Global pipeline gas exports down 6% last year; LNG trade up 2.4%
(Bloomberg; June 10) - Global trade of natural gas via pipelines fell the most on record last year as Russia suspended exports to Ukraine and shipments declined from the Netherlands, the European Union’s biggest producer, according to BP. Exports of the fuel through pipelines slipped more than 6 percent last year, the biggest drop since the oil major started compiling the data in 1989, BP said in its annual Statistical Review. It’s only the second time global gas trade retreated.
Russian shipments declined by 12 percent, while those from the Netherlands tumbled 30 percent. Russia halted supplies to Ukraine for six months last year due to a price dispute between the two nations. Gas output in the Netherlands fell as the government decided to limit output from the Groningen field, Europe’s biggest, after earthquakes caused by gas extraction damaged buildings in its most northern province.
Gas consumption in the EU fell 12 percent last year, the biggest decline on record. Lower demand in the 28-member nation bloc dragged down global consumption, which grew by 0.4 percent compared with a 10-year average of 2.4 percent. The decline was mainly driven by mild weather in Europe rather than structural factors, BP reported. Increased supplies of liquefied natural gas helped compensate for the weaker pipeline trade. Global LNG trade increased 2.4 percent to a 33.4 percent slice of total gas trade.
Another delay in federal review of Petronas LNG project in B.C.
(Vancouver Sun; June 8) - A federal review of the proposed Pacific NorthWest LNG project near Prince Rupert, B.C., has been halted a third time as the company has been told to provide more information on its effects on a sensitive salmon-rearing habitat. The consortium, led by Malaysian state-controlled Petronas, was asked in February to provide three-dimensional modeling demonstrating the project’s effects on sediment and water currents in Flora Bank and its eel grass beds critical for salmon rearing.
Canadian Environmental Assessment Agency spokeswoman Karen Fish said June 8 that the company was told last week more 3-D modeling information is needed. She said the company must also provide information on the effects on aboriginal fisheries, the effects on marine mammals and the effects of dredged material disposal. The halt in the federal review could further delay any go-ahead by the company, which has said a positive federal review is necessary to make a final investment decision.
The company is also facing opposition from the Lax Kw’alaams First Nations, which rejected a $1.15 billion benefits package from the province and the Petronas-led consortium over concerns about the project’s impacts on salmon habitat. The company had initially said it would make a decision by the end of last year, and then said a decision may come by June. Petronas is now looking at perhaps a conditional investment decision, pending final environmental approval by regulators.
Propane glut in Alberta pushes company to export
(Financial Post; Canada; June 8) - While projects to export liquefied natural gas, including one involving Calgary-based AltaGas, have been attracting much of the attention in Western Canada, another depressed liquefied gas product is finding its way to Asia: propane. AltaGas said June 8 it started shipping liquefied propane gas in April from its terminal in Ferndale, Wash., just south of the U.S./Canada border, to markets in Asia following a major production glut in Alberta.
LPG is a by-product of natural gas extraction and is used by firms such as Dow Chemical to produce a range of products, including polyester for clothing. “Developing new markets for LPG is key for gas producers,” AltaGas chairman and chief executive David Cornhill said at a Calgary Chamber of Commerce presentation. Executives said the company is looking to build a 30,000-barrel-per-day LPG export facility in British Columbia, but wouldn’t identify a specific location.
Propane prices have plummeted across North America in the past year to the point at which gas producers in Alberta are now paying their customers to take the commodity away. Research from FirstEnergy Capital shows producers paid roughly 6 cents per gallon (U.S.) of propane to their customers at the end of May; producers earned roughly 75 cents per gallon a year earlier. AltaGas is now exporting 7,000 barrels of LPG per day from its Washington terminal and hopes reach 30,000 barrels a day, an official said.
Canadian East Coast LNG plants may be cheaper than West Coast
(Business in Vancouver; June 9) - The number of liquefied natural gas projects proposed for Canada’s East Coast (six) is well short of the West Coast list (21), and West Coast proposals have a head start, but Calgary-based energy investment and research firm Peters & Co. believes at least one East Coast project is likely to proceed at some point. Canada’s East Coast projects benefit from less remote locations than their West Coast counterparts, allowing for lower capital costs, according to Peters.
West Coast projects in northwestern B.C. are assumed to have a capital cost of about $1,250 per metric ton of annual liquefaction capacity in the first phase. In comparison, East Coast projects in New Brunswick and Nova Scotia incorporate capital costs of $950 to $1,000 per ton. Many of the Canadian East Coast export license filings have targeted the Marcellus Shale play in the northeast U.S. as a possible source of supply — though a source that would require new pipeline capacity to reach the coast.
Bear Head LNG, proposed for Nova Scotia, has said it could start production as soon as 2019, assuming a final investment decision next year and pinning down gas supply and LNG sales contracts, export approvals and financing. Pieridae Energy is also looking at building an LNG plant in Nova Scotia, also targeting 2016 for an investment decision on the project to serve European markets. Pieridae has a 20-year sales agreement with a Germany-based power and gas company. Meanwhile, Canaport LNG is looking to turn an abandoned LNG import terminal project in New Brunswick into an export terminal.
Small LNG plant could provide big tax boost for B.C. community
(Business in Vancouver; June 9) - Compared with other liquefied natural gas plants proposed for the B.C. coast, the Woodfibre LNG project in Squamish is small. But at a capital cost of $1.7 billion, even a small LNG plant like Woodfibre is a big investment and generator of jobs and taxes. The project would generate roughly $2 million in taxes a year for the District of Squamish and create about 650 jobs per year over two years during construction and approximately 100 permanent full-time jobs.
And unlike the Pacific NorthWest LNG project proposed for near Prince Rupert — a greenfield site in a sensitive estuary — the Woodfibre LNG project would be built on the brownfield site of a former pulp mill shut down in 2006. Its construction would include a multimillion-dollar environmental cleanup that includes closing old landfills and removing 3,000 creosote pilings from an old dock in Howe Sound. So why is Squamish essentially saying “no thanks” to the project?
When the pulp mill shut down in 2006, it blew a $1.8 million hole in Squamish’s tax revenues. It has since been covered by shifting the burden to residents and businesses. While it’s estimated the LNG project would more than replace the taxes lost from the closed pulp mill, the sound’s legacy of pollution from Britannia mine, pulp mills and chemical plants makes heavy industry a hard sell. Squamish Councillor Doug Race, who supports Woodfibre LNG, said he believes it has become a fossil-fuel lightning rod.
Barge-mounted LNG plant plans to be first in B.C. race
(The Canadian Press; June 8) - The CEO of AltaGas said his Calgary-based company is on track to building Canada's first liquefied natural gas export terminal by 2018, challenging an international report that said no such facility will be built in the country by 2020. "We think we'll prove them wrong in this decade," David Cornhill said June 8 in an interview following the pessimistic report last week by the International Energy Agency.
Cornhill said the company is making progress on plans for the Douglas Channel LNG terminal in front of Kitimat, B.C. An AltaGas-led consortium took over the project earlier this year. "We have nothing that we see at this point that will stop us," he said. "It is a lot of work, there are some tight timelines, so it's not a walk in the park, but clearly we think it's achievable." AltaGas has not yet made a final investment decision on the project but expects to by the end of the year.
The Douglas Channel project is much smaller than most of the LNG proposals for B.C., with its first phase designed to ship about 550,000 metric tons per year (about 260 billion cubic feet of gas). In contrast, the Petronas-led project near Prince Rupert could ship as much as 22.2 million tons per year. The Douglas Channel terminal would be based on a floating barge rather than on land and would make use of an existing gas pipeline. "I think small LNG facilities are far better from an environment perspective," Cornhill said. "We think it's easier, the impact is lower … cost control is better."
Exxon selects onshore over floating plant for B.C. LNG proposal
(Globe and Mail; Canada; June 8) - ExxonMobil has selected onshore terminal plans in its quest to export liquefied natural gas from a site near Prince Rupert, B.C., positioning the project as a serious contender. While the Petronas-led Pacific NorthWest LNG project looks to be ahead in the quest to be Canada’s first LNG export terminal, ExxonMobil and its Canadian affiliate Imperial Oil hope to finish engineering studies in 2017 for their joint venture called the WCC LNG Project.
WCC LNG disclosed in January that the capital cost for the first phase could range from $15 billion to $25 billion, and it would choose either a barge-based marine facility or onshore terminal. “After extensive study, the concept that will be considered for further definition at the Tuck Inlet project site is an onshore LNG plant,” WCC LNG regulatory manager Michael Bigler said in a letter to the B.C. Environmental Assessment Office. Industry analysts say the onshore system will be more expensive to build.
Industry analysts say only three or four of the 19 B.C. LNG proposals have a realistic chance of being built, especially with a looming global glut of supplies and fierce competition worldwide to export to Asia. “British Columbia’s cost environment remains challenging,” Imperial Oil spokesman Pius Rolheiser said in a statement, cautioning that WCC LNG is in its early stages. WCC LNG estimates it could take years for engineering, permitting and construction, putting the project’s first production into 2024.
Proposed B.C. gas pipelines cross paths with unhappy locals
(National Observer; Vancouver; June 8) - In British Columbia’s Kispiox Valley, 600 miles north of Vancouver, where “No LNG” lawn signs seem to be everywhere, rancher Gene Allen had strong words for TransCanada pipeline contractors. The crews showed up on the riverbed near his $2 million lodge yet again to scope out pipeline drill work, despite his repeated requests for them not to return. “I told him, ‘Over my dead body [you’d] ever put a drill pad in there,'” Allen recalled telling them last month.
“I just said, ‘You might as well take your papers and leave, because you can’t convince me of anything you’re doing is right,’" he said in a recent interview with the Vancouver Observer. Allen opposes LNG on environmental grounds. His objection is not only that the $5 billion pipeline would cross the Kispiox River within view of his lodge that attracts European and American sport fishers and hunters, and not that the pipeline would cross hundreds of rivers to pump fracked gas from the northeast to the coastal LNG plants.
What really bothers him, he said, is how fast the LNG industry is moving in, and how little control local residents have on this massive industrial push. Many are ranchers, farmers, loggers, fishers and guide outfitters, and they don’t want what they see as their sustainable way of life destroyed. “I’ve worked in oil and gas. It’s a boom-and-bust deal. It’s not sustainable,” Allen said. “The sports fishing industry is sustainable, the food-fishing for the First Nations is too. That’s their life blood.”
ConocoPhillips stops shale gas exploration in Poland
(Reuters; June 5) – ConocoPhillips said June 5 it has stopped its shale gas exploration in Poland due to unsatisfactory results, leaving the rest of the field to Polish state-run firms. Earlier this year, Chevron gave up looking for shale gas in Poland, following the withdrawal of ExxonMobil, Total and Marathon Oil over the past three years. ConocoPhillips said its subsidiary Lane Energy Poland had invested about $220 million in Poland since 2009. It drilled seven wells.
"We understand the disappointment surrounding this difficult decision," Tim Wallace, ConocoPhillips country manager in Poland, said in a statement. "Unfortunately, commercial volumes of natural gas were not encountered." Global oil firms were attracted to Poland a few years ago, sharing a belief that Eastern Europe's biggest economy would repeat the shale gas boom seen in the United States.
In 2011 Poland's former Prime Minister Donald Tusk said that he expected the first commercial shale gas in 2014, expressing hopes that it would help Poland significantly reduce its reliance on gas imports from Russia. A drastic cut in Poland's estimated shale reserves marked a first blow in 2012, and a slump in oil prices in the past year proved a second. Poland has not delivered a single commercial shale gas well.
Egypt this week will receive first LNG imports from Australia
(Reuters; June 9) - Egypt is set to receive its first liquefied natural gas delivery from Australia June 10, ship-tracking data on Reuters Eikon showed. The carrier had filled up at a port that serves as the loading point for two LNG export plants, Pluto and North West Shelf — both operated by Woodside Petroleum. Egypt has emerged as a new market for LNG as it looks to ease its worst energy crunch in decades. Falling output and rising demand have transformed it from an oil and gas exporter to a net importer.
Egypt started LNG exports in 2005 but has had to dramatically reduce its deliveries. In a turnaround, Egypt this year secured $2.2 billion worth of LNG largely from European traders in its first-ever tender to supply a newly installed import terminal moored on its Red Sea coast. Vitol, Noble Group and Trafigura secured deals to supply most of the volumes, while negotiations with BP continue. The Egyptian Gas Holding Co. has also signed deals to import 35 LNG cargoes from Gazprom and six from Algeria's Sonatrach.
Hawaii Gas still committed to bulk LNG imports in 2019
(Pacific Business News; Honolulu; June 9) – Hawaii Gas is still planning on importing bulk shipments of liquefied natural gas to the state starting in 2019, despite Hawaiian Electric’s delay of its own shipments of the fuel. “Our goal is still 2019,” said Alicia Moy, president and CEO of Honolulu-based Hawaii Gas, a subsidiary of Macquarie Infrastructure. “We are getting final bids shortly from finalists.” Moy declined to specify the names or numbers of finalists to supply LNG to the gas utility.
Hawaii Gas has been running a pilot project, bringing in LNG in 40-foot-long tanks carried aboard containerships from California. The utility is looking toward bulk deliveries to increase volumes and reduce costs. It has been making synthetic natural gas from naphtha at a local plant.
Hawaii Gas plans to supply itself and other independent power producers in the state with LNG, as well as looking to serve other industries, including ground and marine transportation companies, and possibly even Hawaiian Electric. Earlier this month, Hawaiian Electric said it does not envision shipping LNG to Hawaii until 2019, two years later than it had originally planned. Low oil prices have changed the economics of importing LNG to burn for power generation.
Texas questions link between injection wells and earthquakes
(Wall Street Journal; June 6) - Texas officials are scrutinizing several energy producers in the wake of multiple earthquakes that have shaken the Dallas-Fort Worth area this year, questioning the use of injection wells to dispose of wastewater from hydraulic fracturing operations. The state oil-and-gas regulator is holding hearings this month. A growing body of research suggests that disposal wells, often used to get rid of the dirty water left over from fracking and the brine from oil-and-gas production, may be linked to increased seismic activity. Some in the industry are trying to discount those studies.
But Ryan Lance, chief executive of ConocoPhillips, concedes there is a link. “We’ve followed all the data and the evidence and it does appear that in some areas water disposal is creating seismic events,” Lance said last month. One of the latest studies to link oil and gas activity to the tremors comes from Southern Methodist University in Dallas. It connects a fracking wastewater disposal well operated by XTO Energy, an ExxonMobil subsidiary, and a disposal well owned by EnerVest to a series of quakes near Fort Worth between November 2013 and January 2014.
SMU researchers say the quakes were probably the result of subsurface pressure changes caused by wastewater injections that occurred at the same time as drilling operations were causing large amounts of brine to flow up to the surface. The pressure changes appeared to activate a long-dead fault, said Matt Hornbach, an SMU associate professor of geophysics. Whether more recent quakes around Dallas were caused by injection wells remains in question. “I don’t want to rush to judgment,” he said.
The heightened scrutiny comes six months after the Texas state regulator changed its well permitting rules. It can now modify, suspend or end disposal well approval if scientific data shows the well is contributing to earthquakes, or is likely to do so.
Pipeline company wants to move Marcellus gas into New England
(The Daily Review; Towanda, PA; June 9) - The Tennessee Gas Pipeline Co. is proposing a $5 billion expansion of its pipeline system in the northeastern United States. The expansion — the Northeast Energy Direct Project — would move low-cost gas from the Marcellus Shale to New England in order to meet the region’s growing demand for the fuel, said Richard Wheatley, a spokesman for Kinder Morgan, the parent company of Tennessee Gas Pipeline.
New England currently does not have access to enough natural gas, due to a lack of pipeline capacity to bring the fuel to New England, which has led to high gas and electricity prices in the region. New England gets 52 percent of its electricity from gas-fired power plants, Kinder Morgan said. A 2014 report by the Industrial Energy Consumer Group of Augusta, Maine, said New England experienced its highest energy prices ever in the winter of 2013-2014, twice as high as a year earlier.
The Northeast Energy Project also includes the construction of pipeline laterals and delivery lines in Massachusetts, Connecticut and New Hampshire, nine compressor stations and other upgrades. The project would be capable of providing 2.2 billion cubic feet of gas per day to markets in the northeastern U.S. and Canada. Tennessee Gas Pipeline said it expects to submit an application in September to the Federal Energy Regulatory Commission for a construction certificate. Gas could flow in 2018.
Rail shipments help make up for drop in West Coast oil production
(U.S. Energy Information Administration; June 9) - While total U.S. crude oil production increased by nearly 3.2 million barrels per day from 2010 to 2014, production in the West Coast region decreased by 100,000 barrels, continuing a long-term decline, reports the Energy Information Administration. With no major pipelines linking the coast to supplies from elsewhere in the U.S., West Coast refineries have adjusted to declining regional production by boosting imports. Alaska’s North Slope — ranked second behind California on the West Coast — dropped 110,000 barrels a day between 2010-2014.
In addition to boosting imports, domestic crude shipments by rail to the West Coast have also increased, from an average of 23,000 barrels a day in 2012 to 157,000 in 2014. In the first quarter of 2015, rail deliveries to the West Coast averaged 191,000 barrels a day, the EIA reported June 9. Bakken crude oil production — mostly from North Dakota — is the major source of rail shipments to the West Coast, accounting for nearly 90 percent of West Coast crude-by-rail receipts in 2014.
Crude by rail is moved to unloading facilities at refineries in Washington state and to transfer terminals in California, Washington and Oregon, where coastal vessels and pipelines move the oil to refineries without rail facilities, the EIA said. In California, regulatory and permitting problems have delayed construction of some unloading facilities and forced the closure of operations at others. Despite permitting delays, refineries in California receive some domestic crude oil by rail from Utah and Wyoming.
Company president sets sights on Alberta-to-Atlantic oil pipeline
(Financial Post; Canada; June 8) - Even seasoned energy executives have struggled with trying to get a single major new oil pipeline built from Alberta over the past decade. François Poirier turned his back on a successful banking career to attempt that very mission. The president of TransCanada’s Energy East pipeline is tasked with tip-toeing around provincial politicians, battling environmentalists and engaging communities and First Nations in an effort to build a 1.1-million-barrel-per-day Alberta-to-New-Brunswick corridor at a cost of $12 billion — the most expensive pipeline in the country’s history.
The goal is a 2,850-mile cross-country pipeline that would feed Eastern Canadian refineries and connect trapped Alberta oil sands to export markets via a terminal in New Brunswick. Success would propel Poirier to the status of a modern-day energy pioneer and a cult figure in the industry, especially as seasoned Canadian pipeline executives have seen their otherwise stellar careers marred by loud opposition to their projects.
Poirier is a fair distance from his own finishing line. He suffered a false start in Quebec. Six months after turning in its application to the National Energy Board, TransCanada retreated from a plan to build a marine terminal on the St. Lawrence River in Quebec, conceding to environmental opposition. The rookie energy executive acknowledged it will require more than engineering and regulatory know-how to get the line built. Despite the uphill task, Poirier said the opportunity to lead the project is a “dream scenario.”