrels per day and more than 13.5 million in 2021. All that oil would be good if the world needed it, but that’s not the case. Goldman Sachs said last week. Goldman Sachs is the first major Wall Street bank to forecast that overall global demand will contract this year. Oil-market consultants Facts Global Energy and IHS Markit published similar warnings. It’s not that the decline forecasts are large: 150,000 barrels a day at Goldman and 220,000 barrels a day at FGE. But if it’s true, it would be only the fourth time in the past 40 years that demand has fallen from one year to the next. Goldman Sachs predicted demand will fall 2.1 million barrels a day in the first half of 2020, recovering somewhat in the second half. The price crash, however, may help stem the growth of U.S. oil production, as investors are increasingly reluctant to write checks. North American oil and gas producers have an estimated $86 billion of rated debt maturing in the next four years, according to Moody’s Investors Service, debt that will be harder to pay off or refinance at low prices — and harder to raise money for new developments. Still, there’s no shortage of opportunities in U.S. shale plays. Chevron on March 3 upped its Permian Basin resource estimate to more than 21 billion barrels of oil equivalent, more than double its estimate of just three years ago. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Oregon LNG export permit stymied again

For the second time in four years, the liquefied natural gas export terminal proposed for Coos Bay, Ore., failed to win approval from the Federal Energy Regulatory Commission. The $10 billion project may get another chance with the commission at its next meeting, but it’s only one of several hurdles for the developer, Calgary-based Pembina Pipeline. The state has rejected three of the project’s biggest permits; environmental opposition has grown over the years; and the Asian market for LNG is at record low prices. Maybe shareholders in Pembina knew something in 2017 when the company took over the Oregon project with its purchase of Canadian pipeline rival Veresen. Pembina’s stock price fell that day. The plan was that Pembina, an oil pipeline operator, would diversify into the gas pipeline and LNG business by buying Veresen. “This is the magic: we’ve become basin diversified, commodity diversified,” Pembina CEO Mick Dilger said in announcing the deal in May 2017. The magic didn’t work. The Jordan Cove Energy Project started more than 15 years ago as a proposed LNG import terminal, looking to feed growing North American demand for the fuel amid stagnant U.S. production. In 2009, Veresen, back then known as Fort Chicago, and its partners pipeline operator Williams Cos. and California gas and power utility PG&E Corp., received FERC approval to build and operate an LNG import facility. It was supposed to be operational in 2014. Before construction ever started, however, the U.S. shale drilling boom ignited, putting an end to the gas import project. Like so many other unneeded LNG import terminals on the U.S. East and Gulf coasts, Veresen turned its attention to making Jordan Cove an export project. The company applied to FERC in 2013. The liquefaction plant would have capacity to produce 7.5 million tonnes per year of LNG. Up to 1.2 billion cubic feet per day of feed gas would be delivered by a 229-mile-long, 36-inch-diameter connector line from the California border across Oregon to the coastal terminal in Coos Bay. At full operation, the terminal would send out 10 LNG carriers per month. But in March 2016, avoiding a decision on environmental issues, FERC denied the application; specifically, the pipeline. Lacking any firm customers for the LNG, Veresen had failed to convince regulators that the pipeline was needed. The public benefits of a commercially unproven project were insufficient to overcome the actual harm to property owners along the pipeline route. Unlike LNG export terminals, which undergo no such public-interest test at FERC, regulated pipelines that are part of the nationwide grid are required to show a need for the line. Looking for a favorable decision under the new administration of President Donald Trump, the project reapplied to FERC in September 2017. In hopes of passing the public-interest test this time, the developer announced it had secured agreements to sell LNG in Asia, although they were non-binding deals. FERC’s final environmental impact statement for the project, issued in November 2019, said, “constructing and operating the project would result in temporary, long-term and permanent impacts on the environment. … (and) some of these impacts would be adverse and significant.” However, the final EIS said, “Many of these impacts … would be reduced to less than significant levels with the implementation of proposed and/or recommended impact avoidance, minimization and mitigation measures.” Good enough for FERC but not for Oregon state regulators. The state Department of Land Conservation and Development this month rejected a key permit, deciding that the LNG terminal would have significant adverse effects on the state’s coastal scenic and aesthetic resources, endangered species, critical habitat, fisheries and commercial shipping. Only a member of the president’s Cabinet could overrule the permit denial, the state said. State land agency director Jim Rue said neither FERC nor the Army Corps of Engineers “can grant a license or permit for this project unless the U.S. Secretary of Commerce overrides this objection on appeal.” It was the third state denial for Jordan Cove, adding to rejections of a water quality permit by the Department of Environmental Quality and a dredging permit by the Department of State Lands. “Three strikes and you’re out!” Ashley Audycki, a Coos Bay organizer for the environmental group Rogue Climate, said in a news release the day of the land agency’s denial. “Jordan Cove LNG has failed to obtain three critical permits from the state of Oregon. Jordan Cove LNG has no viable path forward.” Oregon Gov. Kate Brown in January said she “would consider all available options to safeguard the health and environment of Oregon” if the federal government ignores state permitting processes. Pembina in January pulled its application for a state permit for dredging, removal and fill work for the pipeline and LNG terminal, saying it would wait on FERC action. That decision came Feb. 20, when FERC commissioners voted 1-2, declining to approve the Jordan Cove application. Trump has failed to fill two vacant seats on the five-member commission. “I’m disappointed that we were not able to vote out Jordan Cove today, but I respect my colleagues’ need for more time,” said FERC Chairman Neil Chatterjee. “I want to reassure people that today’s vote is not a denial of Jordan Cove’s application. The application remains pending before the commission and we will vote on this matter when we are ready,” Chatterjee said. FERC Commissioner Bernard McNamee, who joined with Commissioner Richard Glick in voting no, said his vote was “not a hard ‘nay,’” and was based in part on the state’s determination that the project is not consistent with Oregon’s Coastal Management Program. “I want to see what the state of Oregon said, and I need that information to inform my decision about whether I’m ultimately going to vote for or against Jordan Cove,” said McNamee, who was quoted by the Natural Gas Intelligence newsletter on Feb. 20. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Gazprom pipeline to China looks far from profitable

Russia has started sending natural gas from Siberia through a multibillion-dollar pipeline into northeast China, but several analysts believe the project will not make a profit for a long time. “All in all, the Power of Siberia is a big image-building stunt for Russia, but not a profitable commercial project, and it translates into a net loss for state-controlled Gazprom,” Mikhail Krutikhin, a co-founder and partner of RusEnergy, a Moscow-based independent analytical agency, said in a December opinion piece in Al Jazeera. “The project is unprofitable, even though the (Russian) government has exempted it from the mineral extraction tax and property tax,” Krutikhin said. Stunt or not, Gazprom reportedly is spending upwards of $55 billion for close to 2,000 miles of pipe and gas field development costs. It’s part of Russia’s turn toward building relationships — and energy sales — with China as it faces growing competition from renewables and U.S. LNG in Europe, its most profitable pipeline gas market,. “The geo-economic leverage that comes with a new energy pipeline is also not lost on Russia,” Ariel Cohen, a senior fellow at the Atlantic Council, wrote in Forbes magazine in December. Deliveries to China through the Power of Siberia line, which started up in early December, reportedly will average less than 200 million cubic feet per day during the first year, ramping up to full capacity of 3.6 billion cubic feet, or bcf, per day by 2025. That would represent more than 12 percent of China’s daily gas consumption last year. China already is an investment partner and customer of Russia’s Arctic Yamal liquefied natural gas project, which started shipping gas two years before the Power of Siberia went into service as Russia’s first gas pipeline connection with its neighbor. “In a nutshell, the Power of Siberia is a very costly window dressing … Until 2030, the Power of Siberia will not even pay off,” said Cohen, a founding principal of International Market Analysis, a Washington, D.C.-based global risk advisory firm. Besides, Gazprom “likely underestimated the market risks of dealing” with a single, state-controlled buyer such as China, Cohen said. Dmitry Marinchenko, lead analyst for oil and gas at Fitch Ratings, said the pipeline’s profitability will largely depend on the price China pays for the gas — a dynamic subject to the whims of global energy markets. “Considering that oil and gas prices will likely remain relatively low for the foreseeable future, there is a high chance the project won’t pay off,” said Marinchenko, quoted in an Asia Times report Feb. 5. “Strengthening relations with China and diversifying export routes are the main rationales behind Power of Siberia,” he said. In addition, long-term gas supply for the pipeline is an issue, Krutikhin said. The Chayanda field in Yakutia region, currently the only source of gas for the pipeline, can produce just two-thirds of what is needed to fill the line. “To reach full capacity, Gazprom has to develop another large field, Kovykta, in the Irkutsk region some 500 miles south of Chayanda, and connect it to the Power of Siberia with another pipeline, which has not been built yet,” Krutikhin said. Developing the Kovykta field could take a decade, he said. Besides for needing more investment in Russian gas fields, China needs to spend more to extend the pipeline farther into its larger demand centers. Currently, the piped gas only reaches northeastern China, which does not need 3.6 bcf per day of gas. Sending the gas into the industrialized Beijing-Tianjin-Hebei regions — much closer to LNG import terminals than Russian gas fields — would bring the pipeline gas into direct competition with seaborne cargoes, which have dropped to record low prices this winter in an oversupplied LNG market. Krutikhin, like Cohen, believes Russia may have overestimated its ability to extract a higher price and a profit from its sales to China. “Having a Chinese company as a single buyer of Russian gas at the far end of a very expensive pipeline is a big risk that erodes the possible commercial gains of the project,” Krutikhin said in his Al Jazeera piece. When Gazprom and China National Petroleum Corp. signed the 30-year gas sales deal in 2014, Russia asked China to help finance the development. China declined. “Because Russia will compete against other pipelines supplying gas to China, including from Turkmenistan and Myanmar, as well as against shipments of seaborne liquefied natural gas, China is in a favorable bargaining position,” Cohen said. China was importing close to 5 bcf per day of pipeline gas, even before the Russian line started up. The price China will pay for Russian gas still appears uncertain, or at least unknown outside the two countries. “The details have not been disclosed,” but Russia is asking for prices comparable with what it charges in Europe, and China would prefer to pay less, Krutikhin told Japan’s Nikkei Asian Review in December. Meanwhile, China holds another strong card at the negotiating table. Through its investment in Yamal LNG, Beijing is familiar with the cost structure of Russian gas operations. Sources told the Nikkei Asian Review that Beijing is leveraging what it has learned at Yamal in its pipeline gas price negotiations. Russia holds the world’s largest gas reserves and earned almost $50 billion from gas exports in 2018, according to the Russian Central Bank. The country’s leadership is counting on strong growth in gas exports both for the revenues and geopolitical influence. The significance of Power of Siberia beyond profits should not be underestimated, Sergey Kapitonov, gas analyst at the Energy Center of the Moscow School of Management Skolkovo, told the Asia Times this month. The project is a signal of increased energy cooperation between the two countries. Gazprom already is talking with China about two more pipelines to connect Siberian gas fields with other parts of the country that stretches more than 3,200 miles across. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Energy numbers in US-China trade deal don’t add up

Though China’s commitment to buy a lot more U.S. oil, liquefied natural gas and coal over the next two years supplied political headlines for the first-phase trade deal between the two countries, analysts generally dismissed the spending numbers — an average of almost $720 million per day — as unlikely to be achievable. Besides for China’s weaker economic growth that is softening its escalating demand for energy, the country has not relaxed its 5 percent tariff on U.S. crude oil imports or its 25 percent tariff on U.S. LNG. To meet the deal’s proclaimed goal of buying an additional $52.4 billion of U.S. energy in 2020-21, China would have to more than double its best months ever of U.S. crude, LNG and coal imports to reach the 2020 commitment of $18.5 billion and then almost double them again to hit the pledge of $33.9 billion in 2021. “The more you delve into China’s commitment to buy an additional $52.4 billion in U.S. energy over the next two years, the more it becomes apparent the goal is unachievable,” Reuters financial writer Clyde Russell said in a Jan. 20 opinion piece. If China were to buy enough U.S. oil to even approach the political commitment — perhaps more than 1 million barrels per day, more than double its biggest month ever — it would have to stop buying most of the light crude it gets from other countries, several analysts noted. And for a lot of China’s refineries, the light crude coming from U.S. shale oil plays is the wrong kind of oil; the refineries are optimized to process heavy, sour grades, such as those from the Middle East. “Not only would this disrupt global trade flows and relationships, it also raises the question as to whether Chinese refiners, and U.S. crude exporters, would want to become so reliant on each other, rather than having a diverse range of trading partners,” said Russell, with a quarter-century as a financial journalist. If China did reach 1 million barrels per day of U.S. crude, that would equate to about 25 percent of all U.S. oil exports the past two months. And what about China’s current oil suppliers that might lose market share to U.S. crude? “Would they simply roll over, or, more likely, try to protect their market share while going after U.S. customers outside of China?” Russell said in a commentary on Jan. 15, the day of the trade deal. “I know it’s stating the obvious, but $52.4 billion buys a lot of energy (equivalent to around 900 million barrels of crude oil at today’s prices),” Gavin Thompson, vice chairman for Asia-Pacific energy at global consultancy Wood Mackenzie, said in a Jan. 21 commentary posted on the company’s website. “And this is in addition to the $8.4 billion China spent on U.S. energy in 2017.” “Unlike China’s modest tariff on U.S. crude, the hefty 25 percent duty on U.S LNG imports is a deal breaker,” Thompson said. “China’s continuing radio silence on any future tariff removal for U.S. energy imports remains the most obvious,” he said. “Given these challenges, it’s likely that the reality of China’s purchases of U.S. energy will fall some way short over the next two years.” Though U.S. LNG production is growing, much of the capacity is already under contract and new projects cannot be built in time to meet the 2020-21 goals. “It just isn’t a good fit to presume that the phase one deal is a big win for LNG,” said energy analyst Katie Bays, co-founder of research and consulting firm Sandhill Strategy, as quoted by S&P Global Platts on Jan. 21. “The real bogey for the U.S. on the LNG side is if the trade deal somehow led to new contracts with LNG developers,” said the Washington, D.C.-based Bays. A real breakthrough would depend on “a comprehensive deal, removal of tariffs, and some indication that the Chinese would be willing to make a long-term bet on the United States,” Nikos Tsafos, a senior fellow at the Center for Strategic and International Studies in Washington, D.C. “At the end of the day, it is not like this is a big breakthrough for U.S. LNG exports or exporters or project developers,” Tsafos was quoted by S&P Global Platts on Jan. 21. Then there is the matter of trust. “After you started the trade war, you then need to convince the Chinese that you are a reliable long-term supplier on whom they have to base their energy security,” Tsafos said. No U.S. LNG has been delivered to China since March 2019, and long-term contracting between Chinese buyers and U.S. LNG developers has stalled. Several projects are holding off on final investment decisions until they can sign up enough customers. Meanwhile, spot-market prices for LNG delivered in Asia have fallen to less than $4 per million this month, and U.S. LNG just isn’t nearly as competitive as it was a year ago when the market was quoting $8 to $9. Even if China’s 25 percent tariff is removed, U.S. LNG would still be about $1.50 to $2.50 per million Btu more expensive than other available cargoes, analysts and traders said, Reuters reported a day after the U.S.-China trade deal. As long as U.S. gas is more expensive, importers would have to absorb the cost or pass it on to consumers, which could make Chinese state oil companies reluctant to commit to large-scale purchases, Wood Mackenzie’s Thompson said. Importers already lose billions of dollars per year on imported gas that costs more than the government allows them to charge their customers. All of which means the government will need “to remove, reduce or approve tariff exemptions before incremental LNG imports from the U.S. can be meaningful,” Jenny Yang, director of IHS Markit’s Greater China Gas, Power, and Energy Future Division, told Reuters. For LNG to cover one-quarter of the commitment for energy buys in 2020, China would have to take an average of one fully loaded LNG carrier every day. Analysts with energy consulting firm ClearView Energy Partners called that number “staggering.” China’s biggest month for U.S. LNG imports was January 2018, before the trade war escalated, when it took about seven cargoes all month. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Traders shrug off US-Iran tensions as oil prices drop

Though the U.S.-Iran tensions of missile strikes and Twitter threats stirred up a world of uncertainty the first days of the new year, global oil prices ended the week down. The hostilities did not escalate and geopolitical anxieties seemed to ease, while oil supplies are so ample that buyers just weren’t worried enough about next week’s or next month’s deliveries to push the price outside of the narrow trading band of the past 90 days. In fact, oil prices last week recorded their largest drop in nearly six months. “There is no dearth of crude oil in the global market,” India’s minister of petroleum, natural gas and steel said on the sidelines of a manufacturing conference Jan. 11, as reported by the country’s news media. Brent crude, the international benchmark price, has held between $59 and $69 per barrel since the first week of October. U.S. benchmark West Texas Intermediate has held between $53 and $63 during that same period. Brent moved up $3 the day after a U.S. drone strike on Jan. 3 killed a top Iranian military leader, but then lost almost $4 the week of Jan. 6-10, settling around $65. WTI behaved about the same, closing at $59 on Jan. 10. The oil-price weakness continued with a further 1 percent slippage on Jan. 13. S&P Global Platts Analytics reported Jan. 5 that it expects Brent will be “capped at $70 per barrel, unless a major source of supply is significantly damaged.” Goldman Sachs thinks even last week’s $65 Brent may be too high. Without a major supply disruption, look for prices to settle back to the bank’s “fundamental fair value of $63 a barrel,” Goldman reported in a note Jan. 6. Alaska North Slope crude last week was selling at a couple dollars above Brent. Absent a military or political escalation that cuts off supplies, there is plenty of oil; and global demand just isn’t growing enough to put pressure on prices. Besides, new supplies continue coming to market, even as OPEC and Russia hold back on their production in a bid to boost prices. Russia, however, knows how to count barrels to its advantage. Its deal with OPEC allows Russia to exclude its growing gas condensate production from its share of the group’s voluntary cutback. Add back in the condensate, also called natural gas liquids, and Russia’s total liquids production hit a record-high 11.25 million barrels per day in 2019, beating the previous mark of 11.16 million set a year earlier, Energy Ministry data showed Jan. 2, as reported by Reuters. Unrestrained by anything other than economics, U.S. oil production has been on a nonstop steep incline for a decade. The United States was producing about 5 million barrels of oil per day just a decade ago. A little more than two years ago, the U.S. was close to 10 million barrels. Now, analysts forecast the U.S. will hit 13 million barrels per day in 2020 as it strengthens its position as the world’s No. 1 oil producer. Most of it is from shale formations. Output from just the country’s seven largest shale basins totaled more than 8.5 million barrels per day last summer — up from less than 1 million barrels 10 years ago. Offshore fields are joining the record-setting output too. Production in the U.S. Gulf of Mexico last August exceeded 2 million barrels per day for the first time in history, the Interior Department’s Bureau of Safety and Environmental Enforcement announced Jan. 7. Look for at least an additional 100,000 barrels a day added to that total in 2020, the U.S. Energy Information Administration said in November. Several big offshore projects shifted into high gear last year. The Shell-led Appomattox project about 80 miles south of New Orleans began production last May, planned for 175,000 barrels per day when it reaches full production. China National Offshore Oil Corp. is a 21 percent partner in the project. In December, Chevron sanctioned Anchor, 140 miles offshore Louisiana in Green Canyon. It’s the industry’s first deepwater high-pressure development at 20,000 pounds per square inch to win a final investment decision, according to BSEE. The $5.7 billion project is designed for 75,000 barrels per day. As producers pump more than U.S. refiners can consume or need, all that oil has to go somewhere. The U.S. exported a record 4.46 million barrels of crude oil per day in the week ended Dec. 27, according to the Energy Information Administration. That would be enough to put the U.S. in second place in exports among OPEC nations. The numbers are up in Norway, too. The Johan Sverdrup oil field in the North Sea began operations in October and already is producing more than 350,000 barrels per day. Equinor, the field’s operator, expects Johan Sverdup to hit its target of 440,000 barrels per day by the summer of 2020, then rise further to 660,000 barrels per day after 2022. ExxonMobil on Dec. 20 said it had started up production at its Liza field offshore Guyana, expecting that the new operation will reach 120,000 barrels per day “in the coming months.” By 2025, ExxonMobil anticipates it will be up to 750,000 barrels per day from five floating, production, storage and offloading vessels operating in the block. It was a good year overall for offshore discoveries, said Norway-based research firm Rystad Energy. Rystad reported that companies discovered about 12.2 billion barrels of oil equivalent in 2019 — the highest since nearly 20 billion barrels in 2015 — from more than 25 discoveries of at least 100 million barrels each. Most of the new oil was found offshore, Rystad said. And Rystad believes that new discoveries in 2020 will exceed the volumes found last year. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

State submits last answers to FERC on Alaska LNG

With an additional 2,000 pages of charts, data, maps and explanations, the state-led Alaska LNG Project team finished out 2019 by answering the last batch of questions from federal regulators for the project’s final environmental impact statement. With less than two months to go before the Federal Energy Regulatory Commission’s scheduled March 6 release date for the final EIS, regulators could present additional questions to the Alaska Gasline Development Corp. As of a Dec. 23 filing, however, AGDC had answered all of the last questions submitted as recently as mid-November. Assuming no delay in the final impact statement, FERC commissioners could vote on the project application June 4. The state has been leading the effort since North Slope oil and gas producers declined in late 2016 to proceed to permitting for the economically challenged multibillion-dollar development, which includes a gas treatment plant at Prudhoe Bay, 870 miles of pipeline from the Point Thomson gas field to Prudhoe Bay and turning south through the state to the Kenai Peninsula, with a liquefaction plant and marine terminal in Nikiski. “As the government, we’re just right now standing back and just observing if there’s any project that can be economical,” Alaska Gov. Mike Dunleavy said in an early December interview with the Nikkei Asian Review in Japan. “If one of these projects, or another project that comes up … if that makes economical sense, that’s a good thing because we just want to monetize our gas,” Dunleavy said, referring to the state-led Alaska LNG Project and privately led Qilak LNG, which proposes to build a much smaller liquefaction plant several miles offshore the North Slope, avoiding the cost of a pipeline. “We have a lot of natural gas on the North Slope. We know that it has been stranded for years,” Dunleavy said. Qilak LNG is a subsidiary of Dubai-based Lloyds Energy, which has been looking to develop an LNG business since it was formed in 2013. The Qilak project — taking gas from Point Thomson but not Prudhoe Bay — initially would produce about one-fifth the volume of Alaska LNG, its sponsor said when it announced the proposed $5 billion venture last October. Qilak has not started the permitting process. Alaska LNG filed its application with FERC in April 2017. If it obtains FERC approval, AGDC would need to spend hundreds of millions of dollars on final engineering and design, land acquisition in Nikiski and get through multiple federal, state and municipal permits before it could make an investment decision. The governor, however, has said he is not interested in the state continuing to take the financial risk of leading the project. Without any partners, investors or financing for the estimated $43 billion Alaska LNG Project, and lacking firm gas supply contracts with North Slope producers or customers for the LNG, the state corporation could just hold on to the FERC authorization until — if — it is ever needed. In a project authorization, FERC will set a deadline to start operations — much like an expiration date for a building permit — though a developer can request an extension. In his proposed budget for the fiscal year that will start July 1, Dunleavy has requested legislative approval of $3.4 million in AGDC spending, down from a $9.7 million budget this year. While downsizing its staff from last year, the corporation said it would continue to look for a way to attract equity and debt financing of the project. “Outreach to potential partners is underway,” the corporation’s Jan. 3 budget write-up said. In addition to nearing the end of the review and approval process at FERC, the Alaska LNG team is working on other permits and regulatory authorizations such as a Bureau of Land Management right-of-way authorization for federal lands and a U.S. Army Corps of Engineers permit under the Clean Water Act and Rivers and Harbors Act. Public comments on the draft EIS closed on Oct. 3, despite several groups asking FERC to extend the comment period. The commissioner released the draft impact statement last June. In its December filings, AGDC provided further explanation of why it believes Nikiski is a better site for the liquefaction plant and marine terminal than Port MacKenzie, heavily promoted by the Matanuska-Susitna Borough that owns the property across Knik Arm from Anchorage. More ice, heavier currents, a wider tidal range and the challenges of LNG carriers transiting across the Knik Arm Shoal all make the Port MacKenzie site far less attractive than Nikiski, the state team told FERC. The borough has spent considerable effort submitting filings with FERC, rebutting the project team’s decision to stick with Nikiski. As an intervenor in the docket, the borough could challenge the final EIS or regulatory commission decision. Also in December, ADGC again listed for FERC the reasons why the corporation believes Anderson Bay at Valdez is an inferior alternative to Nikiski. The City of Valdez, similar to the Matanuska-Susitna Borough, has submitted multiple filings with FERC, seeking further review of its community for the LNG project and challenging AGDC’s numbers and conclusions. The Valdez site would require substantially more “excavation and disposal” than Nikiski to create a buildable project site out of the steep topography at Anderson Bay, AGDC said in its Dec. 23 answer to FERC. “Site preparation would involve blasting, excavating, grading and terracing to the site to create level surfaces for the facility.” Among the other information in December for the final EIS, AGDC provided: • More details of its “direct microtunneling” plans for pulling the gas pipeline underneath the Middle Fork of the Koyukuk River, the Yukon, Tanana, Chulitna and Deshka rivers on the way to Cook Inlet. • Plans for how it would avoid damaging the permafrost and ground cover as occurred during trenching and laying of fiber optic lines along the Dalton Highway to the North Slope in 2015-17. AGDC said its “review of the Arctic broadband projects … indicated the construction techniques, mitigation practices and subsequent rehabilitation plan were not done using standard best practices for construction in Arctic conditions. Poor and shallow trenching techniques and use of ice-rich backfill material combined with the absence of erosion control measures were the primary root causes.” The gas line project will not make those mistakes, AGDC said. • Updated calculations of the project’s air emissions. • A gravel-sourcing plan, listing almost 90 proposed and alternate sites for digging up gravel for construction of the project, mostly for use along the pipeline route. The gravel sites stretch from 18 miles outside Prudhoe Bay to Milepost 760 of the pipeline, a short distance before the line would enter Cook Inlet for the crossing to Nikiski on the east side. • Further explanation of why AGDC believes a site near Suneva Lake, just north of Nikiski, is the best location to make landfall as the pipe comes out of Cook Inlet. An alternate landfall site about 5 miles closer to the LNG terminal site, preferred by several residents in the area, would cross a larger area of seafloor boulders, AGDC told FERC in a Dec. 23 response. In the only third-party comments submitted on the project in December, Trustees for Alaska, on behalf of the National Parks Conservation Association, filed comments Dec. 19, pointing to “newly identified and continuing deficiencies with the air quality analysis” in the draft EIS. The parks association has asked FERC to let it sign on as an intervenor in the application docket, which would give the group legal standing to challenge the final EIS or FERC decision in federal court. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

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