Larry Persily

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.

Goldman Sachs follows global peers on fossil fuels

Though many Alaskans may see Goldman Sachs’ decision not to invest in Arctic oil projects as the equivalent of a lump of coal in their holiday stocking, that’s not on the bank’s gift list either. The global lender, investor and financial services firm also pledged not to finance new coal mines or coal-fired power plants anywhere in the world. Goldman Sachs is the first big U.S.-based bank to publicly declare it will not finance new oil projects in the Arctic, including anything to do with the Arctic National Wildlife Refuge. The company’s Dec. 15 announcement takes a stand against projects that “significantly convert or degrade a natural habitat,” Goldman Sachs said on its website. At the same time that it said no to financing Arctic oil and thermal coal (metallurgical coal used to make steel is still OK), the bank announced a commitment to invest $750 billion over the next 10 years in areas that focus on climate transition. Goldman Sachs “acknowledged” the scientific consensus on climate change, which it said is one of the “most significant environmental challenges of the 21st century.” The decision was not the first time the bank has talked down investment in Arctic oil and gas. In 2017, one of the bank’s natural resource experts said other “enormous cheap, easier-to-produce and quicker-time-to-market resources in the Permian onshore U.S.” looked better than Arctic oil. “We think there is almost no rationale for Arctic exploration … Immensely complex, expensive projects like the Arctic we think can move too high on the cost curve to be economically doable,” Michele Della Vigna, head of energy industry research at Goldman Sachs, said in a CNBC interview in March 2017. This time, the bank’s position is more philosophical than financial. “This is grounded in a core view of where the world is going, a thesis, a research-driven view … that fundamentally these questions of climate transition and inclusive growth are going to be central, secular themes for the economy for our clients and for ourselves,” John Goldstein, head of Goldman Sachs’ Sustainable Finance Group, said on a podcast. “This is where the world is going.” With almost $1 trillion in assets as of last summer, Goldman Sachs is the fifth-largest U.S. bank, according to S&P Global Market Intelligence, a financial industry research firm. The company had 2018 net earnings of $10.5 billion, just a couple billion dollars shy of BP. The 150-year-old company also said it will phase out financing of thermal coal mining companies that do not have plans to diversify away from the fuel. As of the end of 2018, Goldman Sachs had financed $80 billion in clean-energy projects toward its goal of financing or investing $150 billion in clean energy by 2025, according to the company’s 2019 annual report. “We are a financial institution, operating in global markets, with a global client base — and we have a real opportunity through that work not only to lead by example in how we run our organization, but to drive sustainable outcomes for our clients and for our communities,” the annual report said. The Rainforest Action Network said Goldman’s Dec. 15 commitments are the “strongest fossil finance restrictions of any major U.S. bank.” The praise had its limits, however. The bank still lags behind its global competitors, the organization said. Goldman Sachs’ announcement came a month after the European Investment Bank, or EIB, said it would stop issuing loans for coal or oil and gas infrastructure projects after 2021. The lag is to allow for completion of projects already underway. “This is an important first step — this is not the last step,” said Andrew McDowell, the bank’s vice president. The EIB board of directors adopted the plan after heated debate, with some countries objecting to the inclusion of natural gas in the ban, according to a Nov. 18 report by Environmental and Energy News, a Washington, D.C.-based energy newsletter. The EIB decision could pressure other financial institutions to follow, such as the World Bank and Asian Development Bank, the report said. Under the bank’s new policy, projects will need to show they can produce one kilowatt hour of energy while emitting less than a half-pound of carbon dioxide, a post-2021 standard that will ban traditional gas-burning power plants. The bank said “new technologies,” such as carbon capture and storage, may be able to qualify for financing. “The EIB’s new financing criteria will make lending to gas projects very difficult,” Nicholas Browne, a Singapore-based research director with energy consultancy Wood Mackenzie, said in a company statement Nov. 15. “That presents a concern for the gas industry,” he said. “This might increase the risk that the popular and political tide turns on gas like it already has on coal in most countries. If this does occur, it may slow the rate of growth of gas and LNG demand. In turn, this would be a major strategic challenge for companies that have identified gas as the key driver of future growth.” Since 2013, the EIB has funded about $15 billion (U.S.) of fossil fuel projects. Last year it funded about $2 billion worth of projects. Just a week before the EIB announcement, delegates at a European gas conference in Paris heard how the financial services sector is increasingly concerned about investing in gas projects given the growing pressure against fossil fuel. “There is a growing presumption against giving any of our clients’ money to you,” Nick Stansbury, from Legal and General Investment Management, said at the conference, according to reports by S&P Global Platts. “The flow of capital is imperiled by this revolution.” Cristian Carraretto, of the European Bank for Reconstruction and Development, or EBRD, said the bank’s policy on fossil fuel investment was changing quickly. The EBRD has already made it policy not to invest in any coal projects “under any conditions,” he was quoted by S&P Global Platts. In addition, the development bank will not support upstream oil projects except under specific country-by-country conditions. “Things are getting more and more difficult,” he said. ^ 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.

Texas gas flaring draws lawsuit from pipeline company

Flaring of natural gas has ended up in court in Texas. But it’s not what you might think. It’s not an environmental group suing to stop the practice of burning off gas in the field. It’s a pipeline company that wants state regulators to require a gas producer to put the fuel into a pipe and move it to market. “Flaring has long been recognized as wasteful and environmentally harmful,” Tulsa-based Williams Cos. said in its lawsuit, filed Nov. 20 against the Texas Railroad Commission, which regulates drilling and production in the state. The commission “is vested with the duty to prevent the waste of oil and gas,” Williams said in its lawsuit; not to mention that flaring is bad for the pipeline business. The steep increase in gas production in Texas — more than 29 billion cubic feet per day in September, about double the volume of 15 years ago — has outpaced pipeline capacity and markets, leaving some producers with the economic decision that it’s better to burn or vent the gas into the atmosphere than to sell it. Pipeline companies are trying to build more capacity, but nearly as fast as more gas comes up as a byproduct of oil production. Flaring and venting in the Permian Basin alone — in Texas and southeastern New Mexico — reached a high of 750 million cubic feet per day average for the third quarter of this year, according to estimates released Nov. 5 by analysts at Rystad Energy, up from 600 million to 650 million during the previous nine months. Texas, the No. 1 gas-producing state, accounted for 51 percent of all the flared or vented gas in the country in 2018, according to the U.S. Energy Information Administration. The state a year ago granted temporary permission to Exco Resources to burn off gas from its wells in the Eagle Ford shale. The producer has flared billions of cubic feet since then, according to a Dec. 4 report in the Houston Chronicle. Williams would rather Exco put the gas into its pipelines and filed suit to contest an Aug. 6 regulatory order allowing Exco to continue burning gas from 138 wells. The Texas Railroad Commission vote was 2-1. It would be too expensive to use the pipelines, Exco said in its filings with regulators. Besides, there isn’t enough room in the pipes to handle all the gas, the producer said. “Without a flaring exception, Exco will have to shut in the 138 wells, which could cause damage to the wells and the reservoir, resulting in a waste of hydrocarbons,” the company said. Flaring exemptions are relatively easy to get in Texas. The regulatory agency granted almost 7,000 flaring and venting permits in fiscal year 2019, almost double the amount of just two years ago and almost 50 times the 152 permits granted in fiscal 2009. Texas law allows regulatory staff to issue permits for 45 days at a time, but no more than 180 days total. Anything over 180 days requires commission action. Flaring “may be necessary if the well is drilled in areas new to exploration” that lack pipeline connections, the commission explains on its website. “I have some serious concerns about the frequency and ease with which this commission grants flaring exemptions,” said Commissioner Wayne Christian, who voted against the Exco permit on Aug. 6. “The price of gas right now is a lot of incentive to flare out of convenience and economics rather than necessity,” he said at the meeting, as reported by the Houston Chronicle. With U.S. natural gas prices stuck near 20-year lows, Christian expressed concerns about the economic incentive to burn off gas rather than building new pipelines to move it to market. Voting to approve Exco’s request was Commissioner Ryan Sitton, who also cited economics. Shutting in nearly $500,000 per day of oil coming from Exco’s Briscoe Ranch wells to prevent burning roughly $10,000 per day of associated gas would be a waste that the commission is charged with preventing, he said, according to S&P Global Platts reporting. In its lawsuit, Williams said the state has not denied any of the more than 27,000 flaring permit requests received in the past seven years, according to the Houston Chronicle report. Environmentalists accuse state regulators of being weak on enforcement and doing nothing to limit carbon dioxide emissions from flared gas or methane emissions from vented gas. In a letter to the Texas Railroad Commission, Environment Texas, an Austin-based group, asked the commission to stop issuing flaring permits. The letter was signed by environmentalists, scientists, Native American leaders, legislators and retired Shell Oil Co. president John Hofmeister. “At current prices, flaring in the Permian Basin burns an excess of $1.8 million a day worth of natural gas,” the letter said. The Environmental Defense Fund said the commission’s Exco decision gives operators a “blank check” to turn down pipeline connections because they can flare instead. No court date has been set for the Williams lawsuit. Nationwide, the volume of gas that was reported vented or flared reached a record-setting average of 1.28 billion cubic feet a day in 2018, according to the U.S. Energy Information Administration. In 2018, the percentage that was vented or flared increased to 1.25 percent of gross withdrawals, up from 0.84 percent in 2017. Two states, Texas and Bakken Shale producer North Dakota, accounted for 1.1 bcf per day, or 82 percent of the reported vented or flared gas. Reducing gas flaring throughout the U.S. would provide substantial economic and environmental benefits, according to a paper from the Center for Energy Studies at Rice University’s Baker Institute for Public Policy in Texas. “Flaring and venting of gas in West Texas’s Permian Basin — and certain other parts of the U.S. — have reached sufficient scale that taken in aggregate … increasingly looks like ‘wasting one resource to produce another,’” wrote Gabriel Collins, the institute’s Baker Botts Fellow in Energy and Environmental Regulatory Affairs. “Regulators in Texas — the flaring capital of the U.S. — have thus far proven highly deferential to industry on the issue of flared and vented gas, even allowing producers to flare when they are connected to a functional pipeline gathering system,” Collins wrote. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

LNG prices plunge amid decreased demand

The year is not ending well for liquefied natural gas producers. Prices in Asia are down more than 40 percent from a year ago as demand is weaker than expected and supply continues to grow. There has been some easing up on the push for coal-to-gas switching, as the economics favor the cheaper but dirtier fuel. LNG storage tanks in Europe are full — or close to it — limiting that market. And warm weather is cutting into winter demand. The market is so poor that a Singaporean trader recently decided to pay a contractually required fee for a U.S. LNG cargo but not take actual delivery of the gas. The company decided it would lose even more money if it loaded up a carrier and tried to sell the LNG. Amid all that short-term gloom, Qatar has announced it is not going to stand aside and let either Australia or the U.S. take the lead as the world’s largest LNG suppler. The Gulf nation has decided to add two more liquefaction trains — at 8 million tonnes annual capacity each — to its previous plans to expand its output with four of the mega-trains. Instead of the original plan to boost annual capacity from 77 million tonnes to 110 million tonnes by 2024, Qatar is now targeting 126 million tonnes by 2027. The country supplied about one-quarter of the world’s LNG exports in 2018 and does not want to lose market share amid forecasts of long-term demand growth. It has enough gas, Qatar Petroleum CEO Saad al-Kaabi told reporters in the nation’s capital Nov. 25. Based on recent exploration in the country’s huge North Field, Qatar now believes it has 1,760 trillion cubic feet of gas and 70 billion barrels of condensates — double the gas reserves listed in the BP Statistical Review of World Energy 2019 edition. “The big get bigger and the rest of us quiver in our shoes,” said Gordon Shearer, a senior adviser at Poten &Partners in New York. “Qatar is sending a very clear message: They are going to be the low-cost supplier of LNG,” Shearer was quoted by Reuters on Nov. 27. The competitive threat of more gas from Qatar is a problem for LNG project developers that already are finding it harder than expected to sign up the long-term customers they need to line up billions of dollars in investments and financing. The near-term problem of low prices could change if winter weather lights a fire to stoke demand. But for now, LNG is cheap. The spot-market price in Asia in late November held around $5.70 per million Btu, down from more than $10 a year ago. Demand has fallen behind supply. China is witnessing its slowest economic growth in decades and India’s economy is facing headwinds too, making the argument to replace coal with more costly gas a tougher sell for policy makers, S&P Global Platts reported Nov. 20. “No end in sight for Asia-Pacific’s growth slowdown. China says goodbye to growth above 6 percent as policymakers show welcome restraint. India’s soft patch should firm but slowly. Japan’s resilience will be tested by the global slowdown,” S&P Global Ratings said in a research note. After several years of strong growth, Asian LNG demand is expected to grow by less than 2 percent in 2019, according to Platts Analytics, far less than the 20 percent average the past three years. The business looked so weak in November that Singaporean gas marketer Pavilion Energy took the unusual step of canceling a cargo of U.S. LNG, even though it would still be required to pay a fee. “Pavilion Energy evaluated scheduling and other commercial matters, then took the decision not to lift the cargo,” a spokeswoman for the company said Nov. 19. News media reports said Pavilion was supposed to load from the Cameron LNG plant in Louisiana. Pavilion has a long-term deal with Japan’s Mitsubishi to buy LNG from the plant, which is operated by Sempra Energy. Mitsubishi is a partner in the terminal. U.S. terminals typically sell their LNG at 115 percent of the cost of the gas that went into the plant, plus a liquefaction reservation fee of between $2.50 and $3.50 per million Btu. That fee is a sunk cost — what is known as “take-or-pay” — it still has to be paid even if buyers cancel the purchase. There was no announcement of how Mitsubishi or Pavilion would cover or share the take-or-pay fee. This may not be the first canceled cargo of U.S. LNG. Prices for the heating and power-plant fuel may collapse in Europe and Asia next year to levels that would force U.S. suppliers to curb output, Citigroup said in a note to clients last week, as reported by Bloomberg on Nov. 24. Morgan Stanley sees as much as 2.7 billion cubic feet a day of U.S. gas exports curtailed around the second or third quarter, Bloomberg reported. The lack of Chinese demand for U.S. gas during the trade war between the two countries, paired with near-capacity gas storage in Europe, has created a “toxic witch’s brew” that’s making it harder to find a home for American gas, said Madeline Jowdy, senior director of global gas and LNG for S&P Global Platts in New York. There are five U.S. terminals making LNG; four more under construction; and almost 10 more with federal authorizations in hand but not enough investment, financing or customers to commit to start construction. The Federal Energy Regulatory Commission on Nov. 21 approved three LNG export terminals in Texas. FERC only looks at environmental and safety issues, not the project economics. Developers continue working to put together projects to meet expected demand growth later in the 2020s and beyond. Because it takes years to line up financing, customers, permits and to build the multibillion-dollar projects, there are concerns that supply could get tight if developers shy away from making commitments in the next year or two. The swing of the investment pendulum could be felt in the 2020s. “The supply outlook is very much a feast-to-famine situation,” Nicholas Browne, Wood Mackenzie’s Asia gas and LNG director, reported at an LNG conference in Tokyo in September. 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.

Coal’s cost advantage hinders LNG conversions

Cleaner only goes so far in producing electricity in cost-conscious countries, with coal holding a price advantage over imported natural gas. The Paris-based International Energy Agency warned Nov. 13 that the relatively high cost of liquefied natural gas could deter buyers in developing markets where affordability is a primary concern. “LNG is a relatively high-cost fuel. Investment in liquefaction, transportation and regasification adds a considerable premium to each delivered gas molecule,” the IEA’s World Energy Outlook report said. “Competition from other fuels and technologies, whether in the form of coal or renewables, loom large in the backdrop of buyer sentiment.” Currently, coal is about half the price on an energy-equivalent basis of the lowest-cost LNG delivered to western India, according to a Nov. 1 report by S&P Global Platts. Even better for coal, it’s one-third the cost of the highest-priced LNG imported into the country. The government needs to adopt tax policies and other incentives to promote coal-to-gas switching in India, because gas is unable to displace coal on an outright economic basis, according to delegates at a gas summit in India’s capital of New Delhi last month, as reported by Platts. Natural gas demand — in particular, LNG demand — will continue to grow worldwide, but the IEA report acknowledged that cost is an ongoing issue. “The LNG industry faces a struggle to gain a strong foothold in developing markets where affordability is a key consideration,” the report said. China’s gas-demand growth rate has slipped this year, blamed on a weaker economy and a government decision to ease up on its coal-to-gas switching program. After a 17 percent gain in 2018, the country’s demand growth for gas is expected to slide to 10 percent this year, Reuters quoted an official of state-run Sinopec Gas on Oct. 15. China is the world’s biggest coal consumer and has been trying to scale back its reliance on the dirtiest of fossil fuels for heat, electricity and industrial use to help clean up its air. But when more power is needed, coal is the fuel of choice. When hot weather hit in July, the country’s coal imports jumped 21.4 percent from a month earlier as households and businesses cranked up their air conditioning, Reuters reported. Through July, China’s coal imports were up 7 percent from the same period in 2018. And it’s not just imports that are up. The central government has been urging domestic coal miners to ramp up production to ensure enough supply. China’s miners dug out 10 percent more coal in June than a year ago, Reuters reported. Global coal consumption inched ahead in 2017 and 2018 after two years of overall decline, according to BP’s 2019 Statistical Review of World Energy. Three-quarters of the growth in coal consumption in 2018 came from the Asia-Pacific region. The IEA reported that coal is still generating about 38 percent of the world’s electricity, despite growing concerns over fossil-fuel emissions adding to the dangers of climate change. The international agency reported that global greenhouse-gas pollution rose for a second year, ending a lull in emissions and putting the world on track for further increases through 2040 unless governments take more action. In the first seven months of the year, 871 million tonnes of coal, including thermal coal for power plants and coking grades used to make steel, moved from suppliers to customers aboard oceangoing carriers, Reuters reported in August. That’s 2.1 percent higher than in the same period last year. Asia was the main center of demand growth, with imports up 4.5 percent from the same period last year, mainly driven by China and India. Even with lower demand for coal in more environmentally conscious nations, global consumption of coal will grow at an average 0.4 percent a year through 2050, according to U.S. Energy Information Administration forecasts. The U.S., however, is going in the opposite direction for coal consumption. Coal-fired power plants in the U.S. are projected to supply about one-quarter of the nation’s electricity this year, down from almost a 50 percent share in 2008, according to the Energy Information Administration. Low gas prices have enabled the cleaner fuel to take market share away from coal. China is not ignoring the air-quality issue, even with its coal. China Energy Group, the country’s biggest power generator, will add more than 6 gigawatts of new ultra-low emission coal-fired capacity this year as it works to meet growing electricity demand, a senior company official said this past summer. The company also expects to build an additional 5 gigawatts of low-emission capacity next year, according to a report by Reuters. “China still has quite a big demand for electricity. The government now supports regions with poor wind and solar resources to use coal-fired power … it’s a more practical measure, as gas is still too expensive,” said Xiao Jianying, the head of the state-run firm’s coal-fired power department. The higher cost of gas was seen in PetroChina’s third-quarter earnings report, when Asia’s largest oil and gas producer said its gas import business recorded a 21.76 billion yuan net loss (U.S. $3.09 billion) during the first nine months of this year. That’s worse than the 19.96 billion loss (U.S. $2.83 billion) recorded for the same period in 2018. In all of 2018, PetroChina lost $3.7 billion on its gas imports, paying more for the fuel than it is allowed to charge under government price controls. Nor has Japan abandoned coal. The August start-up of Tohoku Electric’s new coal power generation plant, Noshiro Unit 3, in Akita Prefecture is expected to displace some of the utility’s spot-market LNG gas purchases. The facility has a generation capacity of 600 megawatts and could displace about 100 million cubic feet of gas per day, equivalent to one LNG cargo per month, according to S&P Global Platts Analytics. 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.

China preps for first gas from Russian pipeline

China is a month away from getting its first Russian pipeline gas deliveries, which will help fuel the largest urbanized area in its North while also fueling speculation of what it will mean for liquefied natural gas imports into the country. Start-up of the Power of Siberia project — with its five-year gas field development and pipeline construction costs reportedly in the $50 billion range — comes just as China’s rapidly expanding gas demand is slowing down, blamed on weakened growth in the country’s economy. The pipeline in its first full year of operation is expected to move an average of just less than 500 million cubic feet of gas per day, or about 1.6 percent of China’s total estimated gas supply in 2019, according to Platts Analytics and China’s National Development and Reform Commission. But once the line reaches full capacity, expected in 2022-23, it could be transporting more than 3.6 billion cubic feet of gas per day, or about 9.5 percent of China’s supply needs for 2022, according to Platts’ estimates. A source with one of China’s major city gas suppliers told Platts the company would consider reducing LNG imports into northern China once Russian gas is available. Two Chinese end-users said they were considering reselling some of this winter’s LNG cargoes into the spot market. PetroChina expects the new pipeline supply to start Dec. 1, the state-owned major said Oct. 17. The initial northern section of the line will deliver gas to northeastern China and its Beijing-Tianjin-Hebei region, the country’s biggest winter-demand center. With the small volume of gas moving through the line at start-up, the impact on the Chinese market will be limited this winter. The full pipeline route, at more than 2,000 miles when completed, will end in Shanghai. PetroChina’s parent company, China National Petroleum Corp., or CNPC, signed a 30-year deal in 2014 with Russia’s Gazprom. Financial terms and prices have not been disclosed. Longer term, “price will become one of the decisive factors for the amount of LNG imports,” Ling Xiao, a senior executive at CNPC, said at an LNG conference in Shanghai in April. “Opening of the Russia pipeline will pose further threat to LNG imports,” he said. “We are hoping for cheaper and shorter-term LNG contracts and only in that way can LNG be truly competitive.” The pipeline start-up comes as China’s double-digit growth rate in gas consumption is slowing down. Gas demand is expected to grow 10 percent this year, down from an average 17 percent in each of the past two years. “Due to the macroeconomic situation and the government easing its push for the coal-to-gas (switching) program, China’s gas consumption growth is slowing,” said an official of state-run Sinopec Gas on Oct. 15, reading prepared remarks on behalf of Wu Gangqiang, the firm’s deputy chief economist, as reported by Reuters. Last year, China consumed about 10 trillion cubic feet, or tcf, of gas, with 56 percent coming from domestic production and about 26 percent from LNG imports. The rest was pipeline gas from Central Asia and Myanmar. Due to government price controls, importers lose money on much of the gas they bring in, which often costs more than they can charge for it on the domestic market. PetroChina reported it lost $3.09 billion (U.S.) on its gas import business in the first nine months of 2019. It lost $3.7 billion in all of 2018. The company has a mandate to ensure ample domestic supplies — even if that means selling at a loss into the price-regulated market. The government and gas importers would like to cut those losses by boosting domestic production from shale fields. “China’s reliance oil and gas imports is growing too rapidly, with oil topping 70 percent and gas moving toward 50 percent,” Lin Boqiang, director of the Energy Economics Institute at Xiamen University, was quoted by Reuters in September. The government has introduced a subsidy program to promote gas production from tight formations and has extended existing subsidies for production from shale and coal-bed methane, the U.S. Energy Information Administration reported in October. PetroChina and Sinopec have committed to produce a combined 2.1 billion cubic a day of shale gas by 2020, which would be double the country’s 2018 shale gas production. China, however, appears to be counting on inflated forecasts of domestic gas production, according to a Sept. 30 report on Radio Free Asia, which is funded by the U.S. government. China’s leadership has predicted a 20-fold increase in shale gas output by 2035, which could require over 500 new wells per year between 2019 and 2035. The numbers suggest the government is sticking with unrealistic targets, according to the radio commentary. “These numbers do look very, very high relative to what has been done so far in developing shale and tight gas,” said Mikkal Herberg, of the Seattle-based National Bureau of Asian Research. China’s technically recoverable shale gas resources are estimated at 1,115 tcf, just behind the United States at 1,161 tcf, according to a 2013 study by the U.S. Energy Information Administration. But shale drilling in China faces hurdles, the EIA said: Shale formations are in mountainous terrain where infrastructure is non-existent; drilling costs are higher; regulatory support is limited; and water supplies needed for fracking are scarce. To help boost gas production, Chinese President Xi Jinping has a plan to merge the tens of thousands of miles of pipelines held by three state-owned oil and gas giants into one new company. The firm — informally known as National Oil &Gas Pipeline Co. — would aim to attract private investors to help expand the pipeline network and diversify supply. An independent company would be more likely, in theory, to decide on new routes based on national need rather than what serves an individual producer, according to a Bloomberg report in October. ^ 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.

Coal as power source hits 40-year low

The volume of coal burned in the U.S. to generate electricity hasn’t been this low in almost 40 years — and it’s getting lower. After decades with coal at No. 1, natural gas took away the nation’s top spot for power generation in 2016 and hasn’t looked back. Coal-fueled power generation was at 48 percent of the U.S. electricity supply in 2008, down slightly from 50 percent in 1968, but it’s been in a steep downhill run the past decade. Coal’s share of the power mix plunged to 28 percent in 2018, according to the U.S. Energy Information Administration. The EIA projects coal’s share of electricity generation to fall to 25 percent in 2019 and 22 percent in 2020. And it’s not just low-cost natural gas that’s eating away at coal. It’s renewable energy. Electricity from renewables passed coal-fired power in April for the first time ever, the EIA reported. Renewable sources — which the EIA defines as hydroelectric, wind, solar, geothermal and biomass — provided 23 percent of total electricity generation to coal’s 20 percent for the month. It was a little bit of a seasonal anomaly, the agency explained, as overall U.S. power consumption is the lowest in the spring, with coal- and gas-fired power plants often undergoing maintenance during the slow period. Record generation from wind and near-record generation from solar contributed to the overall rise in renewables this spring, the EIA reported. Regardless of the asterisk on renewables passing up coal for one month, the EIA expects coal to remain ahead of renewables on an annual basis in 2019 and 2020. Renewables, however, will be the nation’s fastest-growing power source for at least the next two years, the agency said in January, on their way toward someday passing coal for an entire year. The cost for wind and solar power is dropping, making renewables more attractive as utilities, industries and states strive to reach emission-reduction targets. Northern Indiana Public Service Co. wants to be coal-free in 2028. Working toward that goal last year, it accepted bids from energy developers and learned that a mix of wind, solar and batteries would be cheaper than building a new gas plant to replace its retiring coal units, The New York Times reported. “Renewables in our particular situation were far more competitive than we realized,” said Joe Hamrock, chief executive of the company that owns the utility. “It’s hard to see any scenario where coal rebounds,” Joe Aldina, manager of coal research at S&P Global Platts Analytics, was quoted by CNN Business in September. Just since the January 2017 inauguration of President Donald Trump, who pledged during his winning campaign to bring back coal-mining jobs, approximately 15 percent of U.S. coal-fired power plants have retired, according to Platts. The energy reporting and analytics firm expects an additional 10 percent of the nation’s coal fleet will close down in 2019-20. “Coal is going to get phased out over the long term,” Aldina told CNN. Duke Energy, one of America’s largest utilities, announced in September its goal to achieve net-zero carbon emissions by 2050. “Retiring coal plants is an important part of achieving this objective,” said Lynn Good, Duke Energy’s CEO. Duke Energy plans to retire seven coal-fired units by 2024. That’s on top of the 49 coal units that have been shuttered since 2010, CNN reported. Besides losing power plants and coal-mining jobs, the industry is losing money and finding itself in bankruptcy court a lot more. More than half a dozen large U.S. coal companies have filed for bankruptcy in the past year, The Wall Street Journal reported Oct. 13, predicting that more companies are headed that way. The bankruptcies follow an even higher number of filings in 2015 and 2016, with the increasingly bad news hitting miners in Appalachia and the Powder River Basin of Wyoming and Montana. “Even if you have a totally clean balance sheet, if you can’t get the coal out of the ground at a price that works you’re going to have a problem,” Fredrick Vescio, a director at investment bank Houlihan Lokey, told the Journal. It’s not just small companies going under as demand for coal heads lower. Murray Energy, the nation’s largest private coal company, reported Oct. 2 it has entered into forbearance agreements on interest payments due on its debt. The move buys time to look at restructuring options. The closed power plants, closed mines and bankruptcies come as the coal market continues to get smaller, regardless of President Trump’s decisions to roll back environmental restrictions on coal-fired plants. The president cannot change the economics of cheap natural gas to generate electricity. Gas prices hit 20-year lows for the electricity-heavy air conditioning months of June and July this summer, averaging $2.40 and $2.37 per million Btu, respectively, according to EIA numbers. Next year could be even lower. Global energy consultancy IHS Markit reported Sept. 12 that the oversupply of gas in the United States could drive average prices in real terms at the Henry Hub benchmark to a level not seen since the 1970s. The analysts are predicting U.S. prices will average $1.92 per million Btu in 2020. At that price, it’s becoming increasingly difficult for power generators to pass up cleaner-burning gas. “I think that a lot of the management and boards of the coal-mining companies were unwilling to admit that this was really going to happen,” Karla Kimrey, a former vice president at Cloud Peak, which had roughly 1,235 employees when it filed for bankruptcy in May, told The Wall Street Journal. “Clearly, President Trump is an advocate for coal, but the ones who really matter are the senior utility executives who are deciding where electricity generation will come from in the future,” the Journal quoted Mark Levin, a managing director and senior analyst at Seaport Global Securities. Generating companies have plans to add more than 150 new gas-fired power plants across the country, the U.S. Environmental Protection Agency reported earlier this 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.

Massive Mozambiqe LNG project gets green light

French energy major Total is moving ahead with the $20-billion-plus Mozambique LNG project started by Anadarko Petroleum, which discovered the large offshore gas field in 2011 and with its partners decided in July to begin construction for a 2024 startup. The East African gas development is one of a half-dozen liquefied natural gas projects sanctioned in the first nine months of the year, totaling almost 65 million tonnes of annual output capacity. The final investment decisions represent a 15 percent boost to global LNG capacity, with several more projects expected to get the go-ahead from investors in the next 12 months. Total was quick to affirm its plans to move forward in Mozambique after it started to close the deal on its purchase of Anadarko’s Africa assets in the last week of September. The offshore fields that will feed the project hold a reported 75 trillion cubic feet of gas. The multinational company bought the assets as part of the deal for Occidental Petroleum to take over the rest of Anadarko’s holdings that include valuable properties in the Permian Basin and U.S. Gulf. “Mozambique LNG is one-of-a-kind asset that perfectly fits with our strategy and expands our position in LNG,” Total CEO Patrick Pouyanne said in a prepared statement. Total is the world’s second-largest LNG supplier, after Shell. The venture is “largely de-risked,” with almost 90 percent of the output sold through long-term contracts with key buyers in Asia and Europe, Total said. Even as the project has the benefits of sales contracts in hand and partners from five different countries, Mozambique has its problems. The nation of 30 million people is among the poorest in the world; it’s in default on past international borrowing; and rebels opposed to the government have staged violent attacks. Total executives have dismissed any concerns, explaining that the company has expertise in operating in unstable, sometimes dangerous markets. “We are in Venezuela. We are in Argentina. We have this expertise compared to other players,” Laurent Vivier, Total’s senior vice president of gas, said in a presentation Sept. 19 in Houston, according to the Houston Chronicle. “This is something we are used to doing,” Vivier said. Total also is a major investor in Russia’s Arctic LNG projects. Total holds a 26.5 percent stake in the Mozambique development, which includes partners from Japan, India, Thailand and Mozambique’s national oil company Empresa Nacional de Hidrocarbonetos. In addition to its LNG investments in Mozambique and Nigeria, Russia, Papua New Guinea, Australia and the Middle East, the 95-year-old French company also holds LNG offtake contracts at three U.S. Gulf Coast export terminals, and last month said it planned to sign more deals next year to become the largest seller of U.S. LNG. The Mozambique project received financing help when the board of directors of the Export-Import Bank of the United States voted Sept. 26 to authorize a direct loan of up to $5 billion to support the export of U.S. goods and services for the development. “Private financing was not available for this project given its size, complexity and risk — necessitating support from EX-IM,” said Chairwoman Kimberly Reed. “We have been told that China and Russia were slated to finance this deal” before the federally chartered lending agency approved the loan. It was the bank’s biggest export financing deal in years. Separate from the EX-IM Bank’s assistance, each of the partners will have to cover their equity stake. Mozambique’s national oil and gas company announced in July it would hold off on making plans to raise money for its share until later this year at the earliest. The government said it was trying to limit its debt following a default three years ago and expected it could strike a better deal after construction was underway and Total’s takeover completed. “We’ll go back to the market to seek funding” when conditions become more attractive, said Empresa Nacional CEO Omar Mitha. The government hopes revenues from the project will help the country recover from a loan scandal that forced it to restructure its international debt. Approvals related to sovereign debt became more rigorous in Mozambique after the International Monetary Fund in 2016 discovered the government had failed to declare $1.2 billion of loans. While waiting to raise its share of the project costs, the country is looking to collect $880 million in capital gains taxes from the sale of Anadarko’s holdings in the country. President Filipe Nyusi announced the target for capital gains tax revenues after he met Occidental and Total managers, the Mozambique newspaper O Pais reported in September. The African nation is not the only country looking for what it considers its fair share from resource development. The South Pacific nation of Papua New Guinea, led by a new government that took over in May, wants to strike a better financial deal with ExxonMobil and its partners for expansion of the country’s first LNG plant, which started operations in 2014. The ExxonMobil-led expansion is part of a tandem $14 billion effort — the other led by Total — to more than double Papua New Guinea’s annual LNG export capacity to about 16 million tonnes by 2024. Total has reached agreement with the government, with ExxonMobil next up to the negotiating table to discuss local jobs and other benefits. “It (the ExxonMobil deal) has to be better, it has to be far better” than the terms negotiated with Total. “That’s the key point,” Petroleum Minister Kerenga Kua told Reuters on the sidelines of the annual LNG Producer-Consumer Conference on Sept. 26 in Tokyo. In addition, Kua announced that same day that Papua New Guinea plans to review its natural resource extraction laws, which are more than 40 years old. “Whilst attracting FDI (foreign direct investment) in the oil and gas sector, reaping and sharing the rewards involving this valuable resource must be equitable to our development partners, investors and the host government and its people,” Kua said in an interview with Reuters. ^ 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.

Mat-Su Borough wants another review of Port MacKenzie site

Just six days before the close of public comment on the draft environmental impact statement for the Alaska LNG project, the Matanuska-Susitna Borough has accused federal regulators of failing to prepare an “adequate analysis” of the municipality’s Port MacKenzie as a potential site for the multibillion-dollar gas liquefaction plant and marine terminal. The borough filed a motion with the Federal Energy Regulatory Commission on Sept. 27, calling on FERC to prepare a supplemental draft EIS “in order to cure the foundational defects in the current draft.” The public comment period on the 3,800-page draft closed Oct. 3. The borough wrote in its Sept. 27 filing that it intended to submit additional comments before the deadline “to address technical deficiencies in the report,” but filed its separate motion for a supplemental draft EIS “in an effort to draw attention” to what it believes are “significant flaws” in the environmental review. The alleged shortcomings in judging Port MacKenzie as an alternative to the project’s preferred LNG terminal site in Nikiski, on the Kenai Peninsula about 65 air miles to the southwest, “should be immediately addressed and corrected so that the draft EIS is able to withstand scrutiny upon review by the commission or a federal court,” the borough wrote. As an intervenor in the Alaska LNG docket at FERC, the Matanuska-Susitna Borough has the legal right to challenge the final EIS and commission decision in federal court, as do other intervenors: The Kenai Peninsula Borough, which is defending Nikiski as the preferred site, and the city of Valdez, which is promoting its community for the project. Though Valdez has not submitted detailed objections to the draft EIS, it has asked FERC to extend the comment period. The city issued a statement back in July: “It is apparent that the draft EIS fails to rigorously explore and objectively evaluate” Valdez as an alternative site to Nikiski. The draft “ignores the substantial advantages associated with the Valdez alternative,” and “unlawfully” includes speculative impacts, the city wrote. All three Alaska municipalities have hired lawyers to represent their interests before FERC. They are arguing over a state-led venture that has no firm customers for the gas in a highly competitive global market, no partners, no investors or financing for the proposed $43 billion project to move North Slope gas through a pipeline the length of the state to a liquefaction plant and marine terminal for export. The state agency in charge of the venture, the Alaska Gasline Development Corp., cut more than half its staff this summer as it halted its commercial and finance efforts to instead focus on completing the EIS. Trustees for Alaska, an Anchorage-based environmental law group reviewing the EIS for several clients, also has asked FERC to extend the comment deadline by at least 30 days, the same as Valdez, depending on when the state project team submits additional information requested by federal regulators. The Matanuska-Susitna Borough has long promoted the essentially dormant Port MacKenzie property, about four miles across Knik Arm from downtown Anchorage, as a potential site for the proposed Alaska LNG terminal. Other unsuccessful efforts over the years have included a much smaller LNG project proposed by private interests that folded in 2017. The municipality filed its motion with FERC about 12 weeks after Mat-Su Borough Manager John Moosey told the Alaska Journal of Commerce that while his staff was still reading through the draft EIS, he thought it showed the Port MacKenzie site “in a fair and more accurate light, and that’s really what we wanted.” The borough has complained for the past several years that the port was not fairly judged as a potential project site. Nikiski was selected as the preferred site in 2013, when the project was led by North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips. The state stuck with Nikiski when it took over full control of the project in late 2016, after the companies declined to spend a lot more money on the effort. “If the State of Alaska believes Nikiski is the best place and the project can happen, we’re all in favor of that,” Moosey was quoted in the Journal of Commerce on July 10. The producers, when they were leading the project, and the state-created Alaska Gasline Development Corp., after it took over management, asserted that multiple factors made Nikiski a better site than Port MacKenzie. The project teams said winter sea ice, dredging of shipping channels, strong currents and tidal ranges, and conflicts with critical habitat for the endangered Cook Inlet Beluga whales all counted against Port MacKenzie. In past filings, the borough has rebutted many of the objections. In its latest filing, the borough said FERC dismissed Port MacKenzie from “full consideration as a reasonable alternative site” based on factual inaccuracies. “Even though the draft EIS lacks adequate analysis,” the borough said, “the current draft appears to show that Port MacKenzie is in fact” the least environmentally damaging practicable alternative. For example, the borough said, laying the gas pipeline to Port MacKenzie instead of to Nikiski would reduce the affected wetlands by 27 acres, out of about 1,600 acres. Stopping the line at Port MacKenzie would avoid displacing about two dozen residences and businesses near Nikiski, the borough added. “The draft EIS should be supplemented with a full ‘hard look’ analysis of the Port MacKenzie alternative,” the Mat-Su Borough wrote in its motion to FERC. It also alleged the draft includes “muddled statements” about which project site would cause the least environmental damage. If the FERC-led environmental review fails to provide “sufficient factual information to make this determination,” the borough said, the U.S. Army Corps of Engineers, with regulatory authority over wetlands, dredging and fill, “will be required to supplement the draft EIS at a later date.” A failure by FERC to do its job “likely is delaying the inevitable,” the borough said. Unless FERC changes its schedule, it plans to issue the final EIS in March 2020, with a commission vote on the project application in June 2020. While the Alaska municipalities battle over the project site, AGDC continues working to answer detailed engineering, construction and operations questions from federal regulators. AGDC submitted 295 pages of information, tables and maps to FERC on Sept. 25. The packet included: • A comprehensive table of waterbodies that would be crossed by the main pipeline, the 62-mile line from the Point Thomson gas field to Prudhoe Bay, compressor stations, work camps, access roads and other project construction activities. In addition to other details, the table lists the width of each waterbody and how AGDC would lay the pipeline, such as trenching, and at what time of year. • Revised air dispersion modeling of emissions along the pipeline route, at the gas treatment plant at Prudhoe Bay and liquefaction plant at Nikiski. • Updated annual emissions calculations for maximum LNG carrier operations at the loading terminal in Nikiski. The calculations include emissions from as many as 360 LNG carriers a year, plus support vessels. 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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