LNG glut delayed, but still coming, says one analyst
(Platts analysis; June 21) - The great LNG glut predicted for 2016 as new Australian and U.S. LNG projects came online didn't quite materialize, with disruptions to existing output in Yemen, Libya, Egypt and Angola, combined with underperformance from some of the new producers, resulting in less LNG on the market than expected. But it has just been delayed, Anne-Sophie Corbeau, research fellow at the King Abdullah Petroleum Studies and Research Center in Saudi Arabia, said June 20.
Corbeau spoke at the International Association for Energy Economics conference in Singapore. She said LNG trade expanded by 27 million metric tons per year between 2014 and 2016, while 65 million tons of new capacity came online. She expects an additional 100 million tons of annual capacity starting up between 2017 and 2020, adding to the delayed supply glut. Meanwhile, final investment decisions (FIDs) on new LNG projects have all but dried up, Corbeau said.
The prognosis is that steadily growing demand will soak up the excess supply, and the lack of new projects will see the market eventually move back into deficit. The question is when. Forecasts for LNG demand remain highly uncertain. Tatiana Mitrova, with the Energy Research Institute of the Russian Academy of Sciences, said there will be no need for new Russian LNG or pipeline gas to Asia until 2025. Andrew Seck, vice president for LNG marketing at Anadarko, said FIDs are never easy, but particularly so in the current environment in which there is no common view about the future.
Operator will close U.K.’s largest natural gas storage facility
(Reuters; June 20) - Britain's largest gas storage site under the North Sea will be permanently shut by operator Centrica following repeated outages as failing wells prevent its safe restart, Centrica said June 20. At over 30 years old, the facility accounts for about 70 percent of U.K. storage capacity. A lack of new-build to replace Rough will increase dependency on liquefied natural gas imports and Norwegian pipeline gas over the next few years, boosting market volatility and prices, analysts and traders said.
Seasonal gas storage provides security and flexibility of supply. At times of low demand and low gas prices in the summer, gas is injected into storage to be held for when demand rises in the winter. Rough could cover a tenth of Britain's peak winter demand. "Due to the age and condition of Rough we can no longer safely inject gas into the reservoir and build up the pressure in the well," a Centrica spokesman said. Rough, a partially depleted gas field, is 18 miles off the coast of Yorkshire in Northern England.
The spokesman said falling demand for storage facilities would have forced Centrica — the U.K.’s largest supplier of gas to domestic customers — to close Rough regardless of the cost to refurbish its aging wells. European utilities are losing billions of euros from gas storage facilities in a market suffering from oversupply and weak demand. Centrica said it intends to file applications to permanently end Rough's status as a storage facility but aims to produce all recoverable gas from the field, at 183 billion cubic feet.
Total commits to initial $1 billion investment in Iranian gas
(Reuters; June 20) - Total will go ahead with development of a giant Iranian gas field this summer, its CEO told Reuters, in the first major western energy investment in the country since Tehran signed an international nuclear accord. Chief Executive Patrick Pouyanne said Total would make an initial $1 billion investment after the United States extended sanctions relief for Iran, even though Washington has warned it could cancel the waivers if it believes Tehran is not curbing its nuclear program in line with the deal.
"It is worth taking the risk at $1 billion because it opens a huge market. We are perfectly conscious of some risks," Pouyanne said. The offshore field was first developed in the 1990s, and Total was one of the biggest investors in Iran until international sanctions were imposed in 2006 over suspicions that Tehran was trying to develop nuclear arms. Total has decided to return and develop Phase 11 of the South Pars project in the Gulf, which will cost up to $5 billion.
Most major international giants have so far shown limited appetite to invest in Iran, due to uncertainty over contract terms and a sharp drop in oil prices. Total holds a 50.1 interest in the South Pars project along with state-owned China National Petroleum Corp. (30 percent) and Iran's Petropars (19.9 percent). The gas will supply the fast-growing domestic market and none will be exported, Pouyanne said. South Pars is part of a giant reservoir that straddles the territorial waters of Iran and Qatar. Iran’s gas reserves are estimated at almost 1,200 trillion cubic feet — the largest in the world.
Qatari situation could prompt Japan to diversify its LNG supply
(Nikkei Asian Review columnist; June 19) - In early June, Saudi Arabia and its allies sent ripples through financial markets and global diplomatic circles by blacklisting Qatar, accusing the state of sponsoring and nurturing ties with terrorists. One of the countries most exposed to the crisis is Japan, which faces significant potential costs. Japan relies on Qatar as a major source of liquefied natural gas. Qatar provided 18 percent of Japan's LNG supplies in 2016, the largest proportion after Australia and Malaysia.
The growing rift between Qatar and its neighbors should raise alarms and further push Japan’s moves to diversify its energy supply. At this point the direct damage to Japan's interests is minimal, but that could change if the situation escalates. Tokyo must remain engaged, and aware of the costs and benefits of becoming too entangled. In this sense, it makes sense that Japan's initial response was to "wait and see.” Still, there are ways for Japan to mitigate the risks and to seize opportunities from the crisis.
One of these should be seeking greater spot trading of LNG in place of the current system of supplier-friendly, long-term deals that lock in prices. Japan's largest utilities are negotiating to renew a multibillion-dollar LNG contract with Qatar, which expires in 2021. The political uncertainty and regional pressure facing Qatar puts the Japanese companies in a stronger position to demand greater flexibility and a larger role for spot trading. In that context, the Qatar crisis has hastened an opening in the LNG supply market and could lead to greater diversity in suppliers, including the United States.
Qatar strikes 5-year deal to sell LNG to Shell for European market
(Platts; June 19) - Qatargas has agreed to sell 5.5 million metric tons of LNG over five years to Shell, amid uncertain demand from its Asian long-term buyers and building diplomatic tensions with its trading partners in the Middle East. Under the sales and purchase agreement, the state-owned producer will supply Shell with 1.1 million tons a year starting in 2019, according to a statement released by Qatargas on June 18.
The LNG will be sourced from the Qatargas 4 project, a joint-venture between Qatar and Shell, and delivered to the U.K.'s Dragon LNG terminal and the Netherlands' Gate LNG terminal. The agreement comes amid growing uncertainty over demand from Qatar's long-term buyers in northeast Asia. Close to one third of the LNG produced by Qatar, the world's largest supplier of the fuel, is now sold under spot- or short-term deals, as rising global supplies have forced the exporter to offer better terms.
A big share of Qatar’s existing contracts are due to expire by 2021, including 7 million tons per year contracted with Japanese utilities that are seeking more control via shorter, more flexible agreements, amid growing competition from other LNG suppliers. Qatargas has also seen its LNG strategy affected by the recent diplomatic crisis in the Middle East, with several countries having broken diplomatic ties with Qatar, including two of its LNG customers, over claims it funds extremism and terrorism.
City gas demand drives growth in India
(Live Mint; India; June 19) - City gas usage will drive demand for natural gas in India, energy and commodities information provider Platts said in a recent report. City gas includes piped gas delivered to homes, compressed natural gas used in automobiles and gas delivered to industrial plants. “City gas will see its share of domestic gas usage rise to 24 percent in 2021 from the 20 percent used in 2016. This is in line with the government’s goal of increasing city gas availability for households and transportation,” said the report, “Feeding the Tiger: Search for Transparently Priced Indian LNG.”
Commercial and industrial consumers are also taking advantage of the increased availability of city gas. “Seventy-five city gas networks have been authorized,” the report said. “The rapid pace of adoption and strong government support means the city gas sector is expected to show the fastest relative growth among the gas demand sectors.”
Natural gas accounts for only 6.5 percent of India’s energy mix, compared with almost 60 percent for coal. The relatively low gas-penetration rate is a result of India’s abundance of relatively cheap domestic coal, infrastructure bottlenecks choking gas supply, price uncertainty over gas imports, and low domestic gas production. Over the next five years, India’s imported LNG demand is expected to grow on average 10 percent annually, reaching about 30 million metric tonnes by 2020.
Australia will introduce LNG export-restriction regulations July 1
(The Associated Press; June 20) – The Australian government will restrict natural gas exports next year in an effort to contain soaring energy prices in the domestic market, the prime minister said June 20. Australia is about to overtake Qatar as the world's largest exporter of liquefied natural gas. But many Australians face escalating power bills because state governments have restricted gas exploration and no new coal-fired power stations are being built to replace aging generators that will soon close.
Prime Minister Malcolm Turnbull said he would not tolerate customers in Japan paying less for Australian gas than some Australian businesses. "Our first duty is to protect our people, our businesses, our households," he said. "You can't seriously suggest that we — a nation that is about to become the largest exporter of LNG in the world — would have a shortage of gas in its East Coast domestic market. We have to address that."
The government will introduce new regulations July 1 that will require energy companies such as ExxonMobil, Shell, Santos and Origin to give Australian customers priority access to gas supply before it is exported. After the Australian supply shortfall is calculated, new regulations to restrict gas exports will take effect on Jan. 1, 2018.
Exxon decides to go ahead with oil project offshore Guyana
(EnergyWire; June 19) - ExxonMobil announced it will pursue a new greenfield project off the coast of Guyana, the small South American nation bordering oil-rich Venezuela. Exxon said it has made a final investment decision to develop the Liza offshore field. Liza was discovered five years ago and the company reported last year that the find holds at least 800 million barrels of recoverable hydrocarbons.
Exxon officials think they can have Liza producing about 120,000 barrels per day as early as 2020. Liza will be added to additional recoverable resources offshore Guyana that Exxon plans to exploit. "Gross recoverable resources for the Stabroek block are now estimated at 2 billion to 2.5 billion oil-equivalent barrels, which includes Liza and other successful exploration wells on Liza Deep, Payara and Snoek," the company told media and shareholders in a news release.
Pablo Medina, a Latin American energy analyst at Wood Mackenzie, said in a note to clients that Exxon's announcement likely underscores the potential of the Liza project. Achieving an investment decision in five years "signals the competitiveness of the project, both within the company's portfolio and globally," Medina said. "We currently forecast the full development of Liza-Payara will produce over 330,000 [barrels per day] of oil at peak."
Canada’s offshore Atlantic draws renewed oil industry interest
(The Financial Post; Canada; June 15) - After three rough years, Newfoundland and Labrador’s offshore oil industry is in recovery mode as the Hebron project gets ready to produce first oil, the West White Rose project starts construction and exploration activity surges, fueling hope of another major find. Among those leading the way are companies that cooled off on the landlocked oil sands — Norway’s Statoil, France’s Total, China’s CNOOC and BP — but are motivated to find the next monster Canadian offshore fields.
Bids to explore in the Atlantic have soared even as oil companies were cutting back programs elsewhere, said Jim Keating, executive vice president for offshore development at provincial Crown corporation Nalcor Energy. Interest in the region perked up after Statoil and partner Husky Energy discovered Bay du Nord in 2013 in the Flemish Pass basin. Further exploration wells are planned this summer. Meanwhile, the region will see the largest 3D data capture in its history this summer, Keating said.
In the past 18 months, seven companies entered the region for the first time: Anadarko, Hess and Noble from the U.S.; Navitas Petroleum from Israel; as well as CNOOC, BP and Total. They joined established operators Chevron, ExxonMobil, Husky, Murphy Oil, Statoil and Suncor Energy. Hebron is expected to start producing oil at the end of 2017. Husky is moving ahead with West White Rose after cost savings and negotiations with the provincial government improved its attractiveness, and first oil is expected in 2022.
Texas should spend more on roads in rural drilling areas, report says
(EnergyWire; June 20) - Texas needs to increase its funding for rural roads to offset the deaths and damage caused by the shale-drilling boom, and needs to do more research on the environmental and social effects of oil and gas drilling, said a report by the state's top scientists. The Academy of Medicine, Engineering and Science of Texas spent more than a year reviewing scientific literature on the impacts of the boom in shale drilling.
While drilling has boosted the state's economy, its impact isn't widely understood in part because of a lack of data, the report said. The academy is comprised of the Texas members of the National Academies of Sciences, Engineering and Medicine, and all of the state's Nobel Prize laureates. The report was written by 19 researchers from universities, corporations and a nonprofit group. It was funded in part by the Cynthia and George Mitchell Foundation, established by one of the pioneers of shale drilling.
The report looked at earthquakes, air quality, water quality, land issues such as fragmentation of wildlife habitat and social impacts such as the uneven distribution of wealth. Each well can require 988 to 1,708 loaded truck trips over its life cycle, making the wear on roads one of the most visible impacts of the boom. "The traffic safety issue is one of the most pressing concerns we found," said John Barton, a researcher at Texas A&M University. Between 2010 and 2013, there were 183 fatal crashes involving trucks or other commercial vehicles in the Permian Basin oil field in West Texas. That's nearly double the number from the previous four-year period, the report said.
Closure of coal-fired power plants hits local economies
(Wall Street Journal; June 20) - Far from the mines of Appalachia, the decline of coal is hitting communities that relied on coal-fired power plants for jobs and income. Over the past five years, roughly 350 coal-fired generating units shut down in the U.S., according to federal data. Many of these plants were built near mines in Appalachia and western states. But generators far from coal fields — like New England — have also turned off.
The shutdowns can cost communities high-paying jobs and important sources of tax revenue. Gas-fired plants have been built up to replace the retiring coal generators, but those plants need far fewer workers — one for every five that worked at a coal plant, by some estimates. A 54-year-old coal-fired plant in Somerset, Mass., stopped operating three weeks ago, and local officials started raising property taxes several years back to compensate for lower revenue from the town’s largest taxpayer as production slowed.
In Adams County, Ohio, where two coal-fired plants will shut down, county auditor David Gifford sees layoffs of public employees, program cuts for seniors, libraries and schools, as well as a steep hike in property taxes. The plants contributed more than 30 percent of the county’s $27 million in total tax revenue. It’s a scene being played out elsewhere as more coal plants retire, squeezed out in part by new, cheaper-to-run gas-fired plants.
Cassville, Wis., lost 55 percent of its tax revenue when two coal plants shut in 2015, said Keevin Williams, president of the village of 950 people. The community has cut staff and put off projects. “We’re a small community. When you lose 90 jobs, that’s 10 percent of your population,” Williams said. Last year, gas surpassed coal for the first time in U.S. electricity generation, providing 34 percent of the nation’s power, versus 30 percent for coal. As recently as 2011, coal provided roughly 43 percent of generation.
‘Frack hits’ become problem as new wells run into old wells
(Wall Street Journal; June 21) - Supersized new oil wells are sometimes running into existing wells, a little-noticed consequence of the shale boom that has started to trigger complaints and lawsuits. The problem is known as a “frack hit,” and it has flared up in Oklahoma, where a group of small oil and gas producers say more than 100 of their wells have been damaged by hydraulic fracturing jobs done for bigger companies.
In hydraulic fracturing, firms pump sand and water deep underground at high pressure to break oil and gas from rock. Some owners of older wells have filed reports with state regulators claiming their wells were flooded with water. In some cases, the wells became so full that the water rose to the surface and spilled out. Others have claimed they had to shut in wells due to the damage. A few cases have ended up in court.
While newer wells damaging older ones is a longstanding problem, the issue is gaining attention as companies employ new technologies to drill wells horizontally. James West, with Evercore ISI, who has been following frack hits, said they are of special concern in Oklahoma and Texas, where those drilling new wells must navigate around older wells drilled over decades. “It’s becoming a pretty sizable issue,” he said. Some expect the situation will only get worse. “We’ve got bigger fracks, so more chance of them reaching across, well-to-well,” said Jennifer Miskimins at the Colorado School of Mines.