Larry Persily

AGDC stays on schedule with latest batch of answers to FERC

While cutting back on overall spending to preserve its money to last into 2020, the Alaska Gasline Development Corp. continues answering questions and providing additional information to federal regulators, submitting on March 1 the first of six batches of information it is scheduled to submit through September. The information will be included in the Federal Energy Regulatory Commission’s safety review and final environmental impact statement, or EIS, but not necessarily in the draft EIS that is scheduled for release in June. The March 1 packet answered about 60 of FERC’s information requests from January, dealing mostly with fire safety, equipment and procedures, including trucking fuel to the facilities; mapping fault lines, unstable slopes and other geologic hazards; and plans for a temporary access road during construction that would cross over existing buried pipelines at Prudhoe Bay. The state-led Alaska LNG project team had told FERC it would answer the remaining questions about fire safety, spill-containment safeguards, hazard mitigation and other design issues in monthly batches March through July. The requested information covers various details of the North Slope gas treatment plant at Prudhoe Bay, and the liquefaction plant and liquefied natural gas storage tanks in Nikiski. It will be September, however, before AGDC provides federal regulators with more information about the project’s 27-mile underwater pipeline crossing of Cook Inlet to Nikiski. FERC wants more geotechnical data about the seafloor. It also wants to know if AGDC expects tidal flow and other currents will move debris and boulders across the pipeline, and how the project proposes to stabilize and protect the line against tidal currents and boulders. If all goes according to schedule between the state project team, FERC and other federal agencies involved in preparing the EIS, the final impact statement is scheduled for release in March 2020. That allows nine months for public and agency comment, public hearings, review and revisions between the June 2019 draft and the final EIS. The single EIS will be used by all federal agencies involved in regulatory oversight of the proposed Alaska LNG project, which includes a gas treatment plant at Prudhoe Bay to remove carbon dioxide and other impurities, 807 miles of large-diameter high-pressure steel pipe to move gas to the liquefaction plant and LNG export terminal in Nikiski. Though the state corporation expects to end the current fiscal on June 30 with about $20 million still available to spend, it could run out of funds about the same time that FERC finishes work on the EIS according to a staff financial presentation at the March 6 AGDC board meeting. The corporation is cutting back on its leased office space in Anchorage, closing its Houston office and taking other steps to stretch out its available funding. Interim AGDC President Joe Dubler told the board March 6 that the corporation also has been able to reduce its legal and contractual spending this year. The Alaska Legislature is now working to put together the state budget for fiscal year 2020, which starts July 1, but there was no request before lawmakers as of March 11 to appropriate additional funds to AGDC. Many legislators have said they are looking for evidence that the estimated $43 billion project is commercially viable before proceeding past the EIS. Gov. Michael J. Dunleavy has said he opposes state control of the project — with the state taking all the risk — and he wants to see the North Slope producers back on board. “AGDC will only pursue Alaska LNG if the project viability is assured,” Dubler told the board March 6. “AGDC will seek third-party support from qualified, experienced LNG project owners and operators to build, own, and operate the project.” The state took over the project more than two years ago after North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips — citing market conditions — declined to spend the billion-plus dollars that would be required to complete permitting, final design and engineering. The state, anxious to see the project continue at a faster pace, took over 100 percent funding of the application to FERC and the environmental impact statement. AGDC has not contracted for construction-ready final engineering and design work, which could cost as much as $2 billion, Dubler told the board March 6. While working to finish the EIS, the state corporation continues talking with potential investors and customers, looking to determine if the project can pass the economic-viability test. While continuing its quest for the large-volume Alaska LNG project, the state corporation has completed its original 2010 assignment when the Legislature created AGDC: Obtain regulatory approval for a smaller-volume backup project to deliver North Slope gas to Alaskans. The U.S. Army Corps of Engineers and federal Bureau of Land Management on March 4 signed a joint record of decision for the Alaska Stand Alone Pipeline, or ASAP, also known as the in-state project and the bullet line. The 733-mile pipeline would move North Slope gas south through the state, ending at a connection point near Big Lake, north of Anchorage, to ENSTAR’s gas distribution system for Southcentral Alaska. The project, estimated by AGDC several years ago at $10 billion, does not include a liquefaction plant or any other export component. The line’s maximum capacity would be 500 million cubic feet of gas per day, far less than the LNG project that is designed to handle 3.5 billion cubic feet per day at the entrance to the gas treatment plant at Prudhoe Bay. ASAP was intended to meet in-state needs for natural gas, in particular providing gas to Fairbanks and potential mining projects. The line’s capacity would be more than double the average daily demand of all Southcentral gas users. The state paid 100 percent of the cost of permitting to reach the federal record of decision, but there is no money available for final engineering and design. And, like the LNG venture, the economics of the backup project are questionable. The Legislature has appropriated about $480 million in state funds to AGDC for the two projects since 2010. The final EIS and record of decision on the backup line are helpful to AGDC and the larger gas pipeline project, particularly the decision by the Army Corps to allow construction in wetlands, with mitigation as required. “Because ASAP and Alaska LNG share a common path for 80 percent of Alaska’s LNG pipeline route, this permit and the underlying data will help the Alaska LNG project efficiently advance through the federal permitting process,” AGDC said in a prepared statement. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Jones Act leaves New England out of LNG boom

Western Canada, the U.S. Gulf Coast, West Texas and Appalachia are all overflowing with natural gas. So much so that prices are down and occasionally have turned negative in some areas, when producers actually had to pay someone to take their gas. Too bad there is no easy way to move more of that gas to the U.S. East Coast, New England and Canada’s Maritimes provinces, where natural gas customers are paying the highest prices in North America. The obstacles are by land and by sea. There is not enough pipeline capacity to reach the Eastern Seaboard. And a 99-year-old federal law, the Jones Act, requires that only U.S.-built and U.S.-flagged ships can move cargo between U.S. ports. The problem is, no such liquefied natural gas carriers exist. Examples of too much supply in gas-producing regions and too little of it reaching the gas-consuming coast are economically painful. Next-day natural gas prices at the Waha hub in the Permian Basin in West Texas tumbled to their lowest on record Nov. 27 because of limits on the amount of gas that could move out of the region by pipeline, Reuters reported. Prices fell to an average of 25 cents per million Btu that day. Even worse than a measly quarter, traders said small amounts of fuel were sold at negative prices as producers struggled to get rid of their gas. That compares to the U.S. benchmark price at Henry Hub, Louisiana, which averaged about $4 per million Btu in November. The Permian is the biggest oil-producing shale basin in the country, and because gas is associated with much of the oil coming out of the ground, it is also the nation’s second-biggest shale gas region, behind Appalachia. Permian drillers want the oil, which is much more valuable than gas, so they deal with the gas as best they can. New pipelines are being built or planned to move Permian gas production to the Gulf Coast, where a growing number of liquefaction plants can turn it into LNG for export, and to Mexico, which needs U.S. gas to cover its own production shortfall. But until the new lines are up and running, West Texas producers will have to take what they can get. The imbalance is just as noticeable in Canada, where last May 3 spot prices at Alberta’s AECO pricing hub closed at just 5 cents per million Btu, about $2.50 less than the U.S. benchmark price that day. Then in October, gas prices in Western Canada went into a freefall as a ruptured pipeline limited producers’ ability to get their gas to market. With one less conduit to move Canadian gas to customers south of the border, spot prices at Alberta’s AECO trading hub fell to 8 cents per million Btu on Oct. 19. At the other end of the price spectrum in November, gas prices at the New England trading hub rose to $13.70 per million Btu for Nov. 21, about triple the year-to-date average, Reuters reported. And when gas costs more, so does electricity. Next-day power prices in New England on Nov. 21 were about four times the national average. When winter hits New England, power and gas prices can spike quickly because most consumers use gas to heat their homes and businesses, and most of the region’s electricity usually comes from gas-fired power plants. Companies have tried to build more pipelines to bring gas from the Marcellus shale basin in Pennsylvania and other plays, but they have encountered objections from residents in Virginia, Massachusetts and New York, and denials of state permits in New York. Pipeline developers, however, are not giving up. Calgary-based operator Enbridge will continue to push federal, state and local regulators to allow new gas pipelines that could serve New England with production from nearby Appalachian basins, CEO Al Monaco said Feb. 15. “It’s never been more clear that we need additional gas infrastructure and nowhere is that more evident than in the U.S. Northeast,” Monaco said during a conference call with analysts to discuss fourth-quarter financial results. “This is actually an unbelievable irony when the Marcellus is sitting right next door to this market,” Monaco said. The LNG story in New England is just as ironic. The U.S. shale boom keeps breaking records, producing more gas than the country needs and triggering billions of dollars of investments in export terminals. LNG carriers are leaving the docks for Europe, South America, Asia, even Canada this month. But without a U.S.-flagged LNG carrier, there is no way to move affordable Gulf Coast LNG to the East Coast. Instead, New England has to import LNG from overseas to meet peak winter demand. The LNG import terminal in Boston harbor received about 24 cargoes in 2018, with all but one coming from Trinidad and Tobago. The other cargo was Russian LNG. Dominion Energy’s Cove Point, Md., terminal took in a Nigerian cargo in December 2018. And then this month, a load of U.S. gas left the dock at Cheniere Energy’s export terminal in Sabine Pass, La., headed to the Canaport LNG import terminal in New Brunswick. It was the first delivery of U.S. LNG to Canada, where the Atlantic seaboard provinces have become a customer for U.S. gas to replace domestic supplies since the Sable Offshore Energy Project ceased production in December 2018 after 19 years of serving the region. The Canadian Maritimes “will transform from being an exporter of domestic gas to being an importer of gas from the U.S.,” said Canada’s National Energy Board. Before the U.S. cargo, Canaport received six LNG deliveries in 2018 from Trinidad, Norway and elsewhere. And like New England, there is not enough pipeline capacity to move prolific supplies of U.S. shale gas or Western Canadian gas into the Maritimes. Which means high prices for consumers. Maritimes’ consumers already pay the highest average residential gas bills in Canada, according to the National Energy Board, with bills averaging $160 a month, roughly double British Columbia, Alberta and Saskatchewan. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Draft EIS for Alaska LNG Project pushed back four months

Citing the state’s timeline for answering federal regulators’ questions and fulfilling data requests, the Federal Energy Regulatory Commission has extended by four months its scheduled release date for the Alaska LNG project’s draft environmental impact statement, or EIS. In a notice issued Feb. 28, FERC said it now plans to issue the draft EIS in June. The commission did not specify a date in June. The scheduled release date had been February. The delay in the draft EIS also adds four months to FERC’s schedule for the state-led project’s final EIS. In its Feb. 28 notice, the regulatory commission said the final EIS would be issued March 6, 2020, instead of November 2019. But March 2020 depends on the Alaska Gasline Development Corp. answering all of FERC’s questions in full this summer. “The revised schedule for the EIS is based upon AGDC meeting its commitment to provide complete responses to outstanding data requests on the dates it has identified,” FERC said in its notice. “Staff has revised the schedule for issuance of the final EIS based on an issuance of the draft EIS in June 2019.” FERC explained that its previous schedule of a draft EIS in February and final impact statement in November “was based upon AGDC providing complete and timely responses to any data requests.” The commission has always advised AGDC — the same as for any other project — that an EIS schedule is dependent on full information from the applicant. In its filings in January and February, the state project team reported it would submit answers and additional technical data to more than 150 of FERC’s most recent questions in several batches, starting in early March and ending in July. In a statement provided to the Alaska Journal of Commerce, AGDC spokesman Tim Fitzpatrick said, “FERC’s comprehensive analysis of Alaska LNG now includes more than 150,000 pages of environmental and engineering data, including responses to more than 1,700 FERC queries submitted since AGDC initiated this permitting process twenty-two months ago. Previous FERC scheduling changes accelerated the permitting calendar, and we believe that today’s revision does not affect the prospects for Alaska LNG. We look forward to working with FERC to complete this process and obtain the permits required to bring Alaska’s North Slope natural gas to market.” The state has been talking the past two years with potential lenders, partners and customers in China and elsewhere in Asia, but has not reached any firm deals. The state has spent close to $500 million the past several years on the Alaska LNG project and a smaller, backup project, the Alaska Stand Alone Pipeline, as hopes continue that someday a pipeline will deliver North Slope gas to Alaskans and overseas markets. “Our current plan is to step back and evaluate technical and commercial aspects of the project,” AGDC’s interim President Joe Dubler told a state Senate budget subcommittee in Juneau on Feb. 27 as quoted in an S&P Global Platts report. “If it is viable we are going to solicit world-class partners for FEED, which is front-end engineering and design.” If FERC issues its final impact statement in March 2020, the deadline for commission action on the Alaska LNG project application would be June 4, 2020, 90 days after issuance of the final EIS. Federal regulators have been working to prepare the draft EIS since the state in April 2017 submitted its application for the estimated $43 billion project to move North Slope natural gas down an 807-mile pipeline to a liquefaction plant and export terminal in Nikiski, on the eastern shore of Cook Inlet. AGDC has been working to answer hundreds of questions and data requests from FERC and other federal regulatory agencies participating in the single federal EIS for the project. The proposed Alaska LNG development, which the state took over from North Slope oil and gas producers in late 2016, also includes a gas treatment plant at Prudhoe Bay to remove carbon dioxide and other impurities from the gas stream and a 62-mile pipeline to deliver gas from the Point Thomson field to the treatment plant at Prudhoe. AGDC still owes FERC information on fire safety, spill-containment safeguards and hazard-mitigation designs at the gas treatment plant, liquefaction plant and LNG storage tanks in Nikiski. In addition, federal regulators are waiting for information from the state on pipeline crossings at active earthquake faults, and a more detailed route map showing all seismic hazards within 5 miles of the pipelines. The state team also owes FERC more information about the project’s 27-mile underwater pipeline crossing of Cook Inlet, including addressing whether tidal flow and other currents would move debris and boulders across the pipeline and, if so, how much movement is expected. The regulator also wants to know if AGDC plans to use any additional weights or supports along the underwater pipeline after construction to stabilize the line against tidal currents, and whether the seafloor is firm enough to prevent the weighted 42-inch-diameter pipe from sinking into the seabed and straining the pipe welds during construction and operations. The state gas development corporation reports it has enough funding left over from prior legislative appropriations to last through the EIS process, assuming lawmakers this session approve AGDC’s $10 million operating budget plan for the fiscal year that starts July 1. Moving past the EIS, however, would require at least several hundred million dollars for final engineering and design, which the corporation does not have. It also would require investors, binding gas-supply contracts with the North Slope producers, bankable contracts for customers to take capacity on the pipeline and through the liquefaction plant, and buyers for the LNG. ^ Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.

Canadian producers unite in LNG export effort

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

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

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

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

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

Alaska LNG still on schedule for February EIS draft

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

Mat-Su Borough keeps up fight over LNG site

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

AGDC updates schedule for engineering data requests

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

Texas, ND grapple with gas flaring

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

Mozambique aims to take spot among global LNG leaders

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

FERC denies state request for cooperating status in EIS

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

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

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

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.

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