Larry Persily

Alaska treasury benefits from premium price on Brent

Just about the most expensive crude in North America comes from Alaska’s North Slope. Not that it’s anything all that special, unlike Copper River salmon which fetches a premium price for its high oil content, flavor and color. The geography and markets are just working in our oil-price favor. The past few months, Alaska oil has been running as much as $10 per barrel greater than the U.S. benchmark price in a reversal of decades past when Alaska crude sold below the benchmark. As of Nov. 29, West Texas Intermediate, or WTI, crude was pegged at $51.45 per barrel on the New York Mercantile Exchange. On that same day, Alaska North crude sold for $60.46, according to the Alaska Department of Revenue, which compiles the numbers on a one- or two-day lag because ANS oil isn’t traded on a public commodities exchange. If it holds for a full fiscal year, a $10 spread for Alaska oil could be worth a few hundred million dollars to the state general fund, according to Department of Revenue tables. But no rejoicing over any surprise windfall — the price differential and its extra dollars already are counted in the department’s revenue forecast. It’s a lesson in supply-and-demand-and-price economics. While shale oil producers are pumping record amounts of crude from the Permian Basin in West Texas and New Mexico, the Bakken in North Dakota and elsewhere, those abundant supplies are driving down U.S. prices. But there isn’t the pipeline capacity across the Rockies to move that oversupply to the West Coast. Alaska crude deliveries, at around 500,000 barrels a day, are covering less than one-third of the demand at West Coast refineries. In 2017, the West Coast imported almost 1.3 million barrels per day of foreign crude, led by Saudi Arabia at 283,000 barrels a day, Canada at 228,000, Ecuador at 190,000 and Colombia at 134,000. Even Russia is there, averaging 41,000 barrels a day in 2017. Without a cost-efficient way to move more of that plentiful — and lower cost — U.S. or even Canadian oil to the West Coast, refineries have little option but to pay higher global prices for the crude they need. Alaska profits by tagging along close to Brent, named for North Sea fields and used to price more than half of the world’s internationally traded oil supply. For decades, North Slope oil sold on the West Coast for around $2 less than WTI. From 1988 — when North Slope production peaked at 2 million barrels per day — to 2012, the annual average for Alaska crude was 50 cents to $4 per barrel less than WTI. ANS production was more than West Coast refineries could handle, and a federal ban on oil exports left no option but to force a lot of Alaska crude to travel to more distant U.S. markets — aboard tankers through the Panama Canal or by pipeline across Panama, to refineries on the Gulf Coast, and for some barrels all the way up the Hudson River to a small refinery in Albany, New York. Supertankers carrying Alaska crude, too large for the Panama Canal, even sailed around South America to a refinery in the U.S. Virgin Islands. Too much supply and not enough demand on Alaska’s side of the continent meant lower prices. The switch from a small price discount to a substantial price premium started for Alaska in 2012, according to U.S. Energy Information Administration numbers. From 2012 and 2015, average U.S. crude output jumped about 1 million barrels per day each year for four years running. As all that shale oil flooded the market, the U.S. benchmark price fell away from global prices. This fall, it’s been around $10 per barrel in Alaska’s favor. All that oil also has diminished Alaska’s role in U.S. production numbers. At its peak, Alaska provided about 25 percent of the country’s oil output. We’re now down to less than 5 percent. The Energy Information Administration estimated the country’s total production at a record 11.7 million barrels per day the third week of November. The number was 5 million barrels per day in 2008. At 11.7 million, the U.S. is outproducing Saudi Arabia. It’s all about shale. The EIA expects shale oil production to average almost 8 million barrels per day in December. The agency said Nov. 13 that the Permian Basin alone would produce 3.7 million barrels per day in December. It’s Alaska’s good fiscal fortune that no one has put together an economically viable way to move much of that shale oil to the West Coast, which could wreck the supply-and-demand sweet spot for North Slope crude. Some Bakken oil moves by rail to refineries in Anacortes, Wash., but not enough to knock down Alaska prices. And despite years of struggles to build more pipeline capacity from Alberta’s oil sands to the coast — any coast — for export, little new pipe is in the ground, keeping much of the 4 million barrels per day of Western Canadian production stuck in the mid-continent — and selling at painfully deep discounts. While Alaska enjoys a premium for its oil, Western Canadian Select sold for about $15 a barrel on Nov. 29. Yes, $15. Canadian heavy oil has always been cheaper, but nowhere near that much. Without new pipeline capacity to move more of their oil to the coast for exports or to U.S. refineries, Alberta producers have to take what they can get. They are suffering so much under the deep discount that Alberta Premier Rachel Notley on Dec. 2 ordered companies to cut their production by 8.7 percent (325,000 barrels per day) in hopes of pushing up prices. A few days earlier, the premier announced that her government will buy or lease rail tank cars to move more oil until pipelines can be built. But moving crude by rail at 700 barrels per tank car is expensive, and not always well received by residents watching the long trains roll through their community. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Latest AK LNG filings cover Port Mac, water crossings

Constructing the gas liquefaction plant and marine terminal at the Port MacKenzie site proposed by the Matanuska-Susitna Borough does not eliminate the challenges of building on the property across Knik Arm from Anchorage instead of the project’s preferred site 60 miles to the south on Cook Inlet, the Alaska Gasline Development Corp. told federal regulators. The state team this month filed several lengthy packages of information in response to a list of requests Oct. 2 from the Federal Energy Regulatory Commission, which is just three months away from its scheduled release of the proposed Alaska LNG project’s draft environmental impact statement, or EIS. The review will look at multiple project alternatives — including the LNG plant site. AGDC’s Nov. 20 filing included answers to FERC questions about the suitability of building at what the Mat-Su Borough calls the “optimal site” at Port MacKenzie, which borders other locations at the port already reviewed and rejected by the state team. Since 2013, the project’s preferred choice has been to construct the LNG terminal in Nikiski. The state team told FERC that building at the borough’s recommended site would not resolve many of the overall drawbacks of Port MacKenzie that include: rebuilding the existing barge dock; removing the existing deep-water dock; widening and lengthening the haul road from the waterfront, and rebuilding the road to reduce its steep incline; and likely construction delays because the wider tidal range, stronger tidal currents and ice movement at Port MacKenzie than at Nikiski would slow down deliveries and offloading of project material. The Mat-Su Borough has long advocated industrial development for the property upland from its money-losing port, promoting its road access, existing barge facility and deep-water dock. In January, the borough filed as an intervenor in FERC’s proceedings, challenging the fairness and accuracy of the project’s earlier analysis of the Port MacKenzie alternative. That prompted the Kenai Peninsula Borough in August to file its own intervenor motion to protect Nikiski as the project location. AGDC is pushing hard to provide all the information requested by FERC to stay on schedule for the draft EIS in February 2019, with a final impact statement in November 2019 and a possible commission decision on the project application by February 2020. AGDC lists problems with Port Mac site After further review of the Mat-Su Borough’s recommended site, the state project team in its Nov. 20 filing reaffirmed that it would need to remove the port’s existing deep-water dock to make room for significant expansion of the barge dock for offloading of construction material, production modules and other plant components. AGDC also said it would need to widen from 45 feet to 150 feet the port’s haul road to the upland property to accommodate transportation of large components to the site. In addition to widening the road, it would require regrading and lengthening to bring it down to a 3 percent maximum grade. The bluff at Port MacKenzie is higher than at the Nikiski site, requiring more cut and fill to build the haul road, AGDC said. The state team said it had not calculated how much rock, dirt and other material it would need to move for the widened heavy haul road but said it would exceed the 1.3 million cubic yards it would need to move in Nikiski. Building the plant in Nikiski would require construction of a temporary freight offloading facility specifically designed for construction deliveries and a permanent deep-water dock for berthing and loading LNG carriers during operations. The state team also reported it would be harder to find oceangoing heavy-lift vessels — for delivering the plant modules — that could handle the ice and tidal extremes at Port MacKenzie, which would “increase cost and decrease practicability” of the site. Building a case for “practicability” is important because federal law requires that an EIS consider not only the applicant’s preferred construction plans but also any economically feasible alternatives, referred to as the “least environmentally damaging practicable alternative.” The state has been leading development of the North Slope natural gas project since oil-and-gas producers ExxonMobil, BP and ConocoPhillips in early 2016 declined to spend the substantial funds that would be needed for the federal EIS, permitting and engineering to reach a final investment decision. However, AGDC, which is entirely state funded, appears likely to run out of funds by late 2019 unless the Alaska Legislature next year appropriates more money or the state corporation can entice private investors to buy into the venture. AGDC continues to work toward making its pitch to potential investors early next year, while it also needs to sign up buyers for the LNG, negotiate firm gas supply contracts with the North Slope producers and arrange financing if it hopes to meet its self-promoted schedule of starting construction in 2020. Alaska LNG latest attempt to monetize gas Alaska has long wanted to find a big project that could monetize its natural gas resources, but market conditions, global competition and high project costs have thwarted those plans. In 1995, FERC issued a final EIS and authorized Yukon Pacific Co. to construct a gas pipeline from the North Slope to Valdez, with an LNG terminal in the Prince William Sound community. The project never was able to assemble a gas supply, LNG customers and financing, and FERC in 2010 denied the company’s request for another extension, canceling the authorization. About 20 years before Yukon Pacific made a move on the Valdez project, a consortium of California gas and electric utilities put together a venture called Pacific Alaska LNG and applied for federal authorization to build an LNG terminal in Nikiski. In 1978, FERC issued its final EIS for the project, called Western LNG, proposed for about the same site as Alaska LNG’s preferred location. The Western LNG project would have used Cook Inlet gas, more than 400 million cubic feet per day, about one-eighth the volume of the Alaska LNG venture that would turn about 3 billion cubic feet of gas per day into 20 million tonnes of LNG per year. Like Yukon Pacific, the Western LNG project failed the economic viability test and ended up as an EIS in the library. As Alaska LNG works to finish answering FERC’s questions to stay on schedule for its EIS, only a small number of information requests remain open — some of which will require field work in 2019 and which FERC will accept between the draft and final EIS. AGDC filings range from 1 to 297 pages November’s filings cover impacts to permafrost, noise levels during construction and operation, monitoring of nearby public and private water wells, impacts to people’s health and other temporary and permanent effects from the $43 billion construction project that would stretch from the North Slope to Cook Inlet. Some of the answers were a single page, while others were far lengthier. AGDC’s updated restoration and revegetation plans totaled 297 pages, including more information on preventing invasive species from getting a foothold in the state. The project team told FERC on Nov. 26 that it had decided to use “direct microtunneling” instead of horizontal directional drilling to install the pipe under waterways in areas of continuous and discontinuous permafrost. It said tunneling “is better suited for boring into and through” such river crossings. AGDC cited several reasons for the switch: • Directional drilling requires successive passes to create a large enough path for the 42-inch-diameter pipe, whereas the pipe can be installed after one pass of the tunneling machine. • Less drilling mud is required for tunneling. • Tunneling instead of drilling does not require temporary casings for the bore hole. • And tunneled holes are less susceptible to collapse. In microtunneling, a laser-guided machine is lowered into a pit to start digging its way under the waterbody. It can cost more than directional drilling but offers advantages of accuracy and dependability, according to industry reports. Comprehensive table lists all water crossings Also on Nov. 26, AGDC provided FERC with a comprehensive table of more than 600 waterbodies that would be crossed by the 62-mile Point Thomson-to-Prudhoe pipeline and the 807-mile mainline to Nikiski, including ditches, ponds, creeks and rivers. The Excel spreadsheet lists the milepost location for each crossing, the waterbody’s name (if it has one), whether the crossing is planned for winter or summer construction, the length of the crossing and width of the bank, the proposed construction method (open-cut or frozen-cut to dig and bury the pipe, trenchless by tunneling or drilling beneath the waterway, or aerial crossing over a couple of rivers), and whether blasting would be required for the work. The entire Point Thomson line would be constructed aboveground on vertical supports. The table also lists which species of fish live in each waterbody, whether any species overwinter in the waterway and whether salmon spawn upriver. The thorough data summary also lists whether the waterway supports commercial or subsistence fisheries. The report lists the same information for construction access road water crossings. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Startup delayed for LNG to fuel TOTE ships

While this fall’s big West Coast oil and gas news has been Shell’s multibillion-dollar LNG Canada project in British Columbia, creating thousands of construction jobs toward completion by 2024, a much smaller facility 550 miles to the south plans to start producing the fuel by late 2020. Puget Sound Energy, the gas and electric utility serving communities on Washington state’s Puget Sound, issued a construction contract two years ago for its gas liquefaction plant, storage tank and marine fueling depot. It has an anchor customer lined up to take liquefied natural gas as a marine fuel. It has a 25-year tidelands lease on 33 acres in the Port of Tacoma, which will earn the port $212,000 per month after the plant starts-up. It has all its major permits but one. While construction continues on the $310 million project, the utility is waiting for the final environmental impact statement, or EIS, required for an air quality permit. The permit delay already has pushed back the plant’s anticipated start-up date from 2019 to 2020. Though the project’s capacity is about 1 percent of the LNG Canada development in Kitimat, British Columbia, and about 1 percent of its $30 billion price tag, it’s anything but a small controversy in the Tacoma area. The plant has faced strong and constant opposition from community activists, environmentalists and The Puyallup Tribe, prompting a re-do of the environmental report. Critics have questioned the safety of locating the plant in an urban area, in addition to opposing continued reliance on fossil fuels. Responding to the pressure, the Puget Sound Clean Air Agency, with jurisdiction over four counties and their 4 million residents, ordered the supplemental EIS in January. The agency hired a consultant for an in-depth analysis of the full lifecycle of greenhouse-gas emissions that would be caused by the plant. While work on the report was underway, the agency issued the utility a notice of violation for starting work on the plant without the air permit but did not order a halt to construction. The draft report was issued in October, with a Nov. 21 deadline for comments. The final report is expected in February. The 212-page report said overall greenhouse-gas emissions in the area would be reduced by the liquefaction and LNG storage terminal — if the plant gets all its feed gas from British Columbia. That detail is so important that the report recommended the source of gas be a “required condition” for the air permit, including a requirement that “compliance … will be demonstrated on a continuous basis.” The draft report recommended using Canadian gas because British Columbia has adopted “comprehensive drilling and production regulations” to cut methane emissions. Lacking similar regulations, methane emissions from U.S. gas production are “five times higher,” the report said. Taking gas by pipeline from Canada “won’t be an issue,” David Mills, a senior vice president at Puget Sound Energy, was quoted in news reports. “The vast majority comes from Canada, so we will move forward with the process given that dynamic. … I am fully expecting to have an air permit in hand late winter, early spring,” Mills has said. The liquefaction plant will have the capacity to turn about 20 million cubic feet of gas into 250,000 gallons of LNG per day, storing up to 8 million gallons in an insulated concrete tank 140 feet in diameter and 150 feet tall at its highest point. A little less than half the LNG will be used to serve the utility customers’ peak-demand heating needs in cold weather. The super-chilled LNG would be warmed up, returning it to a gaseous state for re-entry into the distribution pipeline system. The rest of the plant’s production would flow as LNG to transportation users — mostly maritime customers, but also trucking and industrial customers. The anchor marine tenant will be Totem Ocean Trailer Express, better known as TOTE, which plans to convert the two ships it uses for Tacoma-Anchorage freight service to run on LNG. International Maritime Organization regulations require oceangoing ships to significantly reduce sulfur emissions by July 2020, with LNG emerging as one of the preferred options for meeting the new standards. In May, because of the delayed start-up date for the Tacoma fueling depot, TOTE announced it was delaying conversion of its two ships. The ships now run on marine bunker fuel, a diesel-based mix. Despite the delay, TOTE “is fully committed” to converting the ships to run on LNG, the company said in a notification to customers. A Puget Sound Clean Air Agency public hearing Oct. 30 on the draft supplemental EIS drew 130 people who testified and many more who protested outside the hearing — mostly critics of the project. Supporters, however, testified that LNG is part of a cleaner future. “I know all too well what it’s like to live in a dirty, polluted city, and it’s exactly why I support the LNG plant,” said Jenn Adrian, who grew up when the Asarco copper smelter was operating in Tacoma. “LNG is a way forward, a way to move beyond the dirty industrial past.” “This has been through a very long, years-long public process,” Tara Mattina, the Port of Tacoma’s director of communications said in April. “I just don’t understand this argument that this is somehow harmful to water or air quality. … This is in our mind a clean-air project, to provide a cleaner fuel for shipping, and it reduces the potential for harmful spills in the water,” she told the Seattle Times. “We get it that it is still a fossil fuel, but there is no cleaner fuel for ships than this.” Puget Sound Energy serves about 1.1 million electrical customers and 900,000 gas hook-ups in its 6,000-square-mile service area. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC project schedule calls for work to begin first-quarter 2020

The Alaska Gasline Development Corp. told federal regulators Nov. 6 that it plans to start building construction camps and access roads at the natural gas liquefaction plant site in Nikiski in the first quarter of 2020 and along the 807-mile pipeline route by the second quarter. The state-led project’s latest timeline still shows first liquefied gas production by fall 2024. Sticking to that schedule assumes the state corporation can sign LNG customers to binding long-term contracts, complete the deals to buy gas from North Slope producers, find investors and financing for the estimated $43 billion project, acquire the rights to about 900 acres of land in Nikiski, secure any state legislative approvals that may be needed, work through all the required federal and state regulatory authorizations, and reach terms with contractors and suppliers for one of the most expensive energy projects in U.S. history. LNG developments proposed along the U.S. Gulf Coast, in Canada and elsewhere in the world face many of the same issues. AGDC has been talking for the past year with Chinese interests about taking 75 percent of the Alaska project’s LNG capacity while financing 75 percent of development costs. No firm deals have been announced. The project’s latest schedule presented to the Federal Energy Regulatory Commission also says work would start in early 2019 on relocation of a few miles of state highway in Nikiski to make way for the gas liquefaction plant and marine terminal. However, the state corporation leading the North Slope natural gas project lacks funding to buy land for the highway relocation or to contract for its construction. AGDC’s work schedule presented to FERC is not binding; it’s the corporation’s best estimate of what it wants to accomplish. Federal regulators on Oct. 2 asked for an updated project timeline to include in the draft environmental impact statement, or EIS, which is due for release in February 2019. But unless the Legislature appropriates additional state money or the corporation raises funds from other sources, the project could run out of funding by the end of calendar year 2019, about the same time FERC is scheduled to release its final EIS in November 2019, according to a spending plan prepared for the AGDC board’s Nov. 8 meeting. As such, the corporation is planning to approach potential investors in late 2018 or early 2019, according to a report at the board’s Oct. 11 meeting. The presentation for investors “will outline equity offer terms, methods of investment and commercial structuring,” according to the information given to the board. The corporation plans to spend between $3 million and $4 million per month in the current fiscal year that ends June 30, 2019. The project schedule submitted to FERC on Nov. 6 assumes the commission issues its authorization for construction by February 2020 — within the 90-day deadline after the final EIS. “The forecasted schedule for both the draft and final EIS is based on AGDC providing complete and timely responses to this and any future data requests,” FERC reminded the project team Oct. 2 when regulators presented the state with 63 pages of information requests. The potential for any new information requests will depend, commission staff told AGDC representatives at an Oct. 18 meeting, on whether the corporation’s information is complete or prompts follow-up questions. If AGDC and its partners move quickly to a final investment decision after receiving FERC authorization, the project schedule calls for site preparation to begin in early 2020 at the LNG terminal and later that year along the pipeline route. Sealifts of large production modules aboard barges to the North Slope would start in 2023. The state project team on Nov. 6 provided FERC with some of the additional information requested last month, as AGDC nears the end of submitting data needed for the draft EIS. The latest information included: • A list of 34 potential sites where four rock crushers would be set up and moved as needed to provide material during pipeline construction, operating 24 hours a day between eight and 49 days at each site. • The location, acreage, number of crew beds and duration of use for the 29 pioneer work camps that would be set up for initial site prep and access road construction along the pipeline route. Each camp would cover about four acres, with accommodations for 120 workers, with the first camps going in by the second quarter of 2020. AGDC plans to submit by Nov. 19 the final batch of information requested last month by FERC, including: • Additional details on construction plans to lay concrete-coated pipe across 29 miles of the seafloor from the west side of Cook Inlet to Nikiski. • Further information on potential impacts on permafrost during and after construction. • Additional geotechnical and geophysical studies of the feasibility of trenchless pipeline crossings at specific waterways. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Tax policy paves way for LNG Canada project

It wasn’t just growing market demand and higher prices that motivated the partners in the LNG Canada project to go ahead with their C$40 billion development in British Columbia. Lower taxes helped, too. The B.C. premier’s decision to scrap his predecessor’s special liquefied natural gas tax and endorse a new “competitive tax structure” helped the companies make their investment decision, LNG Canada’s commercial director Rob Dakers was quoted in Business in Vancouver. In 2014, the B.C. government pushed a new tax on LNG projects, set at a minimum rate of 1.5 percent of net operating income (revenue less expenses) until a project recovers its capital investments and the plant starts operating at a profit. At that point, the tax rate would climb to 3.5 percent for 20 years, then top out at 5 percent. The special LNG tax would be in addition to corporate income taxes. Then, nothing happened. Hopes never turned real for multiple proposed LNG export terminals on the British Columbia coast and booming gas production to feed the projects. The new industry would create so much provincial revenue, then-Premier Christy Clark said, that the B.C. treasury would be able to pay off all its debts, eliminate sales tax and establish a “prosperity fund” — called a “fantasy fund” by skeptics. But the global LNG market did not cooperate with the plan. Turns out plenty of new supply was on the way, prices were headed down, and developers were not looking to commit tens of billions of dollars with that much financial uncertainty. Then, by early 2018, markets were looking much better, prices were up, and the provincial government that took control in 2017 was ready to offer a deal. If LNG Canada — led by Shell, with partners from Japan, China, Malaysia and South Korea — would commit by November to build its project in Kitimat, B.C. (about 100 miles southeast of the Alaska border), the province would get rid of the LNG tax. The government wanted to move the seven-year-old joint venture toward a final investment decision. British Columbia also will exempt the project from paying provincial sales tax during construction, similar to the policy for many manufacturing plants, recovering that forgone revenue over 20 years in a new structure called “operating performance payments.” The province will exempt LNG Canada from a scheduled $20-per-tonne increase in carbon-emission taxes if the project can meet a target as the world’s cleanest liquefaction plant. That would lock in the carbon tax at $30 per tonne for the project, while the provincial tax for other fuel users is set to rise each year by $5 per tonne until it hits $50 in 2021. The offer also provides the project access to cheaper electrical power, putting it on a similar footing to other industrial sectors. B.C. Hydro will cut its rate for LNG facilities and offer its standard industrial tariff in an attempt to get LNG Canada to use electricity and not gas to power much of its operations. “I think these are the right steps forward to level the playing field and enable LNG development in B.C.,” Susannah Pierce, LNG Canada’s director of external relations, said when the government announced its offerings in March. Other LNG developers can get pretty much the same deal. One small project near Vancouver is close to a construction decision, while others still are in proposal-and-planning stages. “Our obligation is to the people who call British Columbia home, and our job is to get the best deal for them and the generations that follow,” Premier John Horgan said in March. “No premier or government can dismiss this kind of critical economic opportunity for the people of British Columbia.” Instead of the provincial treasury receiving an estimated $28 billion in revenue over 40 years from LNG Canada, British Columbia would take in $22 billion, according to government estimates in March. The tax breaks and other terms, however, are contentious. Before he became premier, Horgan spent years in the opposition, accusing the government of giving away too much revenue to large multinational LNG proponents. “Shell does not need handouts from government, in my view,” Horgan said in 2013. Environmental groups don’t like the deal, calling it an abandonment of British Columbia’s commitment to fight climate change. “Today’s announcement is a new form of climate denial,” Sierra Club B.C.’s climate campaigner Jens Wieting said in March. “By sweetening the pot for fracked gas export, the government is laying out a red carpet for investors to help destroy our climate.” Soon after LNG Canada announced its investment decision Oct. 1, the opposition party was calling on the government to make public the details of the tax deal. “What promises has the government made that will bind future governments or cost taxpayers in the future?” asked Mike de Jong, an opposition party member in the provincial assembly. “What has this government promised in exchange for the decision to proceed, and how long have they promised it for? It may be eminently defensible, but surely people are entitled to know.” Finance Minister Carole James said the government is finishing the “operating performance payment agreement” in lieu of sales taxes during construction, and the terms would be released when they are final. The project’s C$40 billion price tag includes two liquefaction trains in Kitimat, with production capacity of 13 million tonnes per year. The partners have the option of later doubling that capacity. Almost half of the construction cost is for the LNG plant. In addition to the Kitimat terminal, C$6.2 billion will be spent on the almost 420-mile pipeline to deliver feed gas from northeastern B.C. In total, the LNG plant, pipeline and upstream development will employ 10,000 workers at peak construction. A remaining hurdle is a jurisdictional challenge over the pipeline, which already holds provincial regulatory approval. An opponent contends that Canada’s National Energy Board has jurisdiction, not British Columbia, because the line would connect to pipe that serves Alberta. The NEB has agreed to consider the challenge. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

AGDC meets with FERC to stay on schedule

The state corporation in charge of developing the Alaska LNG Project has already submitted its first round of answers to questions posed three weeks ago by federal regulators preparing the project’s environmental impact statement. The response came as the Alaska Gasline Development Corp. is looking for the Federal Energy Regulatory Commission to stay on schedule for its release of the project’s draft impact statement in February 2019. State project team members met with federal regulators last week to discuss the timeline and seek clarification on specific items among the almost 200 data requests presented by FERC on Oct. 2. AGDC submitted several hundred pages of answers and data on Oct. 22, with another round expected by Nov. 19. AGDC asked FERC staff at the Oct. 18 meeting in Washington, D.C., if the corporation’s timeline for responses would be sufficient to maintain the environmental impact statement, or EIS, schedule. That will depend, commission staff said, on whether the answers are complete or if they prompt substantial follow-up questions. FERC and state project staff held a similar technical conference in March to review information needed for the EIS. In addition to AGDC and FERC staff, the Matanuska-Susitna and Kenai Peninsula boroughs, along with the city of Valdez, sent representatives to the Oct. 18 meeting, as all three Alaska municipalities are advocating that the gas liquefaction plant and marine terminal be built in their community. All three have filed with FERC, pushing for the impact statement’s alternatives analysis to consider their community. The site-selection debate, however, did not come up at the meeting. In a more general discussion, FERC staff on Oct. 18 reiterated that the EIS will analyze each project alternative on three criteria: If it meets the project’s needs; if it is economically and technically feasible; and if it provides an environmental advantage. If the environmental review process stays on schedule, FERC plans to issue the project’s final EIS in November 2019 — which would allow the full commission in February 2020 to grant authorization for construction. The state filed its application with FERC in April 2017. The state proposes to build a $43 billion project to pipe Alaska North Slope natural gas more than 800 miles to a liquefaction plant and marine terminal in Nikiski, on the eastern shore of Cook Inlet. In addition to the FERC authorization, the state team is working to line up gas supply agreements with North Slope producers, contracts with customers for the LNG, along with investors and financing for what would be the country’s most expensive oil and gas project. Development funding, however, could run out late 2019 unless AGDC is able to find investors or the Alaska Legislature appropriates additional money. Issues covered at last week’s conference included FERC’s Oct. 2 requests for: • More details on AGDC’s plans for horizontal directional drilling, or HDD, to install the pipeline beneath water crossings. The state team reported it has not contracted with an HDD contractor and therefore cannot provide all of the clarifications requested by FERC. The type of equipment used, for example, might be specific to the contractor, AGDC said. Commission staff clarified that FERC is requesting a general plan with such information as HDD worker training, drilling monitoring, contingency plans, source of drilling water and use of drilling mud. • More specific information on the pipeline’s water crossings, including the proposed crossing method, width of the banks, fisheries habitat and population, and whether any fish spawning occurs at the crossing or upstream. AGDC said it has not visited every crossing — almost 450 along the project route — but it has aerial photos of each location. The state team asked FERC if it would be sufficient to list the areas where its information is incomplete. Commission staff said they need a consolidated table with each crossing, listing the construction method (such as open-cut trenches) and other details. FERC staff said the state team should send in what it has, even if there are information gaps. • More information on the project’s potential impacts during construction and operation on surface water and groundwater. AGDC said some of the information — such as the treatment, location and volume of water discharges — would not be known until a project construction contractor is hired. The state team said it could not anticipate water use and discharges by contractors it has not yet hired. Commission staff responded that AGDC is the project applicant and, therefore, ultimately responsible for environmental impacts. FERC staff explained they are particularly interested in any potential impacts on municipal water sources. AGDC answered that state law governs water use, with specific permitting requirements. FERC recommended AGDC submit information on the state permitting process and how the project would be held responsible for mitigating any impacts on water sources. • An updated groundwater monitoring plan for protecting public and private wells. AGDC reported it is not working with individual land owners on a monitoring plan, though it has notified potentially affected landowners in the project’s path. FERC suggested AGDC identify wells that could be affected by project construction and operation, explain exactly what information it has and where and why it is limited in some cases. FERC clarified that its focus on groundwater monitoring is not limited only to construction camps but applies to the entire project. The state team said additional information would be available before the project’s construction phase. • Cumulative impact estimates for sulfur and nitrogen emissions in sensitive areas at each compressor station along the pipeline route and at the LNG plant site west of the Kenai National Wildlife Refuge. AGDC asked why FERC is applying a more stringent level of analysis for some federal lands than is required by the Clean Air Act. The state team noted that the U.S. Department of Interior had written to FERC, pulling earlier requests from department agencies for such analysis. FERC explained that in some cases it requires additional reporting beyond what is requested by other federal agencies. Commission staff recommended that AGDC make its case why it should not be required to model additional analysis of emission impacts on federal lands far from the direct emission source and FERC would consider it. Issues addressed in AGDC’s Oct. 22 filing with FERC included: • A revised migratory bird conservation plan that addresses questions about vegetation clearing during construction, raptor surveys and nest management. • More information about AGDC’s plans to use granular-fill work pads during construction, particularly in areas of thaw-sensitive permafrost. • AGDC’s response to the possibility of hauling dredged material — pulled from the seafloor to make way for the freight offloading dock at Nikiski — to beach-nourishment sites 40 to 60 miles away on the Kenai Peninsula. AGDC said using the material at distant sites would not be feasible, due to the time and cost of moving the dredged material. The project proposes disposal offshore, in nearby deeper waters in Cook Inlet. FERC requests on the state’s list for response by Nov. 19 include: • Additional details on construction plans to lay concrete-coated pipe across 29 miles of the seafloor from the west side of Cook Inlet to Nikiski. • A revised groundwater monitoring plan, providing “proposed avoidance, minimization and mitigation measures for potential effects on groundwater supply wells” near the pipeline and project sites. • Further information on potential impacts on permafrost during and after construction. • A table of all areas of thaw-sensitive soils along the pipeline route. • Additional geotechnical and geophysical studies of the feasibility of trenchless pipeline crossings at specific waterways. • An updated discussion of seismic risks to the project, reflecting the magnitude 6.4 quake that hit the North Slope in August. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Capacity shortages costing Canadian producers $100M/day

If Canadian oil producers had the $100 million per day that one CEO estimates they are losing out on because they must sell their output at a painfully steep discount to U.S. crude, they could in just over a year’s time collectively pay cash to build the C$40 billion LNG Canada project. Though only hypothetical and certainly unlikely, it’s a costly lesson for the producers in the law of supply and demand — and the laws and politics that make it hard to build new pipelines. Pick a day, any day this month and West Texas Intermediate, the U.S. benchmark, has been around $70 per barrel. It was greater than $76 one day. Then pick a day, any day for Western Canadian Select, the benchmark for oil sands production. It hasn’t been greater than $30 all month; it was $24.22 on Oct. 11. “It’s a crisis,” said Tim McMillan, chief executive of the Canadian Association of Petroleum Producers, as quoted in the Calgary Herald. “When we were canceling pipeline projects over the last decade, this was the end result we should have expected.” Blame it on more than just insufficient pipeline capacity. It’s rising production in Alberta’s oil sands and maintenance at U.S. Midwest refineries that are among the biggest customers for Canadian crude. The inability to move the growing volume of crude to coastal export terminals is costing Canadian producers access to the global market and its higher prices. “All of those things have culminated into a system that is completely overloaded,” Tim Pickering, founder of price-tracker Auspice Capital in Calgary, told the Canadian Press. “We are basically giving this stuff away,” analyst Martin King of GMP FirstEnergy told a Calgary Herald columnist. “Heavy-oil producers are getting 40 percent of what they normally would be paid if we had access to markets,” said Grant Fagerheim, CEO of Calgary-based Whitecap Resources, which produces about 60,000 barrels per day. He estimates the price differential costs Canadian producers up to $100 million per day in lost revenue at current levels. If the differential were to persist over a full year, the impact on provincial royalties would total about 9 percent of Saskatchewan’s entire budget for the current fiscal year, according to Bronwyn Eyre, minister of energy and resources. “That’s money for hospitals and roads and social services,” he said. The region’s pipeline system has the capacity to move about 4 million barrels per day, but that’s not enough. Analyst Kevin Birn of consultancy IHS Energy said Western Canadian crude supplies are expected to average 4.4 million barrels per day this year — most of it oil sands production — climbing to 4.7 million in 2019. What doesn’t go by pipe moves by rail. Separate news reports by Reuters (2017) and the Canadian Press (2018) put the cost at between $12 to $20 per barrel to reach U.S. Gulf Coast refineries. The volume by rail is growing — a lot. Before 2012, little oil was shipped by rail out of Canada. This past June, the country’s energy regulator announced a record-breaking average of 200,000 barrels per day by rail. The International Energy Agency estimates the average will reach 390,000 barrels per day in 2019. If only there was more pipeline capacity to coastal export terminals. “I refuse to believe that Canada as a country will not be able to get its act together and ultimately get these pipelines built,” Cenovus Energy CEO Alex Pourbaix told Bloomberg earlier this month. Cenovus is a major oil sands producer, at about 390,000 barrels a day in the second quarter of 2018. “Right now, the Canadian oil patch is getting killed by the differential,” International Petroleum Corp. chairman Lukas Lundin told Bloomberg last week. “But over time, we think that’s going to change because there’s going to be some pipelines coming up.” IPC this month announced a C$600 million takeover of a small Canadian producer. “If you survive this short-term pain, the long-term gain is very big,” Lundin said. After 10 years of political battles and litigation in the United States, TransCanada plans to start construction next year on its Keystone XL line. The $8 billion, 1,184-mile pipeline will move up to 830,000 barrels a day of Western Canadian production to a connection in Nebraska, where existing lines can carry the crude to the Gulf Coast. It took a change in U.S. presidents for TransCanada to gain approval for the project. But Western Canadian oil producers also have their own politics to blame for a lack of pipeline capacity to overseas customers. Kinder Morgan had worked several years to win approval to triple the capacity of its Trans Mountain line that moves oil from Alberta to a marine terminal near Vancouver, B.C., adding almost 600,000 barrels a day of new capacity. But the weight of litigation, community challenges and opposition from the British Columbia government pushed the company to give up in May and sell not just the expansion project but the entire line and terminal to the Canadian government, which plans to assert federal control and move ahead despite provincial opposition. Canada agreed to pay C$4.5 billion to Kinder Morgan and take over the C$7.4 billion expansion to ensure it gets built. The government figures it will later sell the operation to private investors and is telling its citizens the treasury will not lose any money on the flip. Then there is a new problem. Canada’s Federal Court of Appeal ruled in late August that the National Energy Board failed to adequately consider increased oil tanker traffic in its 2016 environmental review of the expansion project. The court also ruled the government had failed in its responsibility to consult with Indigenous communities. The government decided not to appeal the court ruling and gave the energy board 22 weeks to conduct a full impact assessment of the additional tanker traffic. The board’s assessment is due to the cabinet in February. The court decision to halt approval of the pipeline was “disappointing, but by no means insurmountable,” Canadian Natural Resources Minister Amarjeet Sohi told the Canadian Press last month. The NEB this month called for public comment on whether it should consider marine shipping issues out to the 12-nautical-mile territorial sea limit or to Canada’s 200-nautical-mile exclusive economic zone. The National Energy Board received 123 applications to participate in its court-ordered environmental reconsideration. The board approved 98 intervenors, including the cities of Vancouver, Victoria and Burnaby; Indigenous groups from Alberta and B.C.; environmental groups; oil companies; and the governments of Alberta and B.C. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Mat-Su, Kenai boroughs continue sparring over LNG plant site

The Matanuska-Susitna and Kenai Peninsula boroughs continue to file comments with federal regulators as they each defend their own community as the best site for the proposed Alaska LNG project’s gas liquefaction plant and marine terminal. The Mat-Su Borough on Oct. 16 asked that the Federal Energy Regulatory Commission request additional information from the state team leading the development, the Alaska Gasline Development Corp., “so that the commission can perform an adequate alternatives analysis related to the proposed liquefaction facility.” The borough is promoting its underused property at Port MacKenzie, across Knik Arm from Anchorage, as a better site for the LNG plant than Nikiski, on the Kenai Peninsula, which the project development team selected early in the planning process five years ago. The borough and AGDC have traded filings in the FERC docket the past few months, disputing the attributes — or detractions — of Port MacKenzie. The state corporation has provided FERC with multiple reasons why it believes Port MacKenzie is not a viable option to Nikiski. “Since AGDC continues to show an unwillingness to provide any information regarding Port MacKenzie unless specifically requested by the commission, the Matanuska-Susitna Borough respectfully requests that FERC consider issuing additional information requests to AGDC … to demonstrate why it prefers Nikiski over Port MacKenzie,” according to the filing. Among the questions the borough wants FERC to present to the state team are: • Why AGDC believes the existing road to the port is inadequate. • Why the Knik Arm Shoal shipping channel would need widening to accommodate the estimated 240 LNG carriers a year that would dock at Port MacKenzie. • And why the additional 116 miles for a round-trip voyage to Asia from Port MacKenzie rather than Nikiski “are material in light of the overall length of a trans-Pacific journey.” A few years ago, the project team — then led by North Slope producers ExxonMobil, BP and ConocoPhillips — acquired more than 600 acres of private land at Nikiski toward the final footprint of about 900 acres. The producers stopped buying land when they decided not to pursue the LNG project. AGDC, which took over project management, does not have money to buy the remaining acres at this time. The Kenai Peninsula Borough, in an Oct. 11 filing with FERC, argues that the commission “should defer to the selection” of Nikiski by the state, “unless there are clear and overwhelming environmental, social or safety reasons for rejecting the site — which there are not.” The Kenai Borough contends that since the Alaska Legislature created AGDC to develop a North Slope natural gas project, the corporation’s decision to go with Nikiski “is in effect a selection by the State of Alaska through its delegation of authority to the AGDC.” The Kenai Borough argued to FERC: “The Mat-Su Borough is therefore advocating for a site for the Alaska LNG Project that is contrary to the site preferred by AGDC, an instrumentality of the State of Alaska, the superior governmental body in Alaska.” FERC is scheduled to release its draft environmental impact statement for the Alaska project in February 2019, with the final EIS planned for release November 2019. However, in a letter to AGDC on Oct. 2, with 63 pages of follow-up questions and additional data requests, FERC cautioned that its EIS schedule is subject to change. Though some of the questions related to Port MacKenzie, most covered a wide range of other project design, construction and environmental issues. “You should be aware that the information described in the enclosure is necessary for us to continue preparation of the draft environmental impact statement,” FERC told the state team. “The forecasted schedule for both the draft and final EIS is based on AGDC providing complete and timely responses to this and any future data requests.” Federal law requires an environmental impact statement to review alternatives to multiple aspects of a project. In the case of Alaska LNG, that will include some pipeline routings, construction methods, river crossings — and the LNG plant site, too. If FERC stays on its EIS schedule, the full commission could vote on the state’s project application in February 2020. If AGDC can lock down investors, financing, LNG customers, firm sales agreements to buy gas from North Slope producers, and all the other pieces of the $43 billion project to move Alaska gas to market, the corporation could be in position to make a final investment decision after the FERC vote. However, without additional state funding from the legislature or private investors, AGDC could run out of money before January 2020. The corporation plans to make its pitch to investors by early 2019. In a Sept. 14 filing with FERC, the Mat-Su Borough went much further in its challenge, urging a stop to the EIS process. “FERC must not proceed with its review of AGDC’s application” until the state team “has presented a fair and accurate analysis of Port MacKenzie as an alternative site,” the borough said. The commission is not required to respond to the borough’s stop-action plea. In its Oct. 16 filing, the Mat-Su Borough did not repeat its call for FEERC to stop the environmental review process, blaming AGDC for any delays. “AGDC has caused undue delay and provided late filings as a result of its continued resistance to performing an adequate analysis of Port MacKenzie as an alternative site for the proposed liquefaction facility.” The borough said it is pushing FERC “to ensure that the draft environmental impact statement produced by the commission is based on accurate information relative to Port MacKenzie.” AGDC believes its analysis of Port MacKenzie is accurate, the corporation told FERC on Oct. 2. “The fact that the Matanuska-Susitna Borough disagrees with AGDC’s analysis does not indicate a lack of consultation or bad faith,” the state project team said. The borough’s assertions “are devoid of merit,” AGDC said. “The incendiary accusations are baseless, entirely inappropriate and should be disregarded.” Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

FERC sends 63 more pages of questions for AK LNG Project

With just four months to go before the scheduled release date for the Alaska LNG Project’s draft environmental impact statement, federal regulators on Oct. 2 sent almost 200 additional information requests to the state’s project team. The 63-page list includes questions about waterway crossings and temporary access roads for pipeline construction, avoiding damage to permafrost, protection of Cook Inlet’s beluga whales, and further review of Port MacKenzie as an alternative to Nikiski for the gas liquefaction plant and marine terminal. The follow-up questions arrived as the project team at the Alaska Gasline Development Corp. was nearing the end of responding to the initial round of more than 800 questions and requests for more information from federal regulators. Such additional data requests are not unusual for the Federal Energy Regulatory Commission, which is preparing the single federal EIS for the proposed Alaska LNG development, which includes 870 miles of pipeline from Point Thomson to Prudhoe Bay to a gas liquefaction terminal in Nikiski on the eastern shore of Cook Inlet. The state is the sole applicant in the $43 billion venture, trying to put together deals with LNG buyers in Asia, assemble partners to invest and lenders to provide financing — plus all the permits and authorizations. AGDC is expected to introduce itself to potential investors late this year, followed by a more focused effort in early 2019. The state corporation has contracted with Goldman Sachs and the Bank of China to assist with finding investors and financing. AGDC could run out of state money in late 2019 unless the Legislature appropriates additional funding or the corporation can entice investors to start covering development costs. The seven-member AGDC board, appointed by the governor, is scheduled to meet Oct. 11 in Anchorage. FERC is scheduled to release its draft environmental impact statement, or EIS, in February 2019, with a final impact statement in November 2019 and a commission vote on the state’s project application in February 2020 — assuming the state submits all the materials needed for the review. “The enclosure includes several requests for information that have been made multiple times in the past for which an adequate response has not yet been received,” FERC said in its Oct. 2 cover letter to the state. “You should be aware that the information described in the enclosure is necessary for us to continue preparation of the draft environmental impact statement. … The forecasted schedule for both the draft and final EIS is based on AGDC providing complete and timely responses to this and any future data requests.” The letter asks AGDC to provide: • An updated status list for all authorizations required to build the project, “including the actual or anticipated submittal and receipt dates.” • Additional responses to the Matanuska-Susitna Borough’s assertion that it has identified a better site for the LNG plant than the location reviewed — and rejected — by AGDC in its filing with FERC this summer. Federal regulators also asked the state corporation to further explain why it believes building at the borough’s Port MacKenzie would require one more construction season than Nikiski, about 65 air miles to the southwest. The borough has long promoted Port MacKenzie for industrial development. • Plans to promote employment of Alaska Natives and other minorities during construction and operation. • More information on interconnection points to the mainline for gas distribution in Alaska. AGDC has identified three of the five connection points long promised as part of the gas export project (Fairbanks, the Matanuska-Susitna Borough and Nikiski), but has not settled on the remaining two offtake points. “Provide the locations or an update on the other gas interconnections to be built within Alaska,” FERC asked, “(and) discuss the feasibility of including an interconnection to provide gas to the Denali Borough that could serve the communities in that borough as well as Denali National Park and Preserve.” • Site-specific plans for each of 12 proposed gas line crossings of the trans-Alaska oil pipeline. • Location and acreage for any temporary access roads that would be left in place after construction. AGDC has told FERC that access roads would be removed and the land restored after construction “unless the landowner or land management agency requests that the improvements be left in place.” • A table of the 29 pioneer camps proposed during construction, including the location, current land use, camp size, number of workers at each camp, duration of use for that camp and land-restoration procedures. • Discussion of how the pipeline construction techniques “would be similar and/or different” from the practices used in laying fiber optic lines in trenches along the Dalton Highway that resulted in permafrost thawing and environmental damages. The state is investigating the aftermath of the 2015-2017 telecommunications line construction from Prudhoe Bay to Fairbanks. • Additional description of the impacts on permafrost during project construction and also long-term impacts, “including impacts on thermal equilibrium given the shift in soil makeup and the permafrost profile.” • Further site-specific geotechnical information for proposed trenchless crossings at the Middle Fork Koyukuk, Tanana, Chulitna, Yukon and Deshka rivers. A trenchless crossing means drilling underneath the river and pulling and/or pushing the pipe through to the other side. In a May filing with FERC, the state team reported that further field work would be required to assess the feasibility of trenchless crossings including, in some cases, drilling bores holes to determine soil conditions. “Provide a schedule as to when these additional geotechnical and geophysical studies will be completed and dates for when the revised trenchless feasibility crossing studies will be provided,” FERC asked Oct. 2. • An explanation why the number of pipeline crossings of the Atigun and Dietrich rivers and temporary work areas between 166.2 and 168.6 miles south of Prudhoe Bay “cannot be reduced to minimize in-stream impacts and bank disturbance and destabilization,” FERC said. “As currently proposed, there are seven crossings of the Atigun River and three crossings of the Dietrich River.” • Where and how the project would obtain water to build construction ice roads north of the Brooks Range. • Additional information on the impact of ballast waters that LNG carriers would discharge as they arrive in Cook Inlet to load up at the LNG terminal. The ballast waters would be up to 25 degrees warmer than the ambient waters of Cook Inlet, AGDC reported to FERC in an earlier filing. • An explanation of how AGDC’s proposal for 3.5 inches of concrete coating on the 42-inch-diameter pipe laid across the Cook Inlet seafloor to reach Nikiski would comply with federal regulations which require “that the top of the pipe is below natural bottom, unless the pipe is supported by stanchions, held in place by anchors or heavy concrete coating, or protected by an equivalent means.” • A more detailed crossing plan for Cook Inlet that includes a description of how the strong currents could affect stability of the pipeline during construction and operation. “Explain if tidal and other flow currents would cause movement of debris and boulders across the pipeline,” FERC asked. And provide “a description of how the pipe would be anchored for tidal currents throughout pipe lay operations, especially in the near-shore transition areas … (and) a description of how the concrete-coated pipe would be handled during pipe lay operation to ensure the pipe is not buckled or damaged due to weight and water currents.” What would AGDC do to reduce the risk of freshwater aquatic invasive species from equipment brought into the state for project construction. • A list of measures AGDC would use to minimize impacts on Cook Inlet beluga whales during construction and use of the freight offloading dock in Nikiski. The corporation’s June 11 response to FERC “did not address part of our question on what mitigation measures were planned for construction … and increased activity in the area … used by Cook Inlet beluga whales for feeding, giving birth and raising young.” • Plans for a new public road, parking and a public path to the beach during construction of the LNG plant in Nikiski. AGDC has told FERC it is considering building an alternate public access point south of the marine terminal to make up for its plan to block existing access to the beach. • More information on AGDC’s plan to take 1 million gallons of water per day from the city of Kenai’s public water system to meet the LNG plant’s freshwater requirements, including the effect of the proposed withdrawals on the aquifer. As with past requests from FERC, the state project team will start providing answers and a schedule for when it will complete the work. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Companies, countries jockey to fill mid-2020s LNG demand

A lot has changed between 2013, when Russian gas producer Novatek and its French and Chinese partners decided to go ahead with the $27 billion Yamal LNG venture, and this month when a Shell-led consortium made the same decision for its $31 billion LNG Canada project in Kitimat, British Columbia. Global LNG trade grew 30 percent over the five years; a dozen more countries are importing the fuel; and more LNG is being sold under spot and short-term deals as buyers take advantage of the highly competitive and changing marketplace. The Canadian project could be the first of several in the next year or so as suppliers look to fill an anticipated supply gap in the 2020s and beyond. The world’s No. 1 LNG producer, Qatar, is expected to decide next year to go ahead with a 40 percent boost in its output capacity to 110 million tonnes a year. “If you look at the demand curve and the supply coming on stream, there are simply not enough projects being sanctioned or under development to meet demand by 2023-24,” said Jessica Uhl, Shell’s chief financial officer. “There needs to be 200 million tonnes annual LNG capacity authorized by 2025 to meet future demand,” Sanford C. Bernstein &Co. analysts said. “This is the start of a major LNG investment wave.” Global liquefaction capacity was almost 370 million tonnes as of March, according to the International Gas Union, with an additional 60 million tonnes under construction. New export projects are vying for approval in Russia, Mozambique and the United States, along with capacity expansion in Papua New Guinea. But in September, China imposed a 10 percent tariff on LNG imports from the U.S. in retaliation for levies imposed by the Trump administration. “This is not very good for American LNG projects working hard to take final investment,” said Morten Frisch, a U.K.-based gas-industry consultant. Shell said construction of the LNG Canada project will start immediately, with production to begin before 2025. The first-phase capacity will be 13 million tonnes of LNG per year, with the potential to double the output. At 26 million tonnes, the plant would be about equal to the liquefaction capacity of Algeria, the world’s sixth-largest LNG exporter in 2017. The odds that LNG Canada will proceed with the second phase “is all but an inevitability” due to the economies of scale, National Bank of Canada analysts reported earlier this year. In addition to two liquefaction trains, LNG storage tanks and loading berths at the coastal site on a deep-water fjord, the project includes construction of a 416-mile pipeline from prolific shale gas fields in northeastern B.C., near the Alberta border. LNG Canada has selected TransCanada to build, own and operate the 48-inch-diameter pipeline, which is estimated at $4.8 billion (U.S) with an initial capacity to move 2.1 billion cubic feet of gas per day and expansion potential to 5 bcf. Permits are in place for the pipeline and contractors have been hired, a TransCanada spokeswoman said last week. The company has conditionally awarded $640 million in contracting and employment opportunities to northern B.C. Indigenous-owned businesses, and said it now has the support of all the elected Indigenous groups along the route. LNG Canada “set a new standard” for respectful consultation with First Nations, said Brenda Duncan, the Haisla Nation’s deputy chief councillor. “When LNG Canada first engaged with us, it was the first time ever that we were seen as partners. … We are now participants in our own economy,” she said. LNG Canada and the Haisla reached a benefits agreement for the project, though terms have not been disclosed. None of the LNG Canada partners have disclosed their gas supply costs, production costs or sales prices, although the Australian Financial Review reported last week that the project would be able to land cargoes in Asia at $7.10 (U.S.) per million Btu, quoting Sanford C. Bernstein &Co., a global money management and research firm. The Wall Street Journal reported that Shell expects its investment to generate an internal rate of return of about 13 percent. LNG Canada was first announced in 2012 and had been scheduled for a final investment decision in 2016, but twice the partners pushed back the decision amid weak market conditions. Shell holds a 40 percent stake, with Malaysia’s national oil-and-gas giant Petronas at 25 percent, Japan’s Mitsubishi and PetroChina each at 15 percent, and Korea Gas with 5 percent. Petronas joined the project in May. The Malaysian company holds substantial gas reserves in Western Canada, which it had planned to use to supply its own LNG project, Pacific NorthWest LNG, near Prince Rupert, B.C., north of Kitimat, but Petronas abandoned that development in July 2017. Western Canadian producers have been waiting for the country’s first LNG project to provide a market for their gas, which sells at a steep discount to U.S. production due to pipeline constraints and strong competition in Eastern Canada from U.S. shale gas output. Bank of America Merrill Lynch recently forecast the Western Canadian gas benchmark price could fall to $1 by 2020. “Export projects don’t come soon enough,” the bank said. The LNG Canada partners will each be responsible for their own gas supply and LNG sales, free to sell it however and to whomever they want, said Andy Calitz, CEO of the joint venture. “What you are essentially seeing is speculative development … using a model that has not been traditionally the model for developing big LNG projects in the past,” said Jason Feer, head of business intelligence at Poten &Partners. “Most LNG projects that went to FID had pre-sold a significant percentage of their output via long-term contracts.” In Kitimat, the celebrations Oct. 6 included a beer garden, concerts and fireworks. “We have one more thing (to be thankful for) this Thanksgiving,” said Alan Yu, a resident of Fort St. John, B.C., in the gas-producing region. Canada celebrated Thanksgiving on Oct. 8. Economists had their own take on the political celebrations in Canada. “Politicians like to take credit for things that are good and they like to shift blame for things that go bad. An investment like this only happens if there’s commercial viability,” Kenneth Medlock, Rice University’s Baker Fellow in Energy and Resource Economics, was quoted by a Vancouver newspaper Oct. 3. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

As more than 3,500 delegates gathered in Barcelona for Gastech, the world’s largest natural gas conference, a continent away in Beijing, capital of the world’s largest energy consumer, the government on Sept. 18 ordered a 10 percent tariff on U.S. liquefied natural gas deliveries to China. It’s not easy to upstage a conference that promoted more than 700 exhibitors, 350 speakers and 250 presentations, but the escalating U.S.-China trade fight made headlines that day. “Ultimately, China has a lot of growth in its LNG demand and the U.S. is a very material source of supply, so having an impediment stopping the two from getting together … that creates an inefficiency in the market, and no one wins from that,” Steve Hill, an executive vice president in Shell’s unit that provides natural gas and LNG, as well as marketing and trading services, told S&P Global Platts an interview on the sidelines of the conference. Few analysts said they expect any impact on global prices in the near term, but longer term many said it will make it harder for proposed U.S. LNG projects to line up customers in China and to secure financing. “The bigger implication will be on the launching of new projects,” Hill said. The longer the trade dispute lasts, the less likely that U.S. projects will find financial backers, said Charlie Riedl, executive director of the Center for Liquefied Natural Gas, a U.S. industry group, speaking with Reuters from Barcelona. China’s decision to impose tariffs, which took effect Sept. 24, means LNG is no longer an “innocent bystander” in the trade fight between the two countries, Riedl told S&P Global Platts. “There is a realistic possibility getting to FID (final investment decision) will be difficult,” he said of the multiple U.S. export projects in various stages of planning, design and permitting. “While we would like to see this resolved quickly, I don’t see that happening right now.” But what may be bad for U.S. gas producers and project developers could be good for other LNG suppliers. “Long-term implication is Chinese money is likely to look to countries they feel they can rely on for gas supply — and that is good news for most of the new non-U.S. LNG projects,” Trevor Sikorski, head of gas research at consultancy Energy Aspects, told the Wall Street Journal. “The tariffs will push Chinese buyers to other sellers in Asia and the Middle East because the U.S. will no longer be considered a low-cost option,” said Ira Joseph, head of gas and power analytics at S&P Global Platts. An October cargo out of Cheniere Energy’s terminal in Sabine Pass, La., fetches $9.04 per million Btu in Guandong Dapeng, China, reported S&P Global Platts Analytics. By comparison, a Qatari cargo to the same port goes for $10.48. A 10 percent tariff would make the U.S. gas less competitive. Speaking at Gastech before China’s announcement, Saad Sherida Al-Kaabi, CEO of Qatar Petroleum, the biggest LNG exporter in the world, said the tariff might help his company but could hurt the industry. “I don’t think that long-term it’s good for the market to have politics and to have taxation on a very important basic requirement for humanity, which is energy,” he said. China ordered the tariff on LNG and a list of more than 5,000 other U.S. products in retaliation for President Donald Trump’s decision a day earlier to impose a 10 percent tariff on $200 billion a year worth of Chinese products imported by the United States, climbing to 25 percent by the end of the year. The 10 percent tariff on U.S. LNG could have been worse — China originally had threatened a 25 percent levy. China is the world’s second-largest LNG buyer and expected to eventually overtake Japan for the No. 1 spot. The nation of almost 1.5 billion people is looking to use more gas and less coal to clean up its notoriously polluted air. The United States, the world’s largest gas producer, has been looking to China as a prime market for export sales. “In the 12 months up until June 2018, China was the second-largest buyer of U.S. LNG, accounting for approximately three million tonnes per year,” Wood Mackenzie research director Giles Farrer said in a note following the tariff order. “There has likely been some longstanding damage done to the perception of reliability of U.S. LNG supply in the eyes of Chinese buyers who will shape the next wave of global LNG projects,” Saul Kavonic, Credit Suisse Group’s director of Asia energy research, was quoted by Bloomberg the day after the news. About 15 U.S. LNG export projects are targeting a final investment decision this year and next. “It is hard to see any of these hopeful projects getting another Chinese buyer signed up for long-term volumes,” Sikorski told Bloomberg. Hours before the tariff news, Laszlo Varro, chief economist at the Paris-based International Energy Agency, told CNBC news at Gastech that a lack of export capacity could force curtailment in the U.S. shale gas boom. “Without additional investments into American liquefied natural gas projects, the American gas industry will have to keep gas in the ground, which would be … economically quite disruptive,” Varro said. A week before Gastech, a senior U.S. Department of Energy official told a Senate committee: “Every molecule of energy that the United States exports is exporting freedom to the world.” Putting that statement in the context of the U.S.-China trade war, a columnist for the London-based Financial Times quoted Nikos Tsafos, a senior fellow at the Center for Strategic and International Studies in Washington, D.C.: “This idea that the U.S. is exporting freedom has been somewhat premised on the notion that U.S. LNG is somewhat better, or less risky, than other gas. I think that has been a very difficult thing to say over the past 18 months.” The world has more than enough LNG, the columnist noted, giving China the freedom to choose where to buy gas. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Mat-Su Borough seeks ‘fair and accurate’ analysis of port site

The Matanuska-Susitna Borough alleges the state-led Alaska LNG Project team has presented “numerous factual errors and willfully misleading statements” to federal regulators and failed to perform “a good faith and unbiased analysis” of borough land at Port MacKenzie for the proposed gas liquefaction plant and marine terminal. The borough filed 193 pages with the Federal Energy Regulatory Commission on Sept. 14 supporting its property as a possible site for the multibillion-dollar investment and extensively rebutting information the Alaska Gasline Development Corp. presented to FERC in July. But more than just debating the site’s attributes — or detractions — the borough urged the commission “to refrain from further action” on the Alaska LNG Project. “FERC must not proceed with its review of AGDC’s application” until the state team “has presented a fair and accurate analysis of Port MacKenzie as an alternative site,” the borough said in the first page of its filing. The borough did not file a motion seeking formal commission action, and FERC is not required to respond to the borough’s comments. FERC is five months away from its published date for for releasing the project’s draft environmental impact statement, or EIS. The exhaustive review, as required by federal law, will consider alternatives for multiple aspects of the project, such as pipeline routing, vegetation clearing and restoration, temporary construction roads, waterway crossings — and the location of the LNG plant and marine terminal, estimated to cover as many as 900 acres. AGDC for the past year has been working to answer hundreds of questions from FERC and other federal agencies about project construction and operations, filling in information gaps for the EIS. The state corporation’s most recent responses were submitted Sept. 14, addressing an alternative pipeline routing just inside the eastern boundary of Denali National Park and Preserve, visual impacts of the pipeline at multiple points on the route and air quality issues. The state team expects to answer the last of FERC’s requests in October, though follow-up questions are anticipated as the commission staff and EIS contractor work toward their February 2019 timeline for release of the draft EIS for public comment. FERC authorization is required to construct and operate the gas pipeline from Prudhoe Bay on the North Slope due south through the state and the coastal terminal for LNG exports. The Mat-Su Borough owns the seldom used Port MacKenzie property across Knik Arm from Anchorage and has long promoted the site for industrial development. The land is about 65 air miles northeast of AGDC’s preferred location in Nikiski, on the eastern shore of Cook Inlet, in the Kenai Peninsula Borough. Both the Kenai and Matanuska-Susitna boroughs have hired expensive Washington, D.C., law firms to represent their interests at FERC, and both municipalities have been granted intervenor status at the federal agency, giving them the legal ability to seek a rehearing of FERC decisions and, if unsuccessful at that stage, to challenge the commission in federal court. Producers selected Nikiski in 2013 The Alaska LNG team in fall 2013 selected Nikiski as its preferred location for the terminal and stayed with Nikiski when the project entered pre-file status with FERC in September 2014. In its Sept. 14 filing with FERC, the Mat-Su Borough said failure to recognize Port MacKenzie as a feasible or preferred site goes back six years. In 2012, North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips initiated a review of a potential LNG project, with the state joining the effort in 2014 as a minority equity partner. The producer-led team settled on Nikiski as the best alternative after considering more than two dozen sites in Southcentral Alaska. The producers pulled out in 2016 after declining to spend $1 billion or more on further permitting and full engineering and design work in a weak market. AGDC then took over management of the $43 billion project and applied to FERC in April 2017, using state funds to cover its costs. The Mat-Su Borough elevated its challenges after the state took over the project, filing objections with FERC. The borough alleged Sept. 14 that the alternatives analysis included with AGDC’s application 17 months ago was flawed, unfairly excluding Port MacKenzie. “AGDC’s continued delay in providing accurate information to the commission regarding Port MacKenzie serves no purpose but to further delay” the EIS, the borough said. FERC asked the state in February to answer specific questions — not a full economic and engineering review — about Port MacKenzie for the EIS alternatives analysis. AGDC submitted its answers in July. The borough accused the state project team of purposefully presenting FERC with information on two sites that “likely would maximize environmental impacts,” including high impact to wetlands, ignoring a wetlands-free “optimum site” identified by the borough. “AGDC chose to make no effort to find a least-damaging site,” the borough alleged in its notes of a June 7 meeting with state project officials. Rail extension, Knik Arm bridge caught in dispute In addition, the borough dismissed as contrived AGDC’s July assertion to FERC that a proposed rail line at Port MacKenzie would be in the way of the LNG project. “Future rail development … does not even exist at this time,” the borough said in its Sept. 14 filing. In July, the state team told FERC that federally-mandated safety zones around the liquefaction plant and storage tanks would require relocating the proposed railway and the existing port access road. But while criticizing AGDC for raising the issue of the unbuilt railroad extension, the borough has promoted the potential rail connection as a sales point for the site. It said in a January 2018 filing with FERC: “In addition, a 32-mile rail link connecting Port MacKenzie to the main line of the Alaska Railroad is under construction. The link will shorten the distance between the Interior and tidewater, enhancing opportunities for the development of new industries with low transportation costs.” A 2017 engineering report prepared for the borough, and submitted to FERC, also highlighted the potential rail connection: “Port Mackenzie is an ideal site for the Alaska LNG facility site. … Favorable criteria include easy access to port, rail and truck infrastructure.” The state has spent more than $180 million in the past 10 years on building segments of an Alaska Railroad extension to the port but the line is unfinished and the project needs an additional $120 million or more to complete the job — with no ready cash available and little political support outside the borough. As for the existing port access road, AGDC looked to avoid safety and security concerns presented by the road running through the LNG plant site. The borough’s recommended “optimum site,” however, shows a significantly longer stretch of the road passing through the property’s northern and eastern acreage. The Mat-Su filing also challenged AGDC’s contention that ship traffic at the port to move logs from a recently approved borough timber harvest contract would conflict with the LNG project’s construction and operations. The borough said it believes there is enough room at the port to accommodate multiple users. Besides, the borough said, “There is great likelihood that timber exports will not occur given current import tariffs by foreign countries.” Another contentious point is the proposed Knik Arm Bridge to connect Anchorage and Port MacKenzie. AGDC told FERC the nearby bridge could affect LNG carrier traffic to and from the loading berths. The borough argued that AGDC based its concern on a bridge that may not be built. “There are no current plans for an orbital launch and recovery complex in Anchorage, and no current plans to construct a giant mermaid statue in the middle of Cook Inlet,” the borough said in what it called an “absurd analogy (that) demonstrates the meaninglessness of AGDC’s assertion.” The borough added: “These examples are outlandish, but AGDC raising the specter of some potential unknown is likewise outlandish.” The state has abandoned the bridge project, long promoted by the Mat-Su Borough, though advocates continue to push for its development and critics equally push to ensure that never happens. Other disputes between the borough and AGDC include: • The borough said it is willing to sell the land to AGDC, arguing that the state team reported the land was available only for lease. • The borough said significantly more acreage is available at Port MacKenzie than AGDC reported to FERC. • The borough said the project would not need to construct protective ice-management (deflection) structures at the LNG carrier loading berth; AGDC said otherwise. • The project could use the existing barge facilities at the port, the borough said, contrary to AGDC’s position that the barge dock and trestles would need to be replaced. • And while AGDC said the additional 116 miles round trip from Port MacKenzie to Asian markets, rather than Nikiski, would add costs by requiring one more LNG carrier in the fleet to handle the project’s constant output, the Mat-Su Borough said it is a non-issue — the ships could just run a little faster during the week-long voyage to make up the difference. Most of the contested information was included in AGDC’s detailed filing with FERC on July 13, where the state corporation cited “significant issues” favoring Nikiski over Port MacKenzie, including: • Conflicts with other actual and proposed uses of Port MacKenzie. • The need to move the port’s access road and proposed railroad extension away from the LNG plant site. • Wind, current and sea-ice conditions that would hamper winter operations at the port site. • The extreme tidal range at Port MacKenzie. • Additional dredging that would be required to widen the shipping channel through the Knik Arm Shoal to allow safe two-way ship traffic through the area. • Port MacKenzie’s location within Cook Inlet’s most protected beluga whale critical habitat area. As to Port MacKenzie and its proximity to critical habitat for beluga whales, which are sensitive to underwater noise, the borough responded Sept. 14 it is “taking a proactive approach with beluga recovery,” including helping to fund beluga research efforts. “New research suggests improvements to management or marine construction techniques. … Port MacKenzie will set a new standard for port development … and (will) be the local government leader in the recovery of beluga whales.” Valdez weighs in A third Alaska municipality, the City of Valdez, also has filed with FERC in support of its community’s waterfront as the best site for the LNG terminal. Like the Mat-Su and Kenai boroughs, Valdez is an intervenor in the proceedings, but its filings have been less confrontational than the Mat-Su’s submissions. In a May 2017 filing, Valdez said it would be a lower-risk, lower-cost option than Nikiski, with less “environmental degradation.” In addition, the city told FERC that bringing the project to Valdez would ensure that “its citizens and businesses have access to inexpensive natural gas.” Valdez, about 170 air miles east of Nikiski, is on Prince William Sound, and is the location of the Alyeska oil terminal. The producer-led project team in 2012 considered Valdez, Nikiski, the Matanuska-Susitna port area and about two dozen other potential LNG plant sites in Cook Inlet and Prince William Sound. The state Legislature in 2010 created AGDC to promote and participate in development of a North Slope gas project. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Gas pipeline opponents finding success halting projects

Though oil pipelines have attracted bigger protests — Keystone XL from Canada’s oil sands into the United States and Dakota Access to move Bakken crude to the Midwest — opposition to natural gas pipelines is growing. While many of the challenges are focused against hydraulic fracturing for shale gas and in support of renewable energy, others are specific to local land and water issues, Much of the opposition is in the mid-Atlantic states, where the boom in shale gas drilling in Appalachia’s Marcellus Basin has elevated the visibility — and controversy — of pipelines in an area generally unaccustomed to the oil and gas industry. Opponents have held rallies, pushed local politicians for support, gone to court — even illegally camped out in trees to block pipeline construction. “It’s definitely not getting easier to build a new pipeline,” Stan Chapman, TransCanada’s president of U.S. gas pipelines, told Reuters during June’s World Gas Conference in Washington, D.C. The 600-mile Atlantic Coast gas pipeline — from West Virginia through Virginia and into North Carolina — has drawn significant community opposition, including its plan to tunnel under the James River in Virginia. Construction is underway even as opponents continue to challenge regulatory approvals for the $6.5 billion project. A federal appeals court on Aug. 6 vacated permits issued by two federal agencies for the pipeline. The court told the U.S. Fish and Wildlife Service to impose more protections for threatened or endangered species, including mussels, bumble bees, crustaceans and bats. The court also told the National Park Service to better explain why a pipeline crossing under the Blue Ridge Parkway in Virginia is consistent with the conservation and preservation purpose of a national highway. The project developer said it expects the agencies to quickly address the court’s concerns. Meanwhile, construction will continue in areas unaffected by the court action. Completion is planned for late 2019. The $3.7 billion Mountain Valley gas line could be delayed past its scheduled 2019 completion after the Federal Energy Regulatory Commission — prompted by a court ruling against the project — on Aug. 3 ordered all work to stop on the 303-mile West Virginia-to-Virginia pipeline. The court ordered the U.S. Forest Service and Bureau of Land Management to take a closer look at the line’s environmental impact. Changes in the pipeline route could require “further authorizations and environmental review,” FERC said. Pipeline opponents were successful with their legal strategy in stopping the proposed $1 billion Constitution Pipeline to transport Pennsylvania shale gas into New York. Section 401 of the federal Clean Water Act gives states the right to review projects to ensure they don’t harm local waters. “It essentially gives states veto power over federal decisions,” said Daniel Estrin, advocacy director for the Waterkeeper Alliance. The U.S. Supreme Court on April 30 denied a request from the pipeline developer to review the New York state decision that denied a permit under the Clean Water Act, emboldening other pipeline opponents to go after the same tactic in their states. Also in New York, the New York City Comptroller this month came out against the Northeast Supply Enhancement Project, a $1 billion gas pipeline that would cut across 23 miles of lower New York Bay to meet demand growth in Brooklyn, Manhattan and Queens — especially as consumers switch from fuel oil to gas for heat. “Allowing the construction of the pipeline risks damage to many of New York’s most precious habitats and natural assets,” the city official said. Though FERC’s draft EIS said environmental impacts during construction would be temporary, the comptroller said the EIS did not sufficiently account for climate change and rising sea levels. He wants a re-do. Also on the Atlantic Seaboard, the Alamance County Board of Commissioners in North Carolina on Sept. 4 unanimously adopted a resolution opposing a 72-mile connecting line to bring Marcellus gas into the distribution system. The board’s opposition focused mostly on water quality issues. The commissioners, who have no authority to stop the pipeline, sent their resolution to FERC. Even Texas is not immune to gas controversies. Two groups in the Rio Grande Valley — the Save RGV from LNG and the Lower Rio Grande Valley Sierra Club — oppose three LNG terminals proposed for the Port of Brownsville. FERC is scheduled to release draft environmental impact statements for the projects late this year. Several communities in the area have adopted resolutions against the LNG facilities. In Colorado, voters will decide in November whether to ban oil and gas drilling and flowlines within 2,500 feet of homes, businesses, playgrounds, waterbodies and drinking water sources. The state estimates that 85 percent of non-federal land in Colorado would be off-limits to new drilling. The current limit is 500 feet from buildings. Fracking opponents collected signatures to put the issue on the ballot, citing the increase in drilling amid the growing suburban communities north of Denver. The initiative is widely expected to face legal challenges if it passes. In the Pacific Northwest, the Puyallup Tribe of Indians has asked the city of Tacoma to re-examine whether a $310 million liquefied natural gas plant and storage facility — now under construction — is safe. The plant would liquefy gas and store the LNG in an 8-million-gallon tank to meet peak demand from utilities and serve as a marine fueling depot. The Tribe wants a supplemental analysis of the plant’s impact. The facility is scheduled to start service in 2020. Opponents to the proposed $10 billion Jordan Cove LNG project in Coos Bay, Ore., have long challenged land clearing for a pipeline, the risk to waterways and safety of the LNG plant. Now the developer is having trouble with the state Department of Energy, which last month recommended denial of the developer’s request for a waiver from a full review of the project’s power-generation plant. Calgary-based Pembina Pipeline is behind the Jordan Cove LNG terminal, which would provide an export outlet for gas from the Western U.S. and Canada. FERC is reviewing the project, including a 229-mile pipeline to link the LNG plant with the North American gas supply. The final environmental impact statement is scheduled for November 2019. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

FERC shaves a month off timeline for Alaska LNG decision

The Federal Energy Regulatory Commission on Aug. 31 moved up by one month its schedule for the Alaska LNG project’s environmental impact statement and commission decision. FERC now expects to issue the project’s draft impact statement in February 2019, instead of March, assuming the state-led project team provides “complete and timely responses to any future data requests” and cooperating regulatory agencies “provide input on their areas of responsibility on a timely basis.” The commission’s Aug. 31 notice set Nov. 8, 2019, for issuance of the project’s final EIS, a month earlier than the Dec. 9, 2019, schedule issued in March of this year. Under the revised timeline, FERC’s deadline to decide on the Alaska Gasline Development Corp. application would be no later than Feb. 6, 2020, instead of the original timeline of March 8, 2020. AGDC filed its application with FERC in April 2017. Commission authorization is required to build and operate an onshore natural gas liquefaction plant and export terminal in the United States. The state corporation took over the project almost two years ago after North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips declined to proceed with spending the hundreds of millions of dollars required over the next couple of years on permitting and further engineering for the project. As proposed by the state, the $43 billion venture would pipe North Slope gas 807 miles to a liquefaction plant and marine terminal at Nikiski, on the Kenai Peninsula. The location of the LNG plant, however, is contentious, and will be considered in the federal EIS. The Matanuska-Susitna Borough has intervened in the FERC proceeding to promote its Port MacKenzie as a better site than Nikiski, and the city of Valdez also has filed as an intervenor in support of its community as a better option. The Kenai Peninsula Borough earlier this month told FERC that it, too, wants intervenor status to protect its interests. • The state-led project team is nearing the end of its work assignments from FERC, submitting more details Aug. 15 of project design and operations. The filing provided more information on:The project’s preferred three-mile route to relocate the Kenai Spur Highway around the LNG plant site for safety and security reasons. • A noise analysis of the new Kenai Spur Highway route. • Alternatives for routing several miles of the 42-inch-diameter gas pipeline just inside the eastern edge of Denali National Park and Preserve rather than running the pipe through a steep hillside outside the park boundary. • Sediment transport modeling to help predict how open-cut installation of the gas pipeline across waterways could affect fish habitat in 11 anadromous streams selected by federal regulators for further review. • Visual impacts at five selected sites along the pipeline route near Denali National Park and Preserve. • Turbidity in Cook Inlet that would be stirred up by dredging — and disposal of dredged material — required for construction and operation of a barge landing and ship dock that would be used for offloading equipment at Nikiski. In addition to fulfilling FERC’s data requests, the state corporation continues working toward possible gas supply agreements with North Slope producers, long-term sales contracts for the project’s output, financing and lining up investors for the venture, which would produce 20 million tonnes of LNG at full capacity. AGDC expects to spend about $4 million per month of state funds during the fiscal year that started July 1. The corporation is planning what it calls its “equity road show” for later this year and early 2019 to introduce and promote the project with potential investors. Goldman Sachs and the Bank of China are assisting AGDC in that effort. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Russia paying cost to be an LNG boss

Russia started as a bit player on the liquefied natural gas stage less than a decade ago but is not content in that role and wants to share top billing. In 2009, when Russia’s first LNG export terminal went online, the Sakhalin-2 project in the Far East provided about 4 percent of the world’s liquefaction capacity. When the country’s second liquefaction plant, Yamal LNG, reaches full capacity early next year, Russia will have moved up to 26 million tonnes annual capacity, 7 percent of the world’s total. If gas producer Novatek, which operates Yamal LNG, goes ahead with its plan for a second project in the Siberian Arctic, Russia could climb to 46 million tonnes in the 2020s, in the No. 4 spot behind Qatar, Australia and the United States. Plans to expand Sakhalin production would further bolster Russia’s position in Asian markets, where it holds a decided geographic advantage. The Sakhalin terminal is just 750 miles north of Tokyo Novatek’s own long-term goal is to produce 55 million to 60 million tonnes of LNG per year by 2030, company CEO Leonid Mikhelson said earlier this month. Government financing, tax breaks, building infrastructure and providing icebreakers are part of the plan. “Don’t think of these as commercial projects,” a global energy analyst foretold at a Washington, D.C., conference six years ago. Rather, he said, accept that Russian politics are part of the equation. The government might be willing to subsidize a project to promote economic development or to gain momentum in the growing Asian market. That same summer as the Washington conference, Russian President Vladimir Putin signaled the gradual end of state-controlled Gazprom’s monopoly on gas exports, opening the way for rivals, including Novatek, to do business in Asia. Gazprom has long profited from its exclusive position in pipeline gas sales to Europe, which Putin did not touch. The easing of export restrictions applied only to LNG. As part of the decision to promote LNG exports, the government’s 2013 actions included reducing its mineral extraction tax and canceling export duties on new Arctic offshore oil and gas projects. The government further assisted in Yamal by financing construction of a port, airport, pipelines, icebreakers and dredging to create a navigable channel to the port, at a cost of at least $9 billion. The regional government contributed a property tax exemption and lower corporate profits tax rate. Just five years later, two of three liquefaction trains are now in production at Yamal, with the third train scheduled to start up early 2019, bringing the $27 billion project’s capacity to 16.5 million tonnes per year. The partners are Novatek (50.1 percent), France’s Total (20 percent), China National Petroleum Corp. (20 percent) and China’s Silk Road Fund (9.9 percent). China also provided $12 billion in financing for Yamal, after U.S. sanctions blocked other lenders. Novatek and the country’s top oil producer, Rosneft, both lobbied for LNG export rights. Rosneft and its partner ExxonMobil for years have considered adding a gas liquefaction plant to their Sakhalin-1 project, which started producing oil in 2005. Though the companies continue to plan their own LNG plant, Gazprom would prefer that they pay to run their gas through its Sakhalin-2 project. Reuters this spring reported that ExxonMobil and Rosneft had invited companies, including China National Petroleum Corp.’s engineering arm, to submit construction bids by October for their $15 billion LNG project with an initial capacity of 6 million tonnes per year. The news service reported a final investment decision is due next year. Gazprom, meanwhile, is looking at adding a third train at its Sakhalin plant but lacks enough gas reserves for the expansion. Reaching a deal with ExxonMobil/Rosneft for supply would be the fastest option using existing infrastructure because some of the gas is being pumped back into reservoirs, Sakhalin-2 commercial director Andrey Okhotkin told a Russian LNG conference this summer. While oil and gas giants Gazprom and Rosneft are active in the Far East, Novatek wants to expand in the Arctic. The company is targeting mid-2019 for a final investment decision on its Arctic LNG-2 plant, which would be built east of Yamal. Estimated at $25.5 billion, the plant is proposed at 19.8 million tonnes per year, with start-up in 2022-23. In June, Total agreed to buy a 10 percent stake in the venture, and Novatek has signed a memorandum of understanding with Korea Gas expressing “mutual interest for KOGAS to enter into the Arctic LNG-2 project.” Talks also are underway with Saudi Arabia’s Aramco, China National Petroleum Co. and Japan’s Marubeni Corp. In anticipation of going ahead with Arctic LNG-2, Novatek is building a shipyard in the port city of Murmansk for construction of the production modules that would be towed to the plant site on the Gydan Peninsula. Ice-class LNG carriers move Yamal gas through the Northern Sea Route to East Asia and also westward to Europe, but the ships are significantly more expensive to build and operate than the usual LNG tankers. Novatek is pursuing an answer to that costly dilemma — trans-shipment terminals to transfer the fuel to less-expensive, traditional carriers after the ice-class ships have reached open water. The company wants to build an LNG trans-shipment terminal by 2023 on Russia’s Kamchatka Peninsula, about 1,500 miles north of Tokyo. Trading house Marubeni and shipbuilder Mitsui O.S.K. Lines are among the Japanese companies considering participation in the project. Tokyo also might help through public institutions such as the Japan Bank for International Cooperation and Nippon Export and Investment Insurance, according to a report in the Nikkei Asian Review. And if one trans-shipment terminal is good, two might be better. Novatek is considering building an LNG trans-shipment terminal near Murmansk, CEO Mikhelson said Aug. 20. The location will be determined “in the nearest future,” Mikhelson said. The use of Ura Bay, 25 miles from Murmansk, is under discussion with Russia’s Defense Ministry, which operates a submarine base nearby. The transfer terminal, on the route from Yamal to Europe, would strengthen the company’s positions in the global LNG market, Mikhelson said. “We are losing,” he said, “and will continue losing in transportation with ice-breaking tankers.” ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

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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