9-22-15 BP’s US and Alaska Economic Reports

LNG buyers making progress in push for more flexible contracts
 
(Platts; Sept. 18) – Calls for increased contract flexibility dominated discussions at the fourth annual LNG Producer-Consumer Conference in Tokyo this week, as industry participants met once again to deliberate emerging trends in the LNG market. The debate advanced some from a year ago, when price indexation had largely taken center stage. With some flexibility now granted in this area, the focus increasingly turned to the still-restrictive terms around LNG delivery schedules and destinations.
 
Numerous industry observers saw the removal of destination clauses, take-or-pay terms and wider quantity tolerance in contracts as key components that will be necessary to manage the looming supply glut in LNG. "LNG producers must improve on the contract practices of the past. Simply put, producers need to help increase the flexibility of the trade," said Jae-do Moon, South Korea's vice minister for trade, industry and energy.
 
Jean-Pierre Mateille, Total Gas & Power's vice president for trading, conceded that changes around delivery and schedule terms in contracts were inevitable. "Contracts are becoming shorter.” Most U.S. LNG exports will allow destination flexibility, Mateille said, “We see the traditional link between producer of gas and buyer has been broken up by this new business model.” Satoshi Kusakabe, commissioner of Japan METI's Natural Resources and Energy Agency, said removal of destination clauses would help the market because it would draw more players and increase liquidity and spot trades.
 
Meanwhile, market uncertainty and lack of new project sanctions has prompted caution of future shortages. "Even at current projections, we need to add about 20 million metric tons of LNG per year to maintain a stable supply demand balance [from 2023 onward]," said Demus King, general manager for offshore resources at Australia's Department of Industry and Science. "To deliver in 2023, FIDs need to be made in the next few years."
 
Global commodity traders see big opportunities in LNG
 
(Reuters; Sept. 17) – Mining and trading giant Glencore is mounting a challenge to Trafigura and Vitol to become the top merchant trader of liquefied natural gas as a global market in which sales are largely frozen in decades-long contracts looks ready to thaw. Trafigura recently adopted tactics developed from years of trading oil to become the world's top LNG merchant, investing in logistics and storage, while also providing credit and shouldering risk for buyers.
 
Glencore, on the other hand, plans to double its global LNG trading team and trade as many as 50 cargoes of the fuel over the next year — almost twice what Trafigura traded in its past fiscal year. LNG could soon surpass iron ore as the world's second-biggest traded commodity, with estimates of the market's worth ranging between $90 billion and $150 billion. "The opportunity for growth in LNG trading is spectacular," said Glencore's global head of LNG, Gordon Waters, who joined the firm in July after 18 years at BP.
 
Trading companies, which industry sources say have so far accounted for less than 10 percent of overall LNG trade, could help trigger a more liquid Asian LNG market, with exchanges from Singapore to Tokyo launching indices and futures contracts in preparation. Glencore — which has had a limited presence in LNG up to this point — plans to trade in spot or short-term deals over the next year and double the size of its three-trader team based in Singapore, London and Madrid.
 
First Nation seeks title to island at proposed LNG plant site
 
(Globe and Mail; Canada; Sept. 18) – The Lax Kw’alaams First Nation is seeking aboriginal title to Lelu Island and Flora Bank, creating a legal obstacle for a Malaysian-led consortium that wants to build a liquefied natural gas export terminal near Prince Rupert, B.C. The aboriginal group will file a notice of civil claim to launch the legal action next week in B.C. Supreme Court, Lax Kw’alaams Mayor Garry Reece said Sept. 18.
 
Pacific NorthWest LNG, led by Malaysia’s Petronas, is proposing to construct an LNG export terminal on Lelu Island, and also build a suspension bridge and jetty to a dock for Asia-bound tankers. Pacific NorthWest LNG has offered assurances that the design of marine infrastructure will not harm the environment. But the Lax Kw’alaams believe there would be environmental damage because Flora Bank contains juvenile salmon habitat in eelgrass beds next to the island in the Skeena River estuary.
 
“We want to protect crucial salmon habitat, protect our food security and ensure that governments and industry are obligated to seek our consent,” Reece said. The area is part of the traditional territory of the Allied Tsimshian Tribes of Lax Kw’alaams, and Reece believes that gaining aboriginal title will provide the First Nation with an effective veto over specific aspects of Pacific NorthWest LNG’s proposal. The B.C. government said it respects the right of the Lax Kw’alaams to seek title, while the Prince Rupert Port authority said it is examining the implications of the legal challenge.
 
Petronas will market ‘package deals’ to sell some of its B.C. LNG
 
(Platts; Sept. 15) – Pacific NorthWest LNG will look to sell additional volumes of gas from its planned Prince Rupert, B.C., facility to Asian buyers as part of "package deals,” responding to buyer demand, company president Michael Culbert said Sept. 16. “The Chinese, Japanese and Indian markets are seeking diversity [in supply sources] and Petronas is looking at a portfolio of supplying LNG for 20 to 30 years that will be sourced from Canada besides Australia and other global producers," he said.
 
"A prime advantage of mixing LNG supplies from Canada with other producers will be stability of supply that buyers are demanding," he said on a webcast of the Peters and Co. annual conference in Toronto. Petronas holds 62 percent of the B.C. project that is aiming to start exports in late 2019 or early 2020. Petronas is responsible for marketing the LNG, Culbert said, and already has sold nearly 50 percent of the output under long-term deals with Sinopec, Indian Oil Corp., Japex and Petroleum Brunei.
 
Culbert did not indicate how much LNG that Petronas plans to sell under the package deals, or if negotiations have already started with Asian buyers. Pacific NorthWest LNG is awaiting final clearance from the Canadian Environmental Assessment Agency before taking a final investment decision to build its LNG facility.
 
Asian owned-and-operated LNG plant new to the market
 
(Nikkei Asian Review; Sept. 16) – Companies in East Asia are teaming up to secure cheap, stable supplies of liquefied natural gas. In the process, they are attempting an end-around of the oil giants that dominate the LNG business. One example of how they are trying to do this can be found in Indonesia, where Japanese trading company Mitsubishi and Korea Gas, the world's largest LNG importer, built an LNG plant.
 
The hope is to eventually ease Big Oil's grip on Asia's LNG market. In August, the first shipment of LNG made its way from the new Donggi Senoro plant to an LNG receiving terminal operated by Pertamina, Indonesia's state-owned oil and gas company. This fall, LNG from the Donggi Senoro plant will be shipped to Korea Gas and Japanese electric utilities, said Toru Kawabata, operations director for the joint venture.
 
The new plant in Indonesia — at 2 million metric tons annual capacity — is much smaller than the Middle East's typically gigantic production facilities, though it has huge implications for East Asia's LNG market. It is a wholly Asian enterprise in an industry used to Western oil companies taking the lead in building and operating LNG plants — and its output will stay in Asia. Neither Mitsubishi nor Korea Gas has any experience operating an LNG plant, however, and the team has gotten off to a shaky start. After production began, operating errors have caused emergency shutdowns.
 
 
Major LNG carrier operator says Australia gas could go to Europe
 
(Sydney Morning Herald; Sept. 17) – If Asia doesn't want Australia's liquefied natural gas, Europe will take it, said the CEO of one of the world’s largest independent owner and operator of LNG carriers. Australian LNG producers are seeing growth demand in top-consuming East Asia countries, like China, Korea and Japan, dry up as those economies slow down. That's causing some Australian developers whose projects are due to come online to look elsewhere, said Gary Smith, who heads up Golar LNG.
 
"The only other liquid market that is open to them with the U.S. now closed is Europe," Smith said Sept. 16 at the annual Capital Link Global Commodities Energy & Shipping Forum in New York. "And we've seen it before where cargoes start moving west from Australia instead of east." East Asia nations are not taking a lot of additional supply commitments, with some buyers reselling their cargoes, Smith said. Unless markets in Asia change, Australian LNG is “going to have to go farther to find a home,” he said.
 
European demand for LNG is constant, since the fuel can be used to replace pipeline gas or used by generators to produce electricity, he said.
 
 
U.S. report shows coal losing favor in China
 
(U.S. Energy Information Administration; Sept. 17) – Economic deceleration, industry restructuring and new energy and environmental policies have slowed China’s growth in coal consumption and are also driving more centralized and cleaner uses of coal. After nearly a decade of rapid growth, coal consumption — which currently supplies two-thirds of China's overall energy use — grew only 1 to 2 percent in 2012 and 2013 and was essentially flat in 2014, according to the U.S. Energy Information Administration.
 
Total energy consumption in China has slowed as its economic growth has eased and as the composition of its gross domestic product has shifted. In 2013, the service-sector share of GDP surpassed the industry-sector share for the first time in Chinese history. The service-sector share further increased to 48 percent in 2014. Policies to accelerate the development of service industries are likely to sustain the transition away from industry, further weakening coal consumption, the EIA said in its report.
 
Industry restructuring has reduced China’s energy demand growth from coal-intensive industries such as steel, cement and fertilizer as industry growth slows and processes become more energy efficient. In addition, China's severe air pollution challenges have led to new policies and regulations to restrict coal use in coastal China, to upgrade the nation's coal-fired power generation fleet, and to accelerate the increase of alternative energy technologies.
 
 
Idled oil rigs mean less gas production in U.S.
 
(Bloomberg; Sept. 16) – The retrenchment in drilling for oil in the U.S. is threatening to leave a different market short: natural gas. “The impacts of oil-rig counts extend beyond oil; the outlook for U.S. natural gas is critically dependent on the outcome of this balancing act in U.S. oil rigs,” Anthony Yuen, a strategist at Citigroup in New York, said in a report to clients Sept. 16. “If the oil market remains oversupplied and oil-rig counts fall, the decline in associated gas production would leave the market short of gas.”
 
Associated gas is the gas that comes out of oil wells along with the crude. Supplies of this byproduct from fields including the Bakken formation in North Dakota and the Eagle Ford in Texas may fall by about 1 billion cubic feet a day next year as drillers idle rigs in response to the collapse in oil prices, Yuen said. The U.S. Energy Information Administration has already forecast that shale gas production will drop in October for the fourth straight month, a record streak of declines.
 
Crude producers in the Lower 48 states may have to keep the number of working rigs low for a while longer to balance the global oil market, Yuen said. A premature recovery in the rig count may “exacerbate the current oversupplied environment” and weaken prices, he said. While oil prices have been down, natural gas futures have been lower, too, settling at $2.66 per million Btu on the New York Mercantile Exchange Sept. 16, down 41 percent from June 20, 2014.
 
 
Floating LNG storage, regasification ships gain in popularity
 
(Bloomberg; Sept. 15) – At a time when oil and gas producers are writing down assets and canceling projects worldwide, one niche area is booming. Hybrid ships, called floating storage and regasification units, or FSRUs, offer emerging nations from Egypt to Pakistan a cheaper, quicker way to attack power shortages by importing liquefied natural gas. They cost about $300 million to build, half as much as an onshore import terminal, and are up and running as much as six times faster, sometimes within as little as a year, according to FSRU owners Hoegh LNG Holding and Excelerate Energy.
 
Built at shipyards in South Korea, Hoegh sees as many as 55 such vessels in use within five years, from about 20 now and just one a decade ago. “The main driver is speed,” Sveinung Stohle, Hoegh’s chief executive officer, said by telephone from the company’s Oslo office. “Demand for FSRUs follows a drastic reduction in the cost of LNG. We see that this has caused a very strong increase in requests.”
 
FSRUs are emerging as the fastest alternative for gas imports as nations imposing limits on carbon dioxide emissions turn to cleaner-burning gas. Competition has cut costs of leasing such vessels by 20 percent to about $120,000 per day from five years ago, said Keith Bainbridge, managing director of industry consultant CS LNG in London. Once the 1,000-foot ships are moored, LNG is transferred from arriving tankers through pipes. The LNG is regasified onboard and typically used at a nearby power plant.
 
 
Australia antitrust regulator delays decision on Shell-BG deal
 
(Wall Street Journal; Sept. 17) – Shell’s $70 billion takeover of BG Group has hit a snag after Australia’s antitrust regulator flagged concerns the deal might squeeze domestic supplies of natural gas and drive up prices. The Australian Competition and Consumer Commission said Sept. 17 it would delay a decision on the deal by about two months toNov. 12, after receiving a welter of submissions from businesses worried Shell would curb local supply in favor of more lucrative sales to Asia through BG’s LNG terminal.
 
Shell’s proposed acquisition of BG is, in part, a bet that developing countries will move to cleaner-burning gas amid growing pressure to curb emissions. The regulator’s review of the Shell-BG tie-up has become entwined in a separate study of Australia’s East Coast gas market, which Commission Chairman Rod Sims said is one of the few in the world under the shadow of supply uncertainty despite a global gas production boom.
 
Australia is due to become the world’s biggest producer of liquefied natural gas within two years, as several multibillion-dollar export terminals that began construction when oil and gas prices ran hot start shipping cargoes of LNG to Asia. While that investment holds out the prospect of sharply higher revenues for state and federal governments in Australia, it has also spooked local businesses, which fear paying more for energy as fuel that would have previously fed the domestic market gets shipped overseas.
  
Gas association launches pro-pipeline public awareness campaign
 
(Houston Chronicle; Sept. 14) – Increased domestic production has spurred a need for new pipelines to carry natural gas across the country, but also a wariness by some Americans worried about pipelines snaking through the ground. The Interstate Natural Gas Association of America hopes to combat some of the skepticism by rolling out a new ready-for-social-media campaign with videos, graphics and a website emphasizing that pipelines are a vital energy link for the nation.
 
“If you think about citizens who live near pipelines or in communities where pipelines are proposed to be constructed, they probably don’t know much about natural gas or natural gas pipelines and the tremendous contributions (they) make to overall quality of life,” said Don Santa, CEO of the gas association. With the campaign, INGAA argues that pipelines are the safest method for transporting gas. In addition, gas is better for the environment than the coal it often displaces for power generation.
 
Cathy Landry, an INGAA spokeswoman, said the group is trying to reach “everyday Americans,” including landowners and others in communities affected by pipeline construction — people who may not realize that natural gas is used to generate electricity as well as fuel furnaces. The campaign is being launched as opponents to oil and gas development have focused more attention on pipelines.
  
Analyst forecasts another record year for U.S. gas production
 
(Platts; Sept. 18) – Record levels for production, power burn and storage injection will help make 2015 another record year for natural gas, Jeff Moore, senior energy analyst at Platts unit Bentek Energy, told attendees Sept. 18 at the 38th annual Coal Marketing Days conference in Pittsburgh. Moore said that while coal plant retirements have helped fuel an increase in natural gas generation, the real driver behind in the rise in demand is the commodity's continued low price.
 
With the Henry Hub price staying below $3 per million Btu, natural gas generation is deployed ahead of coal, Moore said. The only time gas demand for power generation was near these levels was in 2012, the year the Henry Hub price dipped to about $2 in May, he said. Bentek sees the price rounding out in 2015 at an average of $2.68 and increasing to $2.84 in 2016. From 2017 to 2020, Bentek expects the price to average $3.38, $3.85, $4.23 and $4.42, respectively.
 
Efficiencies in horizontal drilling and a drastic increase in the initial production rate from wells in the Marcellus and Utica shales will push gas production to a new high in 2015, Moore said. Total U.S. marketed gas production is averaging 72 billion to 72.5 billion cubic feet per day this year but will ramp up to near 74 bcf by the end of 2015, Moore said. Gas inventory levels are predicted at an all-time high at the end of the year, but the volumes depend on winter weather.
  
U.S. oil production finally starts trending lower
 
(EnergyWire; Sept. 17) – U.S. crude oil production is finally starting to decline, according to statistics and experts. After months of production increases — even in the midst of falling oil prices — total output volumes have been trending downward as production growth in some areas is being outpaced by declines in major shale oil regions. The trend appears to be holding.
 
Earlier, it had been difficult to tell whether output declines represented a steady trend or the occasional variance seen month to month. Output continues to expand in the Permian Basin of west Texas and southeastern New Mexico and in federal waters in the Gulf of Mexico. But declines in the North Dakota Bakken Shale, in south Texas' Eagle Ford Shale and from other fields appear to be outpacing growth elsewhere.
 
"There is evidence now that production from the shale plays is declining, not at a rapid rate, but I just recently saw some data for the Eagle Ford and the Bakken which do show production declines over the last couple of weeks," said Bernard Weinstein, director at the Maguire Energy Institute at Southern Methodist University. The U.S. Energy Information Administration sees a gradual decline continuing for the next year, with U.S. oil production forecast to reach 8.63 million barrels a day in August 2016, a drop of nearly 1 million barrels per day from the April 2015 high-water mark.
   
Low oil prices may cut into production as companies run out of cash
 
(Bloomberg; Sept. 17) – As much as 400,000 barrels a day of oil production is at risk as U.S. shale companies like Samson Resources run out of money and are forced to slow drilling. Total debt for half of the companies in a Bloomberg index of more than 60 producers has risen to a level that represents 40 percent of their enterprise value. It’s a sign of distress that shows equity values falling in the face of oil’s crash, said Rob Thummel, a managing director and portfolio manager at Tortoise Capital Advisors.
 
The companies facing high debt loads, which include Encana and Chesapeake Energy, produced 1.1 million barrels a day in the second quarter of this year, according to data compiled by Bloomberg. If more companies file for bankruptcy as Samson did Sept. 16, or embrace the kinds of draconian cuts needed to survive, output could fall by 200,000 to 400,000 barrels, Thummel said. A loss of that much crude would be the steepest U.S. decline since 1989 — about the same as Oklahoma, the sixth-largest producing state.
 
“We are going to see a major response because these financially challenged companies won’t be able to produce as much as they did in the past,” he said. As companies run short on cash from low oil prices, they may be forced to idle drilling rigs, file bankruptcy or seek more expensive financing and sell assets. In the past year, U.S. oil producers used 83 percent of their operating cash flow to pay for debt service, according to the U.S. Energy Information Administration. A year earlier, it was less than 60 percent.