Larry Persily

Gazprom pipeline to China looks far from profitable

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

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

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

Traders shrug off US-Iran tensions as oil prices drop

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

State submits last answers to FERC on Alaska LNG

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

Goldman Sachs follows global peers on fossil fuels

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

Texas gas flaring draws lawsuit from pipeline company

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

LNG prices plunge amid decreased demand

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

Coal’s cost advantage hinders LNG conversions

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

China preps for first gas from Russian pipeline

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

Coal as power source hits 40-year low

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

Massive Mozambiqe LNG project gets green light

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

Mat-Su Borough wants another review of Port MacKenzie site

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

Valdez, Trustees for Alaska seek comment extension for AK LNG

The City of Valdez, which wants to see the Alaska LNG Project terminal built in its community rather than Nikiski, and an environmental legal organization have filed separate requests with federal regulators asking additional time to comment on the draft environmental impact statement for the project. Unless the Federal Energy Regulatory Commission changes the deadline, public comments on the draft EIS are due Oct. 3. The 3,800-page environmental review was issued June 28, and FERC held public meetings Sept. 9-12 in eight communities across Alaska to accept comments on the draft. Valdez and Trustees for Alaska, an Anchorage-based environmental law group reviewing the EIS for several clients, asked in separate filings that FERC extend the comment deadline 30 days past the closing date or 30 days after the state project team submits the last of detailed information requested by FERC, whichever is later. “Given the complexity of the issues involved in this massive project, the impacts that could occur to many public resources, and the key information that is still not available to the public, I am requesting that FERC extend the comment period for an additional 30 days after the applicant has provided the needed information,” Valerie Brown, legal director at Trustees for Alaska, wrote in an Aug. 29 filing with the commission. “The City (of Valdez) joins the Trustees for Alaska in their request for an extension of time,” the law firm of Brena, Bell &Walker, which represents the city, wrote in a Sept. 16 filing with FERC. “In order for the city and the public to provide meaningful comments on the DEIS (draft EIS), additional time is required for sufficient review of both recently filed information and additional information expected to be made available in the near future,” the Valdez letter stated. Trustees for Alaska, which did not identify its clients in its Aug. 29 letter to FERC, listed more than a dozen updates, reports, data sets, calculations and other items that the state project team had not submitted to FERC as of Aug. 28. The Alaska Gasline Development Corp. (AGDC), the 9-year-old state agency given the job of finishing the EIS even though there are no customers or investors for the $43 billion project, submitted hundreds of pages of additional information to FERC on Sept. 18. The filing covered many of the topics raised in the Trustees for Alaska letter, including an updated construction blasting plan, calculations of air emissions during construction, and temporary and permanent impacts to polar bear habitat. In requesting more time for public comments, the Trustees also noted that FERC on July 11 asked the National Marine Fisheries Service and U.S. Fish and Wildlife Service to consult on possible damage to essential habitat for several endangered or threatened species, including Cook Inlet Beluga whales and polar bears. “Ideally,” the Trustees wrote, the agencies’ opinions and assessments “would be available before public comments on the potential impacts of the project are due to FERC.” Under the commission’s current schedule, it would issue the final EIS in March 2020 for the state-led project to move Alaska North Slope natural gas through an 807-mile pipeline to Nikiski, on the east side of Cook Inlet, where the gas would be liquefied and loaded aboard ships for delivery to buyers in Asia. Valdez has promoted its community as a better location for the gas liquefaction plant and marine terminal, and the city’s Sept. 16 filing with FERC is one of several statements it has made on the project over the past couple of years. “It is apparent that the draft EIS fails to rigorously explore and objectively evaluate” the pipeline route and LNG terminal Valdez, the city said in a statement issued July 8. The draft “ignores the substantial advantages associated with the Valdez alternative,” the city said. The draft EIS review found insufficient reason to endorse either Valdez or the Matanuska-Susitna Borough’s Port MacKenzie over Nikiski, citing a range of factors that supported the project’s preferred site. “FERC did what they’re supposed to do, and I thought they did a fine job,” Matanuska-Susitna Borough Manager John Moosey told the Alaska Journal of Commerce in July. He said the borough accepted the outcome. The two requests to extend the public comment period were the only such filings in the FERC docket as of Sept. 23. General comments in support or opposition to the natural gas project were minimal. Several residents of Eugene, Ore., filed statements in opposition to the Alaska LNG project, arguing that methane emissions would add to greenhouse gas-induced climate change. “Please oppose this dangerous project,” one of the letters said. One letter came from Nikiski, supporting a variation of the route for the final miles of the pipeline passing through their community to the LNG plant. A few letters had come in as of Sept. 23 from Anchorage and Fairbanks residents in support of the project, economic development, and improved air quality in Fairbanks from burning gas instead of dirtier fuels. “The Alaska LNG Project will also be a new source of revenue to the state of Alaska, thus helping to provide long-term support for services to Alaskans, including our most disadvantaged,” said a letter from an Anchorage resident. John Shively, state Natural Resources commissioner from 1995-2000, also cited the economic benefits to the state and the advantages of gas as a cleaner energy for Alaskans in his letter supporting the project. The draft EIS, Shively said in his Sept. 18 letter, “concludes most project impacts would not be significant and would be reduced to minor impacts with the implementation of proposed avoidance, minimization and mitigation measures.” He also commented that “establishment of local subsistence implementation councils to identify community issues and concerns will help to ensure impacts to subsistence activities are minimal.” The draft EIS determined the North Slope-to-Cook Inlet project would damage some permafrost, wetlands and forest, but many of the effects could be reduced or eliminated if the right steps are taken during construction and operation to avoid, minimize or repair the damage. “With the implementation of various best management practices and our recommendations, most impacts on wildlife would be less than significant, but adverse impacts on some species, including caribou (Central Arctic herds) and federally listed threatened and endangered species, would occur,” the report said. Not unexpected for a project of this size, the draft listed pluses and minuses in the same sentence: “The project would result in positive impacts on the state and local economies, but adverse impacts on housing, population, and public services could occur in some areas.” In addition to the dwindling list of reports, engineering plans and other items the state project team still owed to federal regulators as of mid-September, FERC on Sept. 17 sent the state corporation a 35-page request for more information on the project’s hazard mitigation design, such as ventilation, spill containment, hazard detection, emergency response and shutdown at the gas treatment plant at Prudhoe Bay and gas liquefaction plant at Nikiski. The requests were based on reviews by FERC staff and a third-party contractor hired to specifically look at such issues. The request for additional details was expected and is common for all federally approved LNG projects. The state gasline corporation’s responses to the engineering and design questions are not due until after the close of public comment on the draft EIS but can be submitted early.

New Permian pipelines will add to oversupplied gas market

U.S. natural gas supply is outstripping demand, holding down prices and prompting speculation over just how low and how long the slide will continue; one research firm predicts prices next year will be the lowest in 22 years. “It is simply too much too fast,” said Sam Andrus, IHS Markit executive director, who covers North American gas markets for the global energy analytics and research company. “Drillers are now able to increase supply faster than domestic or global markets can consume it.” Taken by itself, the U.S. production gain the past two years alone would equal the fourth-largest gas producer in the world. Though U.S. liquefied natural gas and pipeline gas exports have climbed to record highs and power plants nationwide are burning more of the fuel than ever before, even that strong growth in domestic and international demand cannot keep pace with record U.S. gas production. There was a point in August when the U.S. Henry Hub benchmark price was flirting with $2 per million Btu before moving back into the $2.50 range on Sept. 20. But that seasonal price relief for producers in advance of winter looks to be temporary, according to a Sept. 12 report from IHS Markit. Rising production and growing gas stockpiles will work together to knock down prices to an average $1.92 per million Btu in 2020, IHS Markit said. U.S. gas hasn’t averaged below $2 since 1998, according to federal data. Prices averaged almost $3.20 in 2018, dropping to an average of about $2.60 so far this year. New pipelines delivering even more Permian shale gas to market will exacerbate an already oversupplied market, the IHS report said. Permian gas output is expected to average almost 15 billion cubic feet per day in September, double of just two years ago and triple from 2010 levels, according to the U.S. Energy Information Administration, or EIA. Eventually, low prices will push companies to cut back on drilling, bringing supply and demand back into balance, IHS Markit said, forecasting a slight rebound to $2.25 for 2021. “Rising prices stimulate supply and falling prices curtail it. What is unique here is the extent of reduction required,” said Shankari Srinivasan, IHS Markit vice president of energy. The EIA predicts that U.S. dry gas production will average more than 93 bcf per day from September through the end of this year. That’s after August set a new record at more than 91 billion cubic feet, or bcf, per day. The numbers are about double what the nation produced in the mid-1980s. Part of the problem, IHS Markit explained, is that additional oil pipeline capacity out of the Permian is allowing producers there to continue expanding their oil output, adding even more associated gas to an already oversupplied market. New gas pipelines out of the Permian could add an additional 6 bcf per day to the nation’s gas supply. U.S. gas production has grown by 14 bcf per day, about 15 percent, since January 2018, outpacing the strong growth in domestic and export demand. The U.S. is now the world’s third-largest exporter of liquefied natural gas, with four LNG terminals in operation, three more under construction, and six more with regulatory permits in hand and waiting to sign up customers and line up financing before taking final investment decisions. However, through LNG exports and domestic industrial demand, U.S. gas pricing is exposed to the world economy, and a recession would make it worse, S&P Global Platts said. If the global economy goes into a recession next year, demand from U.S. power and industrial sectors would likely decline a combined 2 bcf a day — 2 percent of total U.S. demand — further knocking down prices, Platts said. “A global economic recession remains a distinct possibility next year.” S&P Global Platts Analytics sees low prices hanging around for the next five years. “This is in response to softening global market conditions, increased associated gas production and muted domestic demand-side gains,” the company’s Sept. 9 report read. Without a recession and with some market rebalancing, prices could average $2.66 over the next five years, S&P Global Platts said. It’s not just the U.S. — gas prices are down worldwide. Among the biggest drivers of low prices in Asia and Europe has been the increasing volume of U.S. gas flowing into global markets as LNG, The Wall Street Journal reported Aug. 27. Analysts expect demand from U.S. LNG export facilities to take about 12 percent of the nation’s total gas production by next summer as new facilities start up and existing plants boost their capacity. “It was inevitable,” Ira Joseph, head of gas and power analytics at S&P Global Platts, was quoted in the Journal. “There is simply too much supply coming into the market,” and exports are a way to sell the gas. The pain of low prices is hurting more than just U.S. producers. It has pushed the city of Medicine Hat, Alberta, to abandon 2,000 of its 2,600 municipally owned wells over the next three years. The town of 62,000, known as Gas City, has been losing about $2 per million Btu on the gas it produces, according to a report in the Calgary Herald. Medicine Hat has owned the wells for about a century, and this month was producing about 6,500 barrels of oil equivalent per day from shallow natural gas and oil fields in southern Alberta and Saskatchewan. The average cost of its gas production is about $2.78 per million Btu, and the spot price for gas at Alberta’s AECO hub closed Sept. 12 at 80 cents. “You don’t need a sophisticated computer model to understand this gap means the city-owned utility has been hemorrhaging money,” said a Calgary Herald columnist. Facing dismal economics — and an expected cash loss of $35 million this year from its gas and petroleum resources division, the columnist reported — the city will shut down most of its producing gas wells. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Arctic LNG-2 extends Russia’s reach in Asia

Russian-led ventures earlier this month announced plans for two more liquefied natural gas terminals that would double the country’s production capacity by the mid-2020s. One is in the Arctic and the other in Russia’s Far East, and both are counting on Asian buyers to take much of the LNG. Arctic LNG-2 will aim to send 80 percent of its output to Asia, Leonid Mikhelson, CEO of project leader Novatek and Russia’s richest businessman according to Forbes magazine, said after the development partners signed a final investment decision Sept. 5. And it’s not just China, which is on its way toward becoming the world’s biggest LNG consumer and is a 20 percent partner in Arctic LNG-2. Japan is a partner in the venture, too, one of the largest in the history of Japanese-Russian relations, said Japan’s Industry Minister Hiroshige Seko. “It will unite Japan and Russia even more, as well as Europe and Asia. The Japanese government will provide all necessary assistance for the realization of this project,” the minister said as company officials announced the final investment decision at the Eastern Economic Forum in Russia’s Pacific port of Vladivostok on Sept. 5. On the same day at the forum, Novatek, which holds a 60 percent stake in the $21 billion Arctic LNG-2 project, announced a joint venture with marine shipping company Sovcomflot to purchase, finance and operate a fleet of 17 new ice-class LNG carriers for year-round transit through the Northern Sea Route to buyers in Europe and Asia. The vessels will be built at the new Zvezda shipyard, developed with Russian oil and gas producer Rosneft and with assistance from South Korea’s world-leading LNG carrier shipbuilders. The $4 billion shipyard is near Vladivostok, in the Russian Far East. Novatek, which developed Russia’s first LNG project in Siberia, Yamal LNG, will benefit from extremely low-cost gas at Arctic LNG-2, helping it compete against gas from the U.S. and Canada, Wood Mackenzie analyst Nicholas Browne told Reuters. Arctic LNG-2, at 19.8 million tonnes annual capacity, is scheduled to start production in 2023, reaching full capacity by 2026. Yamal is at 16.5 million tonnes annual capacity. Global LNG production capacity this spring totaled almost 400 million tonnes per year. “Novatek is clearly driving home their ambitions to be a global LNG powerhouse,” Chong Zhi Xin, associate director of gas, power and energy at analysts IHS Markit, said to Reuters on Sept. 5. Novatek’s partners in Arctic LNG-2 are France’s Total, China’s National Petroleum Corp. and China National Offshore Oil Corp., and the Japan Arctic LNG consortium comprised of Mitsui and state-owned JOGMEC, formally known as Japan Oil, Gas and Metals National Corp. “This is an important project for Russia and follows our strategy to create capacities for LNG production,” Russian Energy Minister Alexander Novak said at the forum in Vladivostok. It’s the largest LNG development to reach an investment decision this year, said global energy consultancy Wood Mackenzie, bringing to 63 million tonnes total project commitments in the first eight months of this year as suppliers look to meet growing demand. Meanwhile, Gazprom, which operated Russia’s only LNG export terminal until Yamal started up two years ago, is looking to expand its operation in the Far East and also build a new liquefaction plant and marine terminal on the Baltic Sea. If all of the projects move ahead, Russia would push its way on the top-four leaderboard of global LNG production capacity with Qatar, Australia and the United States, a fast climb from its No. 10 spot just a decade ago. The Baltic project, which would include an LNG plant and petrochemical operation, has been estimated at almost $14 billion, with 10 million tonnes annual LNG production capacity. Prime Minister Dmitry Medvedev said last month it would be impossible to build without government support, and soon after Russia’s state development bank VEB said it would invest up to 111 billion roubles ($1.68 billion) in the project. Reuters reported this summer that Russia’s National Wealth Fund also will help finance the Baltic investment. The government is helping with Arctic LNG-2, too. Novatek will get a reported $600 million in additional tax deductions for building the port, along with the Russian government covering more than half the construction budget at the port and channel, according to reports in Norway’s Barents Observer newspaper. Novatek also will receive about $160 million in property and income tax breaks from the regional government for its investment in a $1.6 billion construction yard near Murmansk, about 1,000 miles west from the project site, where it will build 1,000-foot-long concrete and steel platforms that will be towed and installed at Arctic LNG-2, the newspaper reported. In the Russian Far East, shareholders in the Sakhalin-1 oil and gas project have decided to build their own liquefied natural gas plant and export terminal at the mainland port of De Kastri, about 150 miles from the offshore oil and gas fields. Sakhalin-1 has been producing oil for almost a decade, with production of about 200,000 barrels a day in 2017, while the partners have considered options for selling the gas. The four partners in Sakhalin-1 are Rosneft, ExxonMobil, Japan’s SODECO and India’s ONGC Videsh. The partners had been talking with Gazprom about selling or sending their gas through the Sakhalin-2 liquefaction plant, but Rosneft CEO Igor Sechin announced on Sept. 5 that the Sakhalin-1 partners would build their own LNG plant, according to press reports Gazprom, Russia’s top gas producer, leads Sakhalin-2, where the partners plan to expand production capacity from the current 9.6 million tonnes of LNG per year. Gazprom has not issued any statements about the Rosneft-led effort to build a competing LNG terminal that also would draw on gas fields offshore Sakhalin Island. Sakhalin-2 went online in 2009. The company and its partners Shell and Japan’s Mitsui and Mitsubishi have been working toward an expansion for several years but are not yet at the final investment decision stage. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Excess supply, economic fears drive down oil prices

Fears of an oversupplied oil market amid rising global trade tensions are holding down prices. In addition, markets are reacting to weak economic indicators and unsettling political news, along with rising non-OPEC production, resulting in frequent daily price swings of $2 or more per barrel. Worries of too much oil chasing after uncertain demand is making investors, traders and corporate executives nervous, even prompting one bank to suggest prices could drop more than $20 a barrel if everything goes wrong. “Oil is at the edge of a cliff,” analysts at Bank of America Merrill Lynch wrote in a research note. Brent, the global price, started the week of Aug. 26 at around $59 per barrel, off more than 20 percent from its April peak of $74. U.S. crude tumbled roughly 8 percent on Aug 1, the steepest one-day drop since 2015, after President Donald Trump announced a new round of tariffs on China. “President Trump’s unexpected tariff announcement … suddenly revived the specter of an economic slowdown, akin to bubonic plague for oil demand,” Robert McNally, president of Rapidan Energy Group, told The Wall Street Journal in early August. “The U.S.-China trade spat has been at the center of the oil market demise, which has sent the global economy to the brink of recession and negatively impacted oil demand forecasts,” Stephen Innes, managing partner at VM Markets, Singapore-based trade specialists, was quoted by Reuters on Aug. 20. “Recession risk is now the single biggest factor driving oil prices because it will determine whether recent price falls will be enough to rebalance the market, or whether a deeper and longer slump is needed,” a Reuters’ columnist said Aug. 20. Putting numbers to the risk, a Bank of America Merrill Lynch global research report warned Aug. 2 that prices could sink more than $20 per barrel if China decides to buy Iranian crude in retaliation for U.S. trade tariffs. “A Chinese decision to reinitiate Iran crude purchases could send oil prices into a tailspin,” the report said, noting that the increased volume would add to an already well-supplied market. Global oil consumption is falling at the fastest rate since late 2014 as manufacturing and trade flows slip and as production of new cars and trucks declines, the Reuters’ columnist reported. Demand in the top 18 consuming countries fell by almost 0.2 percent in the three months between March and May compared with the same period a year earlier. Back in 2014-16, the combination of falling consumption with booming U.S. shale output and Saudi Arabia’s refusal to cut back on its production led to a price slump that dropped Brent from the $100-plus level in 2014 to a low of $27.88 in January 2016. This time around, Saudi production cutbacks have limited the price drop. OPEC is trying to prop up prices. Total output by its members hit an eight-year low in July with a further voluntary cut by top exporter Saudi Arabia. The 14-member Organization of the Petroleum Exporting Countries pumped 29.42 million barrels per day in July, according to a Reuters survey, the lowest OPEC total since 2011. But despite the cutbacks by OPEC and its allies, “bulging global oil stocks have failed to decline and the market remains well supplied,” said Stephen Brennock, with PVM Oil Futures, which bills itself as the world’s leading broker of oil trade and investment instruments. OPEC, Russia and other non-members agreed in July to continue their voluntary cutback in production, extending the deal adopted in December. The producing nations agreed to trim their output by more than 1 million barrels a day, about 1 percent of worldwide production. Even with that, OPEC has indicated the market will be in slight surplus in 2020. “The risk to global economic growth remains skewed to the downside,” said an OPEC report of early August. OPEC may be able to govern its own production to guard against global oversupply and low prices, but U.S. producers continue driving much of the surge in output, along with new projects in Brazil and Norway. Citigroup and JPMorgan Chase analysts project global supply will grow roughly 1 million barrels per day more than demand in 2020. The analysts said those new barrels could exacerbate the expected global surplus, particularly as concern about a slowing world economy triggers fears about crumbling demand. U.S. production totaled 12.3 million barrels per day in June, setting a new record. The nation’s output was just 5 million barrels per day in 2008. The U.S. Energy Information Administration forecasts 13.3 million barrels per day in 2020. Much of the booming production is coming from Texas, in particular the Permian Basin. Oil production in Texas has shot up from about 1 million barrels per day a decade ago to 5 million this summer. All that oil needs buyers, and much of it is leaving the country — but not as much as earlier in the summer. U.S. exports averaged 2.4 million barrels per day during the three-week period ended Aug. 9, down from an average 3 million barrels between the start of May and mid-July, Energy Information Administration figures show. It was easier to sell U.S. crude overseas when it was priced about $8 to $10 per barrel less than Brent, as it was over the winter and much of the spring. But U.S. oil is now trading at the smallest discount to global prices in more than a year. New pipelines are transporting oil from the Permian to the Gulf of Mexico, easing the bottleneck that constrained markets and held down prices. With improved access to overseas buyers, West Texas Intermediate crude was trading at just $3.50 less than Brent the third week of August. Higher prices reduce the attractiveness of U.S. crude exports. “Nobody really wants the barrels when they’re $3 cheaper than Brent,” Bob Yawger, director of the futures division at Mizuho Securities USA, was quoted by The Wall Street Journal on Aug. 20. “It could get ugly long term.” Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Spot-market LNG prices have buyers seeking more options

It’s just shy of six years ago when spot-market prices for liquefied natural gas in Asia hit a record $20 per million British thermal units and a cargo aboard a standard-size LNG carrier cost almost $65 million. That same volume of LNG would cost less than $13 million today, or around $4 per million Btu. Spot-market buyers paid more than long-term customers during the post-Fukushima, tight-supply price spikes of 2012-14, but the roles are reversed during today’s weak market conditions. It’s a matter of supply and demand driving spot prices, while long-term LNG contracts are linked to oil prices that are detached from LNG market conditions. In July, Japanese utilities paid an average $4.70 per million Btu for spot LNG cargoes amid an oversupplied market, according to trade ministry data, about half the price those same utilities paid for gas under long-term contracts linked to oil prices. Tokyo Gas and electric utilities in Hokkaido, Tohoku, Kyushu and Hokuriku regions have all said they are looking at ways to take advantage of cheaper spot LNG, Reuters reported Aug. 9. But they are limited in the number of cargoes they can take because most of their supply comes under long-term take-or-pay contracts. Oil-linked LNG contracts around the world vary, ranging from about 11 to 15 percent of the price of a barrel of crude averaged over the past six months to five years. When oil was $120 several years ago, contract buyers paid dearly for their LNG. But nothing linked to oil can compete with $4 spot-market gas. The low prices are pushing utilities in Japan to get more aggressive in the price reviews allowed under their long-term contracts, according to multiple news reports. The five- or 10-year reviews are built into many of the contracts. “Price-review negotiations are becoming more intense,” Thanasis Kofinakos, head of Wood Mackenzie’s Asia-Pacific gas and LNG consulting, told Reuters in early August. According to Reuters, Japan’s second-biggest city-gas company, Osaka Gas, is in arbitration with ExxonMobil’s LNG project in Papua New Guinea after failing to win a reduction in prices during a price review. However, there is a risk in negotiating for a new pricing structure in long-term contracts — what happens the next time the market flips and oil-linked LNG is cheaper than spot sales? Utilities would need to accept the risk that spot prices could surge in tight markets, Hirofumi Sato, Tokyo Gas general manager of financial management, said during an earnings news conference. Besides, it’s not easy for the utilities to gamble on market pricing swings, as they have long favored stability of supply over price. Still, Tokyo Gas is looking for ways to take advantage of cheaper spot prices, including buying up more gas and storing it for the peak winter season, Sato said. Another tactic is to scale back purchases within the limit of what’s allowed under their contracts. Some buyers in Japan and China are seeking to delay shipments or reduce volumes under their contracts from the Ichthys LNG project in Australia, an Inpex executive told Reuters Aug. 8. Inpex is the Japanese oil and gas producer that operates Ichthys. If the money-saving spot prices persist, India’s top gas importer Petronet LNG will look to renegotiate more of its oil-linked supply deals, its managing director said Aug. 8. “You don’t have much of a choice,” Prabhat Singh told Reuters. Petronet is paying $8.25 to $9.50 per million Btu under its long-term contracts with Qatar’s RasGas and for cargoes from ExxonMobil’s share of the Gorgon project in Australia, Singh said. The company renegotiated new price deals in other contracts in 2015 and 2017. No doubt Petronet is aware that Indian Oil Corp. bought a spot cargo for delivery in the second half of August from commodity trader Trafigura at $3.69 per million Btu. China National Offshore Oil Corp. bought a cargo for delivery in early September from trader Vitol at $3.90. As new LNG supply comes into the global market amid weaker demand growth, the volume of spot cargoes is growing, adding to the soft prices. Spot- and short-term trades comprised one-third of the market in 2018, the International Group of LNG Importers said in its 2019 annual report. It was 1.5 percent in 1997 and 8.9 percent in 2003. There is so much low-cost LNG available that traders are starting to look at booking vessels to store LNG at sea as they bet on winter demand to boost prices, according to multiple news reports. If October and November spot prices are 90 cents higher than August prices, “floating storage is starting to make sense … and at $1.50 people will be jumping on it,” a Singapore-based LNG trader told Reuters. Another factor is the steady return of Japan’s nuclear-power fleet over the next three years. Nine nuclear plants are back online, with 14 more expected in the next few years, leading a shift in demand away from imported LNG. S&P Global Platts estimates the issue of over-contracting for LNG will emerge this year among Japanese utilities. The situation could peak in 2020, with the over-contracted volumes reaching 19.5 million tonnes. Europe is buying more LNG, but has its limits. There is increasing concern Europe’s gas storage could hit “tank tops” by the end of summer, putting more downside pressure on prices, Reuters reports. Storage sites at some key hubs in the Netherlands and Austria are already more than 95 percent full, Refinitiv data shows. U.K. and Dutch gas prices, benchmarks for European gas sales, have lost half their value since last September. They hit 10-year lows in June, knocked down by an influx of LNG imports and pipeline gas from Russia. Continued oversupply, coupled with new liquefaction capacity coming online in the U.S., Australia, Russia and Mozambique, could cause developers to rethink their schedules. “We may see some delays in final investment decisions in new LNG projects given the current market environment,” Inpex Senior Managing Executive Officer Masahiro Murayama said in an earnings call. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

FERC sets eight public meetings in September on AK LNG draft EIS

The Federal Energy Regulatory Commission has scheduled eight meetings around the state in September to hear public comments on the draft environmental impact statement for the proposed Alaska LNG project. “The primary goal of the public comment meetings is to have you identify specific environmental issues and concerns with the draft environmental impact statement,” FERC said in its July 26 announcement. “All verbal comments will be recorded by a court reporter and become part of the public record.” FERC released the draft environmental review on June 28. Public comments are due by Oct. 3. Allowing time for state and federal agency review, along with revisions to the draft, the commission’s schedule calls for release of the final EIS in March 2020 and a commission vote on the project application in June 2020. The state, which has been by itself directing the estimated $43 billion project for almost three years, plans to finish the work with FERC and then put the effort on hold until it sees a way forward with private companies in the lead. The public comment meetings will run Sept. 9-12, with sessions in two different communities each day. All meetings are scheduled for 5 to 8 p.m. Monday, Sept. 9 Inupiat Heritage Center, Utqiagvik Trapper Creek Elementary School, Trapper Creek Tuesday, Sept. 10 Kisik Community Center, Nuiqsut Houston Fire Station, Houston Wednesday, Sept. 11 Tri-Valley Community Center, Healy Nikiski Recreation Center, Nikiski Thursday, Sept. 12 Morris Thompson Cultural and Visitors Center, Fairbanks Dena’ina Center, Anchorage FERC will lead the meetings, not the project applicant Alaska Gasline Development Corp. “Other federal agency representatives may also be in attendance and available to answer questions,” FERC said. In addition to the eight FERC meetings, the federal Bureau of Land Management will hold two public sessions on subsistence issues. Those meetings are scheduled for “potentially affected communities.” BLM will be looking at the effects of construction and operation and how they fit under the Alaska National Interest Lands Conservation Act. Those meetings are scheduled for 6 to 9 p.m. at: Anaktuvuk Pass Community Center, Tuesday, Sept. 17. Kaktovik Community Center, Thursday, Sept. 19. Comments on the draft EIS can be filed electronically through the eComment feature on the ferc.gov website. “This is an easy method for submitting brief, text-only comments,” FERC stated. Longer comments, or submissions with attachments, can be submitted through the eFiling feature on the website. Or people can mail comments to: Kimberly D. Bose, Secretary; Federal Energy Regulatory Commission; 888 First Ave. NE, Room 1A; Washington, DC 20426. All comments should include the project’s docket number: CP17-178-000. FERC staff is available to help with filing comments online: Call 1-866-208-3676 or email [email protected] The 3,800-page draft EIS determined that the project would damage areas of permafrost and wetlands and could affect migrating caribou and six endangered or threatened wildlife species — referred to as “adverse impacts” — but many of the effects could be reduced or eliminated if the right steps are taken during construction and operation to avoid, minimize or repair the damage. FERC is the lead on the environmental review of the state-sponsored project to pipe North Slope gas 807 miles to a natural gas liquefaction plant and marine terminal in Nikiski, on the Kenai Peninsula. The draft EIS was prepared with the assistance of nine other federal regulatory agencies, including the U.S. Fish and Wildlife Service, National Park Service, Environmental Protection Agency, National Marine Fisheries Service, Army Corps of Engineers and Bureau of Land Management. The state has been leading the project since North Slope oil and gas producers ExxonMobil, BP and ConocoPhillips decided in late 2016 to stop writing big checks for regulatory and engineering work. Now the state, through AGDC, has decided it, too, needs to slow down spending. The state corporation plans to finish the FERC process and try putting together a project without the state in the lead. AGDC earlier this month announced it would lay off more than half its staff, shutting down its effort to find customers and investors. “We’re going to have just enough people to get this thing done (FERC) and at the end of next (fiscal) year in June, then we take a look and say, ‘Where do we go from here?’” AGDC interim president Joe Dubler told the state House Resources Committee on July 19. At that point, AGDC will re-examine the state’s future participation in the project, Dubler said, according to a July 24 report in the Alaska Journal of Commerce. Dubler also told legislators that AGDC did not renew the nonbinding joint-development agreement it had with three large, nationalized Chinese firms to buy up to 75 percent of the project’s LNG output in exchange for an equal share of financing. The project envisioned in the agreement “frankly doesn’t exist anymore,” Dubler said, explaining the Gov. Mike Dunleavy administration is not comfortable with the risk the state would assume as project leader, the Journal of Commerce reported. The agreement was signed in front of President Donald Trump and China President Xi Jinping in November 2017, promoted as a signature achievement in former Gov. Bill Walker’s effort to secure partners for a state-led Alaska LNG project.

LNG trucking expands as option in absence of pipelines

Though the liquefied natural gas industry is mostly focused on projects that produce millions of tonnes per year and LNG ships that transport almost 70,000 tonnes per load, a growing volume of the gas is moving in 20-tonne deliveries. Trucks are hauling 40-foot-long insulated LNG tanks around the U.S., Canada, Mexico and especially China. The “pipeline on wheels,” as they are called, have been delivering LNG to Hawaii to displace costly synthetic gas made from naphtha. The pilot project started in 2014 and has been expanded. FortisBC, which recently completed a $400 million expansion of its small 1971 gas liquefaction plant across the Fraser River from Vancouver, said July 16 it had signed a two-year contract to ship 53,000 tonnes per year to China — delivering almost 60 of the specialized shipping units per week. Pricing was not disclosed. The 40-foot tanks can each carry about 12,000 gallons of LNG, which, when regasified, is about 1 million cubic feet of gas. The LNG will go to smaller commercial and industrial customers in China that are not connected to a gas pipeline, potentially displacing coal or fuel oil, Doug Stout, vice president of market development at FortisBC, told Bloomberg. The company has been selling smaller shipments of LNG to China on a spot basis since 2017. The expansion at the Tilbury liquefaction plant and marine terminal took the facility’s capacity from 35,000 to 250,000 tonnes per year. The July contract is with Chinese LNG distributor Top Speed Energy. Such shipments are a growing component in the global LNG sector, especially when the customers are small or unconnected to a pipeline grid, Alex Munton, an analyst for Wood Mackenzie, was quoted by Bloomberg on July 17. China’s ENN Group last year opened a new LNG import terminal in Zhoushan, at the mouth of the Yangtze River. It’s the first in the world built to load the majority of its LNG into trucks instead of reheating it to a gas for pipeline distribution, according to a late-2018 Bloomberg report. The facility is designed to take in up to 3 million tonnes of LNG per year, with 2 million destined for loading into tanker trucks. The operation includes 14 loading bays, and the privately owned distributor started with a fleet of 400 trucks to serve the market during the 2018-19 winter. The trucked LNG market is unregulated in China, allowing nimble sellers to benefit from rising prices during peak demand, while pipeline gas prices remain set by the government. “We haven’t seen this kind of volume in trucked LNG anywhere else in the world,” Xizhou Zhou, head of China energy research for IHS Markit, said last year. Trucks delivered about 19 million tonnes in China in 2017, about 12 percent of the country’s total LNG consumption, according to Wood Mackenzie estimates. In North America, two companies have carved out a niche by using tanker trucks to deliver the fuel to industrial and agricultural customers in Mexico. Houston’s Stabilis Energy is tapping into a growing market in Mexico, supplying LNG to industrial customers and greenhouses, the Houston Chronicle reported this spring. Its $55 million plant in the South Texas town of George West can produce 120,000 gallons of LNG a day. The plant also supplies fuel to portable LNG-powered generators at remote drilling and fracking sites in Texas, and at fracking sand mining sites out of reach of pipelines and power grids. Mexican gas company Enestas serves customers outside of local power grids and miles away from pipelines. Gold, silver and lithium mines in Mexico use the company’s gas-fired generators to power equipment and provide heat in deep mine shafts, the Chronicle reported. Industrial-sized greenhouses designed for growing peppers, cucumbers and other vegetables in the mountains of Central Mexico burn gas to keep crops warm at night. Enestas expects to sell 10 million gallons of U.S. LNG to its customers in Mexico in 2019 — equal to more than 800 million cubic feet of gas. Up the U.S. East Coast, New Fortress Energy has proposed building an LNG export terminal in New Jersey, filling the storage tanks with gas liquefied at a plant in Pennsylvania and trucked to the dockside facility. The U.S. Army Corps of Engineers, the lead permitting agency for the project, released company plans in mid-July that said the terminal, just across the Delaware River from the Philadelphia International Airport, would receive as many as 15 trucks an hour — around the clock — to fill an oceangoing tanker every two weeks. The gas, produced from Pennsylvania’s Marcellus Shale, would be liquefied at a plant about 200 miles away in Bradford County, also proposed by New Fortress Energy. Rail might be another option to move the LNG to the waterfront terminal. Communities along Canada’s north shore of Lake Superior could start burning gas by late 2020, as the Ontario government this spring decided to provide $27 million (Canadian) toward building an LNG plant in Nipigon for distributing gas to communities struggling with high energy costs. The provincial funds will cover about half the cost of the plant. Residents in Marathon, Terrace Bay, Schreiber, Manitouwadge and Wawa — total population, about 11,000 — suffer under price spikes on fuel oil, propane and electrical power. An earlier feasibility study estimated trucking LNG into the towns would save municipalities, homeowners and business more than $6 million annually. Northeast Midstream, an Ontario energy developer, will take gas from a nearby pipeline and liquefy it. Trucks will deliver the LNG to depots in each community, where it will be warmed back to a gas and distributed by short pipelines into individual homes, public and commercial buildings. Press reports said longer pipelines were not a good option in the area’s rugged topography. The promise of lower home heating costs are the main selling points for Terrace Bay Mayor Jody Davis. “In the wintertime, over the past several years, heating bills in some of our homes have been up to $1,000 per month” for diesel, fuel oil or propane. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

Pipeline obstacles constrain capacity amid energy boom

Oil and gas pipeline developers around the country are frustrated at the delays and legal challenges they have to plow through when they would prefer to be burrowing underground to install new pipe. Tulsa, Okla.-based Williams Cos. has been trying for more than four years to obtain permission to replace about six miles of an older 8-inch-diameter gas line it owns in Seattle’s northern suburbs with a 20-inch line to serve new development in the area. Alan Armstrong, Williams’ CEO, told The Wall Street Journal this month that permitting delays have driven the project cost to $50 million from an estimated $6 million. The company hopes to start work this summer. “That is such a simple piece of work,” Armstrong told the Journal. “It’s hard for me to even talk about it because it’s repulsive how much money has been spent there.” The North Seattle Lateral, as it’s called, just north of Bothell and Woodinville, was built in 1956 and delivers gas from Canadian and Rocky Mountain producers. “(It) is operating beyond its intended peak capacity on cold winter mornings and days,” the company says on its website. Challengers during the permitting process include the Sierra Club and Mothers Out Front. Environmental groups have pushed regulators for greater scrutiny of the project, which would cross 15 streams. Challengers also have raised concerns of a leak or explosion in the suburban and rural area of Snohomish County. In Michigan, Enbridge has taken the state to court over a $500 million pipeline project. The company wants to dig a tunnel for new liquids pipelines to replace a 66-year-old line on the lakebed under the Straits of Mackinac, which connects Lake Michigan and Lake Huron. The legal fight escalated between the Calgary-based company and the State of Michigan after Gov. Gretchen Whitmer won election last fall. She wants the line shut down. The company wants to the state to honor an agreement with the previous governor that would allow Enbridge to install new pipe in the protective tunnel. The company’s Line 5, as it’s called, can move 540,000 barrels per day of crude oil and natural gas liquids from Canada to Michigan and Ontario refineries and other customers. Enbridge is asking the Michigan Court of Claims “to establish the constitutional validity and enforceability of previous agreements.” The governor wants the pipe out of the water to protect the Great Lakes from the risk of spills. In Canada, the most recent legal fight is not a company versus government but two governments battling each other. British Columbia wants to restrict the flow of oil sands production from Alberta through the coastal province. The intent is to block expansion of the Trans Mountain pipeline to move 890,000 barrels per day of oil sands bitumen to an export terminal near Vancouver. The B.C. Court of Appeals ruled May 24 that the federal government has sole jurisdiction over interprovincial projects such as an oil line, shutting down British Columbia’s maneuver. The B.C. government appealed and Alberta responded by joining the case as an intervenor to protect its interests. “The B.C. Court of Appeals’ unanimous decision was clear. B.C. does not have constitutional authority to block cross-provincial projects,” Alberta Premier Jason Kenney said July 12. “The actions of the British Columbia government not only target Alberta’s economy by landlocking our energy resources,” but also undermine free trade within Canada, Kenney said. The project that started the debate over oil sands pipelines 10 years ago — the Keystone XL line — continues to have its multiple days in court. Opponents asked a federal judge on July 1 to cancel permits and other approvals issued by the U.S. Army Corps of Engineers for the line from Canada, opening another legal fight over the long-delayed project. Attorneys for the Northern Plains Resource Council, Sierra Club and other groups filed the lawsuit in Montana. They claim the Army Corps did not examine the potential for oil spills and other environmental damages when it approved plans from pipeline developer TC Energy (formerly known as TransCanada). The 1,184-mile pipeline from Canada would connect to existing pipe in Nebraska to deliver oil to U.S. Gulf Coast refineries and export terminals. First proposed in 2008, Keystone XL was rejected by President Barack Obama but revived under President Donald Trump. Besides the filing in Montana, legal challenges continue in Nebraska. Though oil lines may attract the most media attention, insufficient U.S. gas pipeline capacity creates a lot more price volatility for consumers. Earlier this year, two utilities that serve the New York City area stopped accepting new customers in two boroughs and several suburbs, citing a lack of gas pipeline capacity. They said they couldn’t guarantee delivery to additional furnaces, The Wall Street Journal reported July 7, never mind that the country’s most prolific gas field, the Marcellus Shale, is only a three-hour drive away. Environmental and political opposition is making it difficult to build new pipelines in New England and the Mid-Atlantic states. At the other end of pipelines, producers in the Permian Basin in West Texas and Bakken in North Dakota have so much gas with no way to get it to market that they are burning it — a combined 1.2 billion cubic feet per day at its worst earlier this year. There just aren’t pipelines to move all the gas. U.S. production rose to a record of more than 37 trillion cubic feet last year, up 44 percent from a decade earlier. Prices have been negative at times this year at a trading hub near Midland, Texas, where producers had to pay companies to take gas off their hands. At the other end of the distribution system, prices hit records when heavy demand coincided with supply disruptions. A cold snap along the East Coast led to gas prices as high as $140.85 per million Btu in New York and $128.39 in the Mid-Atlantic on Jan. 4. “I don’t recall a situation when we’ve had the highs and lows happen in such extremes,” the Journal on July 7 quoted Rusty Braziel, a former gas trader who now advises energy producers, industrial gas buyers and pipeline investors. Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide. He is the incoming Atwood Chair of Journalism at the University of Alaska Anchorage School of Journalism and Public Communication.

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