Larry Persily

LNG tariffs could be self-defeating move for China

In the short term, China may have to pay more for liquefied natural gas imports though longer term it has several other supply options if it goes ahead with its threatened 25 percent tariff on U.S. LNG, analysts reported in the week after China’s announcement. There could be a lot more LNG coming from expansions in Qatar, Australia and Papua New Guinea over the next several years, with new projects moving toward final investment decisions in Mozambique and Canada’s West Coast. And there is the scheduled late-2019 start-up of the 2,500-mile Power of Siberia pipeline to move Russian gas to China. The line’s capacity of 3 billion cubic feet of gas per day could fulfil more than 15 percent of China’s import demand in 2023, based on the International Energy Agency’s 2018 forecast report. Neither Gazprom nor China has announced pricing terms for the gas. As a near-term reaction if the tariff takes effect, U.S. gas would become uneconomical in China and traders would shift their cargoes to send U.S. LNG to other buyers like Japan and South Korea, while redirecting non-U.S. gas to China, Trevor Sikorski, with Energy Aspects in London, told Bloomberg. China would probably end up paying about 10 percent more for spot cargoes after the swaps, he said. Spot-market pricing fluctuates much more than contract prices linked to oil or other fixed indices. The tariff would not reduce overall U.S. LNG export volumes, but would reorient trade flows, pushing more U.S. gas to Europe and other markets, while Mideast and African cargoes would be pushed to Asia, driving up prices, Neil Beveridge, an analyst with Sanford C. Bernstein &Co., was quoted in the Australian Financial Review. A 25 percent tariff could hit the next wave of U.S. projects with a “real impact on prospective deals … it certainly adds to the risk of delay,” David Lang, global head of LNG at law firm Baker &McKenzie, told Bloomberg. “This is a pretty dramatic move.” “At least in the short term any Chinese buyer looking for long-term supply would have to drag their feet on signing a U.S. contract,” Jason Feer, head of business intelligence at Poten &Partners in Houston, told Bloomberg. It could hit U.S. developers seeking long-term contracts to underpin financing of their export projects, Giles Farrer, research director for global gas and LNG supply for research firm Wood Mackenzie, was quoted by the Houston Chronicle. As much as the threatened tariff may hurt U.S. project developers, there will be a price to end-users in China. “This action is more likely to hurt Chinese buyers than U.S. exporters,” Katie Bays, an analyst with Height Securities in Washington, D.C., was quoted by Bloomberg. China said it would impose the tariff if President Donald Trump follows through with his Aug. 2 threat of more duties on goods imported from China. “So long as the U.S. places no barriers on exports of its own, such barriers … by importing countries would be potentially self-defeating,” CNBC quoted Citigroup analysts. “This coming winter for example, China is likely to be short on both LNG and soybeans, two U.S. commodities on which it has placed barriers.” However, a tariff war could cast doubt on the dependability of U.S. gas supplies, Citigroup added. China’s gas consumption is rising dramatically as the country — as a matter of government policy — tries to clean its air of coal pollution by burning more gas. Warren Patterson, commodity strategist for ING Bank, said he was “quite surprised” to see LNG show up on China’s list. “Given the transition we are seeing in China, with a move away from coal toward natural gas, I would have thought that the government would have wanted to ensure adequate supply,” Patterson told Bloomberg. The importance of U.S. gas to help meet that demand may mean the threatened tariffs don’t last, said Vivek Chandra, chief executive of aspiring exporter Texas LNG, which is working to develop a 2-million-tonne-per-year terminal in Brownsville, Texas. “Imports of U.S. LNG and oil into China represent one of the best ways for both countries to balance their trade balances,” Chandra told the Australian Financial Review. “Thus, we do not expect these tariffs to prevail in the long term.” Beveridge, with Sanford C. Bernstein &Co., shared a similar view with Reuters: “LNG is one of the most obvious ways to lower a trade deficit between the U.S. and China, and if there is a trade deal to be done LNG will be involved. … The latest rhetoric smacks of a negotiation being played out in a very public way.” But politics could make it harder. Hugo Brennan, senior Asia analyst at consultancy Verisk Maplecroft, told CNBC: “Geopolitical dynamics will undermine American exporters’ bid to become major gas suppliers to China.” There are other suppliers “eager to fill the gap,” Charlie Riedl of the Center for LNG, which represents the U.S. industry, told the London Financial Times. “This … would have very real effects on the U.S. LNG industry.” China could turn to Australia and Qatar, the world’s two biggest exporters, to supply its needs, ING’s Patterson said. Australia is nearing the end of a massive build-up of LNG capacity, with its sixth and seventh new export projects to come online this year, providing several opportunities for lower-cost expansions of existing liquefaction plants. The partners in Papua New Guinea’s 4-year-old LNG project are looking to make an investment decision on a major expansion next year. In Mozambique, Anadarko, the leader of the largest of several gas projects, has targeted the first half of next year for its investment decision. The world’s largest LNG producer, Qatar, already has decided to expand its 77 million tonnes of annual capacity by 30 percent, with a 2023-2024 start-up. The $40 billion (Canadian) Shell-LNG project in Kitimat, British Columbia, is scheduled for a final investment decision later this year. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

State agency wants in on EIS review for Alaska LNG project

The Alaska Department of Natural Resources has asked federal regulators if its permitting office can join the environmental review team for the Alaska LNG Project as a “cooperating agency,” promising not to share anything with the project applicant, its colleague in state government, the Alaska Gasline Development Corp. The Federal Energy Regulatory Commission has been working toward an environmental impact statement, or EIS, for the state-led North Slope natural gas project since AGDC filed its application in April 2017. The commission is scheduled to issue its draft EIS in March 2019. Federal offices with permitting authority over a project are required to assist as cooperating agencies, such as the Army Corps of Engineers and U.S. Fish and Wildlife Service for the Alaska LNG Project. FERC is the lead for the federal EIS for the Alaska gas development. The law also allows non-federal agencies to participate, if they have “special expertise with respect to the environmental impact of the proposal.” Cooperating agencies must cover all their own costs of participating in the review. The Office of Project Management and Permitting at Natural Resources coordinates between multiple state agencies with such environmental permitting expertise, Department of Natural Resources Deputy Commissioner Heidi Hansen wrote in a July 13 letter to FERC, asking the commission to accept the state office as a cooperating agency in the federal review. The DNR office “routinely enters into agreements with the lead federal agency as the single point of contact for state regulatory agencies … participating in the deliberative process and compiling state agency comments,” Hansen wrote. The state’s letter included a draft agreement for FERC to consider, modeled on a 2011 agreement from a previous state-supported Alaska gasline effort. The draft commits DNR’s Office of Project Management to hold confidential any material in the federal environmental review not available to the public. “To the extent permitted by law,” the July 13 draft agreement said, the office would not release any confidential or deliberative information outside of state agencies that have permitting or regulatory authority over the project. The ban would prohibit sharing with the project applicant, AGDC. “There is clear separation between AGDC and the State of Alaska’s regulatory agencies for conducting the permitting process,” Hansen wrote in her letter to FERC. The state Legislature created AGDC in 2010 to promote, permit and finance a North Slope gas pipeline project. It has the power of eminent domain to acquire private property, and it has authority to borrow money for construction. Although federal regulators are far along in their environmental review, “we see significant value in participating in the EIS process to assist FERC and other cooperating federal agencies by providing additional information and data needed for their analyses,” the deputy commissioner wrote. To further address the potential conflict for an Alaska state agency to cooperate on a federal EIS for a project led by the state, DNR’s project office “acknowledges that it is FERC’s policy that an agency cannot be both a cooperating agency and an intervenor in the same proceeding.” In the draft agreement presented to federal regulators, DNR’s Office of Project Management agreed “to forego its right to seek intervention in the Alaska LNG Project EIS proceeding with FERC.” An intervenor in a FERC proceeding has the legal right to challenge not only the EIS but also any commission decision. However, the draft agreement continued, “this will not disqualify the State of Alaska or the Office of the Governor and other principal departments of the state … from actively participating as intervenors in the Alaska LNG Project certificate proceeding before FERC One state entity sitting on the review team for another state entity’s federal EIS is not unique — for Alaska. In 2011, when the state was an advocate and partial funder for a different North Slope gas development project, FERC accepted the State Pipeline Coordinator’s Office at Natural Resources as a cooperating agency for the environmental review. However, FERC rejected a request from the Fairbanks North Star Borough to participate as a cooperating agency. The state pipeline coordinator’s office joined the effort several months before FERC held public meetings in early 2012 — called scoping sessions — to learn what issues people and organizations wanted covered in the EIS. (The pipeline office closed in 2015 and its duties were reassigned within the department.) This time around, the state asked for cooperating-agency status almost three years after the FERC-led scoping sessions for the Alaska LNG project. Federal regulations instruct cooperating agencies to participate in the process “at the earliest possible time.” The 2011 proponents ExxonMobil and TransCanada, operating as the Alaska Pipeline Project, never advanced beyond the pre-file stage at FERC and formally withdrew their application in 2014 before regulators started drafting an EIS. The pipeline would have carried Alaska gas through Canada and into the North America pipeline system. Prolific U.S. shale gas production and low prices put an end to the effort to sell Alaska gas in the Lower 48 states. About the same time as the file closed at FERC on the North American pipeline project, Alaska oil and gas producers ExxonMobil, BP and ConocoPhillips turned their focus to the export market. The companies started the pre-file process at FERC in September 2014 for a project to pipe North Slope gas to Nikiski on Cook Inlet, where the methane would be liquefied and loaded aboard ships for delivery to Asian buyers. When the producers decided to slow down spending on the LNG project in 2016, due to weak market conditions and low oil and gas prices, the state took over and went ahead with the application to FERC. AGDC continues answering questions AGDC and its contractors have been working the past year to answer questions and data requests from federal regulators, filling in gaps for the environmental review. In its latest filing, the state project team on July 24 presented FERC with the same material it gave the Army Corps of Engineers a few months earlier, addressing wetlands, dredging and fill issues. The Clean Water Act requires AGDC to obtain a permit from the Army Corps. In addition to ensuring preservation or restoration of wetlands and identifying appropriate Cook Inlet disposal sites for dredged material from the Nikiski marine terminal, the Army Corps and FERC review will look at the state’s plans for streambed and bank restoration efforts at temporary bridges over waterbodies. AGDC plans 54 temporary bridges for construction access roads and pipeline work, ranging from a 20-foot-long span over an unnamed creek to two 300-foot spans over the Deshka River. Included in the state’s July 24 filing with FERC, the state team said it is “not practicable” to restore to their original condition and function all wetlands affected by the project, such as areas of gravel fill placed during construction. Some wetlands will be re-established with revegetation. “These wetlands could have a functional value that is equal to, better than, or less than the value of the wetlands they replace,” AGDC has told the Corps and FERC. Some property owners may not want the wetlands restored after construction, if the owner sees more value in retaining the gravel fill, the state team said. And, in some cases, removing fill placed during construction could “introduce open water and erosion” and “can do more harm than good.” Impacts to wetlands and other waterbodies “will be discussed in a Wetlands Compensatory Mitigation Plan, which will be provided after the draft EIS is issued,” AGDC told FERC. “The plan will be refined in coordination with the Corps, leading up to the final EIS.” As soon as the Army Corps decides what areas covered by the project would qualify as wetlands, AGDC will provide more detailed mapping of terrain and boundaries. The state team also noted that wildfires can turn areas “of discontinuous permafrost wetlands into uplands,” reporting that the pipeline would cross “several areas of discontinuous permafrost that were previously burned.” AGDC is waiting for the Army Corps to issue its determination of what still is considered wetlands. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

LNG projects ramp up in response to growing market

Oil and gas companies are responding to the growing market for liquefied natural gas by ending their hiatus from new projects, while more liquefaction capacity is coming online in Russia, Australia and the U.S. Gulf Coast. LNG projects under construction or anticipated to reach a final investment decision within the next 12 months total more than 125 million tonnes of annual output capacity — more than a one-third boost to global capacity as reported by the International Gas Union’s 2018 annual report. Not sitting still as the market grows, world leader Qatar plans to expand its LNG capacity by 23 million tonnes by 2023 — jumping to 100 million tonnes per year. Qatar Petroleum has signed a contract for front-end engineering and design of three new liquefaction trains — the world’s largest — and drilling could start next year to develop additional gas reserves, S&P Global Platts reported. Qatar last year lifted its 12-year-long moratorium on new gas production. Nigeria, the world’s fourth-largest LNG exporter, is taking steps to expand its LNG production capacity by a third, Bloomberg reported. Nigeria LNG, a venture of the state-owned oil company and three oil majors, signed engineering and design contracts July 11. A final investment decision could be taken late this year. The plan would boost annual capacity to 30 million tonnes by 2024. Nigeria’s seventh liquefaction train could cost as much as $6.5 billion to build, with an additional $5 billion for the wells and pipelines to supply the expansion. Working to add Mozambique to the list of 20 LNG-exporting nations, ExxonMobil plans to expand its proposed Rovuma project to cut production costs as the company and its partners prepare to formally tap lenders this fall, Bloomberg reported. ExxonMobil looks to build two liquefaction trains — at 7.6 million tonnes each. “The larger train design will lower the unit cost … and ensure a competitive new supply for the global LNG market,” a spokeswoman said. Under plans submitted to the government, Exxon proposes a 2019 final investment decision with a 2024 start-up. Anadarko plans to raise $14 billion to $15 billion from banks and export credit agencies as it lines up long-term sales to guarantee loans for its own LNG project in Mozambique, Reuters reported. The facility would start at 12.88 million tonnes a year. Partners include Mitsui of Japan and ONGC Videsh of India. Anadarko said it has made enough progress with customers, government approvals, financing and preparing for construction to make an investment decision within 12 months. In addition, Italy’s Eni also is investing heavily in Mozambique. It leads a consortium that last year gave the go-ahead for an $8 billion floating LNG project called Coral, with a capacity of 3.4 million tonnes per year and a planned 2022 start-up. ExxonMobil is looking to possibly double output at its four-year-old Papua New Guinea LNG project, adding 8 million tonnes annual capacity, Interfax Global Energy reported. The Australian Financial Review reported the cost of expanding gas production and LNG capacity could reach $12 billion. Much closer to Alaska, Shell and its partners in LNG Canada are expected to decide later this year whether to start construction in Kitimat, B.C. The first phase would provide 13 million tonnes a year of capacity, with a potential expansion to double that, Canada’s Globe and Mail reported. Shell’s partners include Malaysia’s Petronas, PetroChina, Mitsubishi and Korea Gas. Petronas bought into the venture in May after it abandoned its own multibillion-dollar LNG terminal in British Columbia last year. Including a 415-mile gas pipeline from northeastern B.C. and other costs, LNG Canada could total C$40 billion. Also looking at the Asia market, the $27 billion Yamal LNG project in Russia’s Arctic expects to complete construction of its second and third liquefaction trains by early 2019, reaching full production capacity of 16.5 million tonnes. The Yamal leader, Russian gas producer Novatek, already is making plans for a second Arctic project at almost 20 million tonnes, with an investment decision by 2019. China National Petroleum Corp. is a 20 percent partner in Yamal LNG. It also is in talks to take an equity stake in Arctic LNG-2, according to TASS, the Russian news agency. In addition to taking an equity stake in production, China is signing up for new supplies. The Australian Financial Review reported that PetroChina signed a three-year contract with Papua New Guinea LNG for 450,000 tonnes per year, starting in July. The deal turns PetroChina from a regular buyer of spot cargoes from the terminal into a firm customer and could pave the way for a larger, longer-term contract to help underpin the proposed expansion in Papua New Guinea. “This could be the getting-to-know-you deal,” said Tony Regan, a director of LNG consultancy DataFusion Associates in Singapore. Meanwhile, $200 billion of LNG investments in Australia is coming near an end, with the last two projects — Shell’s Prelude and Inpex’s Ichthys — expected to start production late this year or early 2019, with total capacity of 12.5 million tonnes. On the U.S. Gulf Coast, most of the activity has involved adding liquefaction and export to underutilized or unused LNG import terminals. • Cheniere is continuing to expand its Sabine Pass, La., plant, building a fifth train to add another 4.5 million tonnes of capacity, while marketing a proposed sixth unit. • Cameron LNG in Louisiana, led by Sempra Energy, has three trains under construction at almost 13 million tonnes and a fourth with all its permits. Developers need only to secure buyers for the train before taking an investment decision. • Three trains are under construction at Freeport LNG in Texas, totaling 15 million tonnes, while plans for a fourth have been submitted to regulators. • Reuters reported that start-up of the $2 billion, 2.5-million-tonne Elba LNG export terminal in Georgia is delayed to late 2018. • Three more Gulf Coast projects have federal approval but lack investment decisions. Two would be repurposed LNG import terminals – the 16-million-tonne Lake Charles project, led by Shell and a Texas pipeline company, and 15-million-tonne Golden Pass terminal, led by Qatar and ExxonMobil. And though a greenfield project, without an LNG import terminal, Cheniere is developing its Corpus Christi plant in Texas in a similar phased approach to the brownfield projects, with two trains under construction, at 4.5 million tonnes each, while a third reached final investment decision in May after China National Petroleum Corp. signed on as a buyer. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC says Port MacKenzie ‘not feasible’ for LNG terminal

Several months of additional review did not change the opinion of the state’s North Slope natural gas project development team that Nikiski is a better site than the Matanuska-Susitna Borough-promoted Port MacKenzie for a multibillion-dollar gas liquefaction plant and marine terminal. The Federal Energy Regulatory Commission had instructed the state team to conduct a more thorough analysis of the borough site on Knik Arm as an alternative to the project’s preferred choice of Nikiski, on the east side of Cook Inlet about 65 air miles southwest of Port MacKenzie. The analysis will be incorporated into FERC’s environmental impact statement for the proposed Alaska LNG project. The Alaska Gasline Development Corp. responded to federal regulators July 13 that it would not be possible to build and operate the LNG plant and marine terminal at Port MacKenzie “without constraining either existing or planned uses of the complex, or of the proposed LNG facility and its marine terminal.” The Alaska LNG project team in 2013, when it was led by North Slope oil and gas producers, selected an industrial area of Nikiski as the best location, a decision which the state stuck with for its 2017 application to FERC after the producers left the project. The producer-led team acquired more than 600 acres of private land at the site — about two-thirds of the acreage required for construction of the LNG plant, dock and freight landing facility. The Matanuska-Susitna Borough in January 2018 filed a formal complaint and request with federal regulators, pressing for a better look at Port MacKenzie, which the municipality has long promoted for industrial development. The borough owns the port property. AGDC cites beluga habitat, currents, tide “Significant issues have been identified which make the Port MacKenzie site not favorable over the proposed … site in Nikiski,” AGDC said in its July 13 filing with FERC. Those include: • Work restrictions during construction and terminal operations because of the site’s location within Cook Inlet’s most protected beluga whale critical habitat area. The upper Cook Inlet area provides foraging and calving habitat for the endangered species. • Conflicts with other actual and proposed uses of the port, and the need to move the access road and proposed railroad extension away from the LNG plant site. “The area identified by the borough currently used for port operations is not feasible in conjunction with existing facility operations,” AGDC reported. • Wind, current and sea-ice conditions could hamper winter operations at the port site. • The wider tidal range at Port MacKenzie — with an average difference between high and low tides of 26.2 feet, as opposed to Nikiski’s 17.7-foot average range — would reduce by 25 percent the opportunities for unloading construction barges, adding a full work season to the project, AGDC said. • Twice the current dredging volume would be required to widen the shipping channel through the Knik Arm Shoal to allow safe two-way ship traffic through the area. Strong currents in the area necessitate a wide berth for ships to move safely in and out of the port, AGDC said. Even with the additional dredging and wider channel, LNG carriers still would be limited to crossing the shoal only at high tides, AGDC said. • The longer travel distance for LNG carriers to reach Port MacKenzie would add 12 voyages per year, requiring an additional ship — and higher costs — to move the same volume of LNG as the shorter route to and from Nikiski. Reaching Port MacKenzie instead of Nikiski, however, would save 55 miles of pipeline, AGDC said. Although Port MacKenzie offers an existing dock and barge landing, AGDC said the deep-water dock at the site is inadequate for berthing and loading LNG carriers, and would have to be demolished and replaced. In addition, the barge dock would be unable to accommodate the heavy demand of offloading construction materials, the state team said, requiring a new facility. The Nikiski site also would require construction of a new deep-water dock for LNG carrier loading, and a roll-on/roll-off barge and freight dock for delivering plant modules and construction equipment. However, AGDC said, winter sea ice at Port MacKenzie is thicker and builds up in heavier concentrations than at Nikiski, requiring construction of “ice mitigation structures” — large concrete structures (95 feet across) set on the seabed and reaching to the surface — to protect the dock and LNG carriers from ice damage. Borough says AGDC is wrong The Matanuska-Susitna Borough does not accept AGDC’s analysis, writing to FERC on July 20 that the borough “has already identified several aspects of AGDC’s response with which it disagrees.” The borough did not provide any details in its one-page letter but said it “intends to file substantive comments to highlight the incorrect information.” It said it would provide the information by Sept. 1, just six months before FERC is scheduled to release its draft environmental impact statement, or EIS, for the Alaska project on March 8, 2019. In addition to reviewing a project’s effects on the environment and communities, a federal EIS is used to determine the “least environmentally damaging practicable alternative” for multiple decisions in project construction. As such, the Alaska LNG impact statement is required to consider not only the location of the LNG plant but also pipeline routing, river crossings and other environmentally sensitive project decisions. The proposed Alaska LNG project includes 62 miles of pipeline to move gas from the Point Thomson field west to a gas treatment plant at Prudhoe Bay, where gas from the two fields would be cleaned before going into an 807-mile pipeline running through the middle of the state to Cook Inlet. The design capacity for the plant is 20 million tonnes of LNG per year, or about 7 percent of total LNG worldwide trade last year of 293 million tonnes, according to the International Gas Union’s June 28 annual report. AGDC met with borough representatives in February, May and June during its review of Port MacKenzie. The state team analyzed two possible locations for the LNG plant on borough property: One on the waterfront, and an option almost 1.5 miles inland. AGDC said the waterfront property “is not feasible in conjunction with existing facility operations” at the site. Because of federally required safety zones required around the plant, the state said, the LNG project would need to control even more property, displacing the proposed railroad extension to the waterfront and an access road. And while the inland property would solve the problem of a buffer zone displacing other users, it would complicate the project by separating the liquefaction plant and its LNG storage tanks from the loading dock and would require a 1,400-foot-wide exclusive safety corridor between the plant and the dock. The state team, in its filing with FERC, pointed to planned and proposed uses for the port area as possibly incompatible with construction or operation of the LNG terminal, including a five-year contract for loading timber at the port under a harvest contract and port lease the borough approved in April. AGDC has said it wants to start construction in 2020, though it is not scheduled to see a final EIS until December 2019, and lacks firm customers for the LNG, financing for the $43 billion project, and binding contracts to buy gas from North Slope producers. The state corporation told Alaska legislators July 11 that is spending about $3 million a month on permitting, finance, commercial negotiations and promotion, with expenses to move closer to $4 million a month next year. AGDC’s July 13 filing also responded to several other questions and data requests from FERC. AGDC prefers modeling over drilling Regulators had recommended the state team collect sediment cores from a sampling of 15 rivers and creeks that the 807-mile pipeline would cross to help in determining the environmental risks of open-cut trenching AGDC has proposed for waterbody crossings. AGDC has balked at that recommendation. “To achieve the requisite core depth to match pipeline burial depth, such sampling would require the use of drilling equipment in the anadromous stream, and permitting requirements would likely place operation of the drilling equipment in the winter of 2018/2019,” the state team told federal regulators. “To avoid such delays, transport of such equipment into remote sites, and impacts to spawning or juvenile fish,” AGDC said, the project team has decided to use terrain mapping and modeling, which includes data from more than 3,000 boreholes along or near the pipeline route. “A final report detailing the methods, data inputs, results and application to other crossings will be prepared and submitted to FERC on or before Aug. 30,” AGDC said. The state team also responded July 13 to several questions federal regulators had asked about how the pipeline and its compressor stations, LNG plant and vessel traffic could affect air quality along the route, including in Cook Inlet. The approximately 250 LNG carrier calls per year at Nikiski would add about 50 percent to large-vessel traffic in the inlet, AGDC said. “The increase in vessel traffic that would occur due to the project is not expected to substantially increase regional haze levels in the Cook Inlet region or cause a violation” of air-quality standards, according to its response. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

By the numbers: Updating Alaska LNG Project construction

Editor’s note: This update, provided by the Kenai Peninsula Borough mayor’s office, is part of an ongoing effort to help keep the public informed about the Alaska LNG project. Persily is a special assistant for oil and gas issues to borough Mayor Mike Navarre. Alaska LNG project teams played it by the numbers — really big numbers — in a presentation on construction plans to federal, state and municipal officials. Site preparations for the proposed liquefied natural gas plant and massive LNG storage tanks in Nikiski would require stripping up to 4 million cubic yards of loose soil, soft peat moss and other vegetation. That’s more than enough to cover a rough trail 10 feet wide, a foot deep from New York City to Houston. Crews would then need to excavate as much as 6 million cubic yards of frost-susceptible material — up to 6 feet deep in some areas — to prepare the site for construction. Some of the material could be reused as fill, while other material would need to be trucked in to complete the base. The two domed LNG storage tanks would each measure 305 feet in diameter, more than large enough for a Boeing 747 to spin around inside without scraping its wings. All of the numbers are approximate and subject to change as the project teams refine the design, they reminded participants at workshops held Sept. 2 and 3 in Anchorage. More than 20 Alaska LNG project team members were at the workshops to brief government agency officials and answer questions. Add in the jetty, the twin loading berths for LNG carriers and other components of the Nikiski project, and the preliminary numbers continue adding up: The project would use 800,000 cubic yards of gravel, 300,000 cubic yards of concrete, 300,000 cubic yards of armor rock, 100,000 tons of structural steel, 6,500 pilings, 7 miles of electrical wiring, almost 200 miles of aboveground piping, and 20 miles of buried pipe. The trestle to reach the loading berths could be as much as 3,200 feet long — more than half a mile — to reach water deep enough for the LNG carriers to safely maneuver. Though no substantial dredging would be needed for the jetty and loading berths, an estimated 1 million to 2 million cubic yards of dredging would be required at the temporary dock that would be built for offloading materials from barges and heavy-lift vessels during construction. The 250-megawatt, gas-fired power plant at the LNG plant site would generate enough electricity to run a city of several tens of thousands of homes. Peak construction workforce at the Nikiski site would be 4,000 to 6,000 workers. Planning work continues The LNG team reported that ongoing engineering and construction planning includes several goals: Limit truck traffic in the area as much as possible, limit dredging as much as possible, and maintain public access throughout the area as much as possible. The informational workshops were part of a series provided by Alaska LNG for regulatory agencies. The project partners — ExxonMobil, BP, ConocoPhillips, TransCanada and the State of Alaska — plan to submit their second draft of environmental and engineering reports to the Federal Energy Regulatory Commission in first-quarter 2016. The final reports and complete project application could come third-quarter 2016 as the partners work through regulatory and permit issues for the $45 billion to $65 billion project to move Alaska North Slope gas to market. In addition to the LNG plant at Nikiski, the project includes 806 miles of pipeline to reach the plant site from North Slope gas fields and a gas treatment plant to remove carbon dioxide and other impurities before the gas enters the pipeline. Alaska LNG has been buying up property around the proposed plant site in Nikiski, accumulating ownership or options on about 600 acres of the 800 to 900 acres needed for the operation. Team members reported that demolition could start later this month on some structures. They also are doubling their security patrols in the area in response to community concerns. The actual footprint for the LNG plant, storage tanks, power plant and other support buildings would total approximately 200 to 300 acres. The teams explained that the rest of the land is to provide a safety, noise and light buffer for neighboring property owners, plus work space to support the construction effort. Offloading facility comes first There is a lot of work to get to that first cargo. Before significant construction could begin, the material offloading facility would need to be built. The current plan, subject to change, has it just north of the LNG carrier jetty. With a 1,500-foot-wide frontage for offloading from heavy-lift vessels (called lift-on, lift-off) and a side facility with a 500-foot face for roll-on, roll-off deliveries, the freight dock could see 250 LNG plant modules delivered by 60 ships over a three-year period. Riprap — heavy rocks stacked atop each other — would be installed on either side of the facility to protect the shoreline. Each prebuilt module could weigh as much as 6,000 tons. Self-propelled modular trailers would haul the huge pieces to the plant site. The freight dock would be dismantled at the end of the project. Water depth at the proposed site for the offloading facility is only about 15 feet and would need to be dredged to 30 feet, the teams said. Estimates are that would require moving 1 million to 2 million cubic yards from the seabed. “We are continuing to study how we can minimize that,” a team leader said. The dredged area would measure about 3,200 feet by 1,500 feet, depending on the final design and seabed slope. The project continues to collect data on currents, waves, sediment, sea floor bathymetry and other conditions in the area. There are plans to excavate a sample pit in the seabed in the second quarter 2016 to measure how much and how quickly it fills in. Disposal sites for any dredging material are still being considered, including upland and at sea. Upland disposal could be used to protect the shoreline from erosion or for fill at the project site. Any decisions on disposal sites will be based on the composition of the dredged spoils and in close consultation with government agencies. In an effort to limit truck traffic on heavily traveled Kenai Peninsula highways, the teams reported that as much as possible construction materials arriving in Anchorage or Seward would be barged to Nikiski. Construction site services Even before the material offloading facility is under full construction, Alaska LNG would build “pioneer camps” at the plant site, the first housing for the first work crews. During construction, until the project builds its own power generating plant, Alaska LNG may buy electricity from a local provider — that’s one of the issues still undecided. Currently, Alaska LNG plans to drill its own water wells, estimating its maximum needs during peak construction at almost 400,000 gallons a day, or enough for 4,000 to 5,000 people, according to U.S. government water-use estimates. Current plans indicate no water would be withdrawn from Cook Inlet for plant operations, the teams said. The liquefaction equipment would be air-cooled, not water-cooled. Alaska LNG plans to build a secondary-level treatment plant on site for domestic sewage, and is still looking at options for proper disposal of industrial waste. The mission statement for handling construction waste is “reduce, reuse and recycle,” with the teams reporting there could be an estimated 7,500 tons of wood waste in addition to the 4 million cubic yards of vegetation from site clearing. The teams are working to determine “what can be handled locally, what can be handled on site, what has to be hauled away.”
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