Pakistan looks to low-cost coal, even as it boosts LNG imports
(Bloomberg; March 21) - Pakistan imported its first liquefied natural gas in 2015 and is building up its capacity to buy more of the fuel for power generation, but its coal reserves would give the nation a cheap domestic alternative to expensive oil and gas imports. The nation spends about $8 billion a year on imported petroleum and already is one of the region’s biggest buyers of LNG. In the Thar Desert, Pakistan has begun to dig up one of the world’s largest deposits of low-grade, brown, dirty coal to fuel new power stations that could revolutionize its economy.
The Thar project is one of the most expensive among ambitious energy developments that China is helping Pakistan to build as part of a $55 billion economic partnership. A $3.5 billion joint-venture between the nations will extract coal to generate 1.3 gigawatts of electricity that will be sent across the country on a new $3 billion transmission network. Pakistan relies on coal for just 0.1 percent of its power, according to the Pakistan Business Council. The Thar project and others could see that jump to 24 percent by 2020, said Tahir Abbas, an analyst at Karachi-based brokerage Arif Habib.
On paper, Pakistan could be one of Asia’s top economies, with almost 200 million people. But it remains hobbled by corruption, political turmoil, terrorism and poverty, all underpinned by a crippling shortage of energy. The country has natural gas reserves, four nuclear power stations and the world’s largest dam. Yet power outages remain a way of life with blackouts of 12 hours or more. Thirst for energy is taking Pakistan in the opposite direction of Western countries that are trying to reduce coal-fired power.
Mideast LNG demand growth predicted to stabilize in couple of years
(Gulf News; March 22) - Liquefied natural gas demand in the Middle East is expected to continue to grow over the next two years before stabilizing above 29 million metric tonnes per year, about 1.4 trillion cubic feet of gas, according to forecasts from S&P Global Platts. In 2014, the region, which also includes Pakistan, imported 4.3 million tonnes of LNG, or just under 2 percent of total global LNG imports. By the end of 2016, the figure had increased to 20.9 million tonnes, or 7.9 percent of the global total.
“Over the past three years, LNG imports into the region have grown by more than 380 percent at a time when deliveries to traditional demand centers have been relatively stagnant or in decline,” S&P Platts said in a report on LNG demand in the Middle East that was shared with the media at a press conference in Abu Dhabi on March 21. The growth in LNG import volumes is tied to increased use for gas-fueled power generation.
According to the report, Egypt is expected to remain the largest importer of LNG in the region over the next two years, after which domestic gas supplies are set to displace much of the demand for LNG. Imports into the UAE are expected to continue to increase with the delivery of the country’s second floating storage and regasification unit in 2016 and a third import terminal set to be installed in the emirate in mid-2018. The UAE mainly imports gas to generate electricity. The report also said that Bahrain will be the next Middle East country to enter the LNG market in 2018.
Asian spot-market LNG prices for May slip to $5.65
(Reuters; March 20) - Asian spot-market LNG prices fell again this week with Angola releasing additional supply even as more Australian and U.S. production gears up at a time of already saturated markets. Spot prices for May delivery slipped to about $5.65 per million Btu, 10 cents below last week's levels. Sources said April prices continued to slide from last week's $5.85, even straying to $5.50.
Output from the third production line at Australia's giant Gorgon plant is due to start this month, project operator Chevron said. In addition, Cheniere Energy's third production line at its Sabine Pass, La., terminal looks set for "substantial completion" by the end of this month, with the first test cargo having already been shipped. And two cargoes put up for tender by Angola LNG show the extent to which that project has hit its stride after various setbacks last year.
Total may take 50.1 percent interest in Iranian natural gas project
(Reuters; March 17) - Total is seeking a 50.1 percent stake in a $4 billion project in Iran's giant South Pars gas field, the French energy firm said in a regulatory filing March 17. The filing detailed talks held with Iranian officials on several projects in 2016. Total signed a preliminary deal for the South Pars project last year, becoming the first Western oil major to sign an energy agreement after the European Union and the United States eased sanctions as part of a pact to curb Iran's nuclear ambitions.
In a filing with the U.S. Securities and Exchange Commission, Total said the South Pars 11 project would require investment of about $4 billion, with Total financing 50.1 percent with equity contributions. If finalized, Total would operate the project China National Petroleum Corp. would own 30 percent through one of its subsidiaries and Iran's Petropars would have 19.9 percent. Total had not previously given details about the value of the project or indicated the breakdown of ownership.
South Pars is part of a Persian Gulf reservoir that is one of the biggest gas fields in the world, but its development has been hobbled by years of Western sanctions imposed on Iran. The South Pars project is expected to have a production capacity of 370,000 barrels of oil equivalent per day and the gas would be fed into Iran’s distribution grid. Total is expected to make a final investment decision by summer. Total also said in its filing that it discussed other projects with Iranian officials in 2016 and carried out technical reviews, including possible investment in a liquefied natural gas export plant.
Chevron says it will focus on smaller LNG projects
(Bloomberg; March 21) - Chevron has signaled the end of major new liquefied natural gas projects in Western Australia and is unlikely to sanction expansion of its Gorgon or Wheatstone export projects as it focuses now on boosting returns from the multi-year investments. The climate for developing large greenfield LNG projects has shifted to smaller developments given the slump in oil prices to under $50 a barrel, said Nigel Hearne, a managing director with Chevron’s Australia unit.
“The mega projects of the past decade are giving way to smaller, more targeted investments with quicker economic returns,” Hearne said in a speech in Perth on March 21. Chevron’s two Australian LNG developments have suffered from cost overruns, delays and poor timing as oil’s worst slump in a generation and a global LNG supply glut reduced revenue from projects across the industry. The $54 billion Gorgon project, which is nearing completion, includes three liquefaction trains, while the $34 billion, two-train Wheatstone project is on schedule for start-up the middle of this year.
“I can’t see us in the near-term investing in a fourth train at Gorgon or a third train at Wheatstone,” Hearne said. Chevron is focused on generating returns on its existing investments and paying a “dividend back for the money” already spent. A growing supply glut will likely deter significant investment in new Australian LNG projects beyond 2017, according to a December report from Deloitte Access Economics.
Norwegian company sees market for floating LNG import terminals
(Reuters; March 20) - Norway's Hoegh LNG Holdings is targeting Australia as the next destination for its liquefied natural gas receiving, storage and regasification ships, its chief executive said March 20. Hoegh is talking with Australia's energy retailers and also sees the country’s big gas users as potential customers, with floating regas and storage units (FSRUs) giving those users access to the world market to meet their gas needs.
Australia is about to become the world's top exporter of LNG but faces a gas shortage at home as domestic producers have focused on supplying gas to liquefaction plants that are locked into 20-year export contracts. Importing LNG to meet local needs could be an option. "(Australia's) at the top of the opportunity list on our side," Hoegh LNG Chief Executive Sveinung Støhle told Reuters.
Domestic buyers could take advantage of a global glut of LNG to break the grip of Australia's big gas producers that have more than doubled contract prices to big gas customers such as power producers and fertilizer, brick and packaging manufacturers. "If they're not happy with the price they're paying in Australia, well then they can buy LNG in the market," Støhle said. Hoegh LNG and fellow Norwegian company Golar LNG are world leaders in the construction of FSRUs, which have become attractive to gas importers as they are quicker and cheaper to build than onshore terminals.
Lower pipeline tolls help, but Canadian producers need LNG exports
(Reuters; March 20) - TransCanada's move to lower tolls for its Mainline west-to-east gas pipeline raises the competitiveness of Canadian natural gas for the near future, but access to Asian markets is the key to the long-term survival of the landlocked industry, industry insiders say. Canada's gas producers, which rely solely on North American demand, have been increasingly squeezed in the lucrative eastern market by U.S. rivals with lower transportation costs.
TransCanada said last week it will seek regulatory approval for a discount in tolls of nearly 50 percent for Western Canadian producers to use the Mainline to send their output to markets in the east, a move that has broad industry support. But the North American market will get more crowded in the future, with flat demand and increasing U.S. output, said a report by the Conference Board of Canada think-tank. It painted a bleak outlook for the industry, projecting U.S. output to eat into Canada’s market share.
Canadian producers still need to look to new markets in Asia, industry executives said. Canadian Natural Resources, which will ship on the Mainline, said while the lower toll is a "positive step" the company still supports accessing new markets. Growth will need to come in the overseas market with liquefied natural gas exports, said Stuart Mueller of the Canadian Association of Petroleum Producers. Though multiple LNG export projects have been proposed for Canada’s West Coast, none of the larger proposals have advanced to an investment commitment amid weak market conditions.
Canadian gas producers suffered $7.6 billion in losses last year
(EnergeticCity; Fort St. John, BC; March 20) - The Conference Board of Canada says tough times may be ahead for Canada’s gas producers. “North America’s gas market has changed greatly over the last decade. Rising U.S. shale production has increasingly squeezed Canadian gas out of some U.S. markets,” said Conference Board of Canada Economist Carlos A. Murillo in the group’s latest outlook on gas production. “Not only is the U.S. market moving toward self-sufficiency, but the U.S. gas industry is also beating Canadian competitors in the race to enter global liquefied natural gas markets.”
U.S. gas output increased 40 percent in the past decade, mainly due to rapid growth in shale gas. In the meantime, Canadian production stagnated to the point where today’s U.S. shale production is about three times greater than Canada’s total output. With U.S. shale gas displacing imports of Canadian gas, Canadian exports are 25 percent lower than they were 10 years ago. The changes to supply, along with a warm winter, led to the lowest prices since the late 1990s last year and pre-tax losses for Canadian gas producers of $7.6 billion (Canadian).
North American gas demand is expected to remain relatively flat, and Canadian exports to the U.S. could continue to decline over the next five years. Although gas use in Canada’s electricity generation and industrial sectors will increase, those gains will not be enough to offset a potential decline in exports to the U.S. “Unless a large domestic LNG export facility is built, Canadian production levels will continue to fall,” Murillo said.
Alberta forces oil and gas company into receivership
(Calgary Herald; March 21) - Alberta’s energy watchdog has taken the unprecedented step of forcing a Calgary oil and gas company into receivership for allegedly failing to look after its assets safely. The more than 1,400 wells, pipelines and facilities of Lexin Resources will be sold by a court-appointed receiver, the Alberta Energy Regulator said March 21. The agency shut down the properties last month after Lexin raised doubts it could ensure the safety of its sour gas wells, which contain potentially deadly gas.
“We believe that this is the most appropriate course of action following Lexin’s continued disregard for the requirements to ensure public safety and environmental protection,” said Cara Tobin, a spokeswoman for the provincial regulatory agency. Lexin has blamed most of its problems on the regulator. Michael Smith, a Lexin director, said in a recent letter that the agency improperly demanded tens of millions of dollars in security deposits along with “grossly overstated” fees and other charges.
Because of the actions and a lien against its property, it has been “virtually impossible” for the company to obtain financing, sell its assets and deal with creditors, Smith said in a memo. Lexin last summer told the regulator its leak detection system was not working, sparking fears about safety at its wells and facilities. It also warned it had laid off most of its staff and could not respond to emergencies. Most of the wells were transferred to the Orphan Well Association, an industry-funded group responsible for ensuring the assets are safe until a buyer can be found or Lexin complies with the rules.
TransCanada wants to start work on $1.4 billion B.C. gas pipeline
(Vancouver Sun; March 20) - TransCanada is seeking regulatory approval to start next year on construction of a pipeline that would help feed a proposed liquefied natural gas export plant on B.C.’s north coast, even though a final decision has not been made whether to build the terminal. The Calgary-based company has conditional federal and provincial approvals for the North Montney Mainline, subject to an investment decision on the proposed Pacific NorthWest LNG project on Lelu Island near Prince Rupert.
TransCanada has asked the National Energy Board to allow it to move forward with construction of almost 130 miles of pipeline and related facilities of the proposed 190-mile North Montney Mainline ahead of the LNG project decision. Construction would cost about $1.4 billion and connect the North Montney project with TransCanada’s existing pipeline network southwest of Fort St. John, B.C., allowing the company to ship the gas to markets across Canada and much of the U.S., not just to the B.C. coast.
Company spokesman Shawn Howard said growing B.C. Montney basin output means there is demand for the pipeline, which could carry 1.5 billion cubic feet of gas per day, even without a final go-ahead on the LNG terminal. “Simply put … shippers have a need to connect their North Montney gas supply to market,” said Howard in an email. The LNG project is primarily backed by Malaysia’s national oil and gas company Petronas, which has yet to make an investment decision on the Pacific NorthWest LNG project.
Kinder Morgan plans 430-mile line to move Permian gas to coast
(Houston Chronicle; March 22) – Houston’s Kinder Morgan said March 22 it plans to build a 430-mile gas pipeline from the West Texas Permian Basin to the Corpus Christi region on the Gulf Coast. The project is designed to capitalize on growing Permian oil and gas production to carry more gas to the Texas coast, where it can be consumed locally, refined and exported, or shipped to Mexico. The 42-inch-diameter pipeline could be completed in late 2019. Kinder Morgan did not reveal the project’s estimated costs.
Although everyone in the Permian is drilling for oil, most of the wells drilled also produce associated gas and gas liquids. That extra gas is why producers don’t need to drill specifically for gas in West Texas. The proposed Gulf Coast Express Pipeline could tap into Kinder Morgan’s existing Permian-area pipeline network, as well as Energy Transfer Partners’ new Trans-Pecos Pipeline, which will ship gas from Texas to Mexico.
The growing petrochemical sectors in the Houston and Corpus Christi areas are consuming more gas for feedstock, while new Gulf Coast liquefied natural gas projects need gas to convert into LNG for export. Also, Mexico increasingly relies on Texas shale gas for power generation. Kinder Morgan already is expanding an existing line from Texas and Arizona into Mexico. Likewise, Energy Transfer, as well as Canadian pipeline giants Enbridge and TransCanada are all building new gas lines into Mexico.
Shell sees profitable future in budget deep-water drilling
(Wall Street Journal; March 20) - Shell is trying to reinvent its business with a concept that sounds oxymoronic: budget deep-water drilling. The company is working on the Mars platform 130 miles southeast of New Orleans to wring more oil out of a massive old field — and to keep it profitable even if oil sinks to $15 a barrel. Shell is making a high-stakes bet that it can apply highly efficient technologies and processes perfected onshore as it hopes to squeeze more oil out of wells like those that ring the platform.
It also wants to make new deep-water projects cheaper and faster, especially in Brazil, where it acquired a bevy of offshore prospects as part of its $50 billion purchase of BG Group last year. It is a strategy born of necessity. Big oil companies have traditionally needed $70 oil or more just to break even on new deep-water projects. But with shale oil flooding the market, that price isn’t expected anytime soon. So while Shell doesn’t say the megadrill era is gone forever, it isn’t comfortable spending $10 billion to $20 billion on moonshots. Shell is going lean to focus on projects that produce first oil faster.
The company’s longstanding goal of increasing production and replenishing reserves, costs be damned, has taken a back seat to delivering returns on every barrel. That means deep-water projects have to compete with opportunities in shale and onshore basins around the world. Shell initially discovered Mars in 1989, and it took seven years and more than $1 billion before first oil. Production peaked at more than 225,000 barrels a day in 2002, later falling as low as 60,000. The company’s goal now is to squeeze more oil out of the field. Mars has recently rebounded to pump 75,000 barrels a day.
Big Oil sees big future in U.S. shale oil
(Bloomberg; March 21) - ExxonMobil, Shell and Chevron are jumping into U.S. shale with gusto, planning to spend a combined $10 billion this year, up from next to nothing a few years ago. The giants are gaining a foothold in West Texas with such projects as Bongo 76-43, a well being drilled 10,000 feet beneath the desert, extending horizontally for a mile, blasting through rock to capture light crude oil from the Permian Basin.
While the first chapter of the U.S. shale revolution belonged to wildcatters who parlayed borrowed money into billions, Bongo 76-43 is financed by Shell. The majors have been as relentless in transforming shale drilling into a more economically efficient operation as the pioneering wildcatters before them. If Big Oil is successful, it will boost U.S. oil output, keep prices low and steal influence from other producers such as Saudi Arabia.
“We’ve turned shale drilling from art into science,” Cindy Taff, Shell’s vice president of unconventional wells, said on a visit to Bongo 76-43, 100 miles west of Midland, Texas. The well, named after an African antelope, shows a leaner, faster industry. Traditionally, oil companies drilled one well per pad. At Bongo, Shell is drilling five wells in a single pad for the first time. That saves money otherwise spent moving rigs from site to site. Shell is now able to drill 16 wells with a single rig every year, up from six wells in 2013.
“The arrival of Big Oil is very significant for shale,” said Deborah Byers, of consultancy Ernst & Young in Houston. “It marries a great geological resource with a very strong balance sheet.” Exxon plans to spend one-third of its drilling budget this year on shale, aiming to reach nearly 800,000 barrels a day by 2025, up from less than 200,000 now.