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Karhu-er
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Seems wasteful.
Seems wasteful.
Seems wasteful.
NYMEX natural gas traded over $6.15/Mcf today.
Are natural gas prices reverting to their long-run historical relationship to petroleum prices?
On a strictly BTU-equivalency, NYMEX natural gas should be priced at a roughly 1:6 ratio to petroleum. On average, over the last twenty-four-odd years, NYMEX natural gas has been priced at ~1/12th of the WTI price.
http://alfred.stlouisfed.org/alfredgraph.png?g=sho
This has been the coldest Dec Feb period in over 30 years. The price is just a reflection of low storage inventories and fear of a cold 2nd half of Feb and Mar.
We have a cool summer, and a warmish fall and winter next year and the price will tank.
The path toward U.S. energy independence, made possible by a boom in shale oil, will be much harder than it seems.
Just a few of the roadblocks: Independent producers will spend $1.50 drilling this year for every dollar they get back. Shale output drops faster than production from conventional methods. It will take 2,500 new wells a year just to sustain output of 1 million barrels a day in North Dakota’s Bakken shale, according to the Paris-based International Energy Agency. Iraq could do the same with 60.
Consider Sanchez Energy Corp. The Houston-based company plans to spend as much as $600 million this year, almost double its estimated 2013 revenue, on the Eagle Ford shale formation in south Texas, which along with North Dakota is one of the hotbeds of a drilling frenzy that’s pushed U.S. crude output to the highest in almost 26 years. Its Sante North 1H oil well pumped five times more water than crude, Sanchez Energy said in a Feb. 17 regulatory filing. Shares sank 7 percent.
Rethinking the Ban on Exporting U.S. Oil
“We are beginning to live in a different world where getting more oil takes more energy, more effort and will be more expensive,” said Tad Patzek, chairman of the Department of Petroleum and Geosystems Engineering at the University of Texas at Austin.
Drillers are pushing to maintain the pace of the unprecedented 39 percent gain in U.S. oil production since the end of 2011. Yet achieving U.S. energy self-sufficiency depends on easy credit and oil prices high enough to cover well costs. Even with crude above $100 a barrel, shale producers are spending money faster than they make it.
Missed Forecasts
Companies are showing the strain. Chesapeake Energy Corp., the Oklahoma City-based company founded by Aubrey McClendon, reported profit yesterday that missed analysts’ forecasts by the widest margin in almost two years. Shares declined 4.9 percent. Fort Worth, Texas-based Range Resources Corp. fell 2.3 percent after announcing Feb. 25 that fourth-quarter profit dropped 47 percent. QEP Resources Inc., a Denver-based driller, slid 10 percent after fourth-quarter earnings reported Feb. 25 fell short of analysts’ predictions.
The U.S. oil industry must sprint simply to stay in place. U.S. drillers are expected to spend more than $2.8 trillion by 2035 even though production will peak a decade earlier, the IEA said. The Middle East will spend less than a third of that for three times more crude.
Bulls Crow
Shale wells can vary in price. Chesapeake will spend an average of $6.4 million each this year, according an investor presentation last updated yesterday. Houston-based Goodrich Petroleum Corp. will spend up to $13 million on some of its wells, Robert Turnham, president and chief operating officer, said in a Feb. 20 earnings call.
Bullish analysts and oil executives have reason to crow. While drilling in Iraq could break even at about $20 a barrel, output will be limited by political risks, Ed Morse, global head of commodities research at Citigroup Inc. in New York, said in a January report. By contrast, the break-even price in U.S. shale is estimated at $60 to $80 a barrel, according to the IEA. The price of a barrel hasn’t dipped below $80 since 2012 and has stayed above $90 since May. Costs in the U.S. will continue to fall as drillers get faster and improve results, Morse said.
Crude Exports
“The U.S. oil and natural gas renaissance is receiving significant investment because return on investment is good and competitive with other opportunities,” Rick Bott, president and chief operating officer of Oklahoma City-based Continental Resources Inc., a pioneer of shale drilling, said in an e-mail. “We’re confident that continued technological advancements will keep the Bakken and other plays at the forefront of investment for the foreseeable future.”
Harold Hamm, the chairman and chief executive officer of Continental Resources who became a billionaire drilling in North Dakota, told U.S. lawmakers Jan. 30 that the country, which U.S. Energy Information Administration data show supplied 86 percent of its own energy last year, can drill its way to energy independence by 2020. Hamm is leading an effort to get Congress to allow crude exports for the first time since the 1970s.
U.S. oil production will average 9.2 million barrels a day in 2015, up from 7.4 million last year, according to the EIA, the statistical arm of the U.S. Energy Department. Colorado boosted output by 11 percent in the first 11 months of last year, Wyoming was up 12 percent and Oklahoma added 24 percent.
“I don’t see the shale boom coming to an end,” said Andy Lipow, president of Lipow Oil Associates, an energy consulting firm in Houston. “We’re just getting started in places like Colorado, Wyoming and Oklahoma.”
Horizontal Wells
Sanchez Energy said in a Feb. 19 statement that Sante North 1H isn’t yet finished and the well will produce more oil than the early report suggested. The company said it has 120,000 acres in the Eagle Ford and plans to spend 90 percent of its exploration budget there this year. The company’s shares have risen 63 percent in the past year.
Traditional wells are bored straight down, like straws stuck into large deposits of crude. Shale is tapped by steering the drill horizontally through layers of oil-rich rock, sometimes for a mile or more. The formation is blasted apart with a high-pressure jet of water, sand and chemicals, a practice called hydraulic fracturing or fracking, to open up cracks that free pockets of trapped fuel. The complexity and materials needed to drill horizontally and blast the rock add to the cost.
Yield Little
The boom’s boosters have given rise to the misconception that wringing oil and gas from shale can be easily replicated throughout the country, Patzek said. That isn’t the case, he said. Every rock is different. The Bakken shale, along with the neighboring Three Forks formation, covers an area larger than France, according to the IEA. An oil-bearing formation that’s 400 feet (122 meters) thick in one spot may taper off to nothing just a mile away, Patzek said. What works for one well may yield little in a neighboring county.
The output of shale wells drops faster, too, falling by 60 to 70 percent in the first year alone, according to Austin, Texas-based Drillinginfo Inc. Traditional wells take two years to fall by about 55 percent before flattening out. That forces companies to keep drilling new wells to make up for lost productivity.
“You keep having to drill more and you keep having to spend more,” said Mark Young, an analyst with London-based Evaluate Energy, which tracks production and its costs.
Sweet Spots
A prolonged slide in prices below $85 a barrel may put pressure on operators that have struggled to contain costs or that don’t own acreage in the prolific “sweet spots” of the oil fields, said Leonardo Maugeri, a former manager at Rome-based energy company Eni SpA who’s researching the geopolitics of energy at Harvard University’s Belfer Center for Science and International Affairs.
Companies have boosted well productivity and will continue to whittle down the break-even price, he said. While the boom could survive a brief dip in oil prices, a long slump could slow drilling and cause production to fall swiftly, Maugeri said.
“To sustain in the short term, the U.S. needs prices at $65 a barrel,” Maugeri said. “That’s a critical level. Below that level, many opportunities will vanish.”
The U.S. benchmark oil contract for West Texas Intermediate crude for delivery in April 2016 is trading at about $85 a barrel, almost $18 a barrel less than today and still $20 above Maugeri’s threshold.
Net Debt
Even with crude prices above $100 a barrel, U.S. independent producers will spend $1.50 drilling this year for every dollar they get back from selling oil and gas and will carry debt that is twice as much as annual earnings, said Ryan Oatman, an energy analyst with SunTrust Robinson Humphrey Inc., an investment bank in Houston.
By contrast, the net debt of Exxon Mobil Corp., the world’s largest energy explorer by market value, is less than half of the cash earned from operations last year. The company will spend 68 cents for every dollar it gets back this year, according to company records and analyst forecasts compiled by Bloomberg.
So far, oil prices have been high enough to keep investors interested in the potential profits to be made in shale, Oatman said.
“There is a point at which investors become worried about debt levels and how that spending is going to be financed,” Oatman said. “How do you accelerate and drill without making investors worried about the balance sheet? That’s the key tension in this industry.”
http://www.bloomberg.com/news/2014-...l-independence-slams-against-shale-costs.html
The oil industry is pressuring President Barack Obama to end the 41-year-old ban on most crude exports. BP Plc isn’t waiting for a decision.
The British oil giant has signed on to take at least 80 percent of the capacity of a new $360 million mini-refinery in Houston that will process crude just enough to escape restrictions on sales outside the country.
Amid a flood of new U.S. oil, the demand for simple, one-step plants capable of transforming raw crude into exportable products such as propane is feeding a construction boom along the Gulf Coast. If the new processing units continue to multiply, they could render moot the politically sensitive debate over whether to ease the restrictions in place since the Arab oil embargo of 1973.
“It’s a relatively inexpensive way around the export prohibition,” said Judith Dwarkin, chief energy economist for ITG Investment Research Inc. “You can lightly ruffle the hydrocarbons and they are considered processed and then they aren’t subject to the ban.”
Rethinking the Ban on Exporting U.S. Oil
BP and other producers will also be able to sell the lightly refined products to a variety of domestic markets.
The first of the units, built by Kinder Morgan Energy Partners LP for use by BP, is scheduled to come online in July. Three additional plants have been proposed by other pipeline or trading companies, and refiners including Valero (VLO) Energy Corp. and Phillips 66 said they may follow suit. The plants, built for 1/10 the cost of a complex, full-scale refinery, take advantage of the law that allows products refined from oil to be sold overseas, though not the raw crude itself without rarely granted government permission.
Gasoline Prices
Supporters of the export ban say keeping U.S.-produced oil at home helps lower fuel prices for industry and consumers. Building enough mini-refineries designed for export could have the opposite effect, said Daniel Weiss, a senior fellow at the Center for American Progress, which supports the limits.
“It could be a way of getting around the oil ban and therefore could have an impact on the price at the pump,” he said.
Kinder Morgan, run by billionaire Chief Executive officer Richard Kinder, expects to open the first phase of its 100,000 barrel-a-day crude processing plant in July, located along the Houston Ship Channel. BP has signed a 10-year contract to use the facility, which is designed for further expansion.
“The export of refined products is increasingly in vogue,” Rich Kinder told analysts on a Jan. 15 conference call for the Houston-based company. “We’ll be able to continue to benefit from what we see is a significant trend.”
Creating Value
Kinder Morgan’s plant is designed to help BP in “creating more valuable products or getting to where we could export,” said Ronald McClain, the company’s president of products pipelines.
“BP complies with all federal regulations regarding imports and exports,” Scott Dean, a spokesman for BP, said in an e-mail response...
...[Kinder Morgan] has the ability on its pipeline network to sell products from the Kinder Morgan plant both inside the U.S. and for export. BP lost its access to Gulf Coast markets when it sold its 450,000 barrel-a-day refinery in Texas City, Texas, to Marathon Petroleum Corp. last year. The new plant can help the company serve some of those customers.
For producers such as BP and ConocoPhillips, the plants help solve one of the more vexing challenges of newly abundant oil in the U.S.: the more they produce, the cheaper it gets. That’s because of energy policies that prevent them from selling their crude to overseas markets, while applying no such limits to products that are processed in refineries, such as gasoline or diesel.
Oil Glut
The result is that refiners so far have reaped the greatest rewards of the U.S. oil renaissance, exporting record amounts of gasoline while the drillers who created the boom have been forced to contend with a glut of unrefined oil and depressed prices. New discoveries and advanced drilling techniques helped produce more than 1 million barrels last year of a purer, lightweight oil that’s closer to gasoline than darker, heavier crudes. Production of the light oil, known as condensate, doubled from 2011, according to RBN Energy LLC.
The glut, in turn, is leading producers to turn to the new plants, called splitters because they split off gassy molecules in a distillation process that is far less complex than that of a typical refinery. The tower-like facilities can turn the condensate into liquid fuels such as kerosene, propane, butane, and naphtha, an ingredient in gasoline.
Refiners including Valero and pipeline operators including Magellan Midstream Partners LP have so far discussed plans for a dozen such plants, with the total potential to process more than 460,000 barrels of condensate a day -- almost half last year’s production, according to a Feb. 5 note from analysts at RBC Capital Markets led by Leo Mariani.
“The international buyers of these products will likely need to refine them further, so this is basically a veiled form of condensate exports,” wrote Mariani, who’s based in Austin, Texas.
http://www.bloomberg.com/news/2014-03-06/bp-splitter-refinery-seen-skirting-u-s-oil-export-ban.html
Saudi Arabia named Prince Muqrin bin Abdulaziz as second in line to the throne, the latest royal promotion as King Abdullah confronts unprecedented political instability in the Middle East and economic changes at home.
Muqrin, the king’s half-brother who was born in 1945, was made second crown prince alongside his duties as second deputy prime minister, the official Saudi Press Agency said yesterday, citing a royal decree. King Abdullah named his defense minister and half-brother Prince Salman bin Abdulaziz, born in 1935, crown prince in June 2012, making the traditionalist former governor of Riyadh next in line to become king.
“By many accounts, Prince Muqrin is a close and trusted adviser to King Abdullah,” said Fahad Nazer, a political analyst at Vienna, Virginia-based JTG, and a former official at the Saudi embassy in Washington. “His relative youth, extensive experience in government and knowledge of the West make him an attractive candidate. He appears to be a generally popular figure among many Saudis, whereas other royals may be more polarizing.”
The appointment came hours before U.S. President Barack Obama was due to arrive in the kingdom for talks with King Abdullah. The two are expected to discuss U.S. support for Gulf security, Iran, Syria and Israeli-Palestinian peace talks, Deputy National Security Adviser Ben Rhodes said at a March 21 briefing.
Obama Visit
Saudi rulers have criticized the U.S. decision to abandon plans for military action against Syrian President Bashar al-Assad.
King Abdullah, who was born in 1924, has promoted a younger generation of royals to govern the world’s largest oil exporter. In May last year he named his son Prince Miteb bin Abdullah as minister of the National Guard. In December he appointed another son, Prince Meshaal bin Abdullah, to run Mecca province.
Yesterday’s move aims “to provide a bridge between generations, so that Miteb can become crown prince at a future date,” said Theodore Karasik, director of research at the Institute for Near East and Gulf Military Analysis in Dubai.
The decree set out details of the possible succession. Muqrin will be appointed as first crown prince if that position becomes vacant, it stated. He will become king if both that post and the position of first crown prince are unfilled at the same time. The decree “may not be modified or changed in any way or form by any person whoever it may be,” it said.
‘National Cohesion’
The appointment heightened “unity and national cohesion” and reflected the extent of understanding among members of the royal family, Justice Minister Mohammed Bin Abdulkareem Al-Issa said, the official Saudi Press Agency reported late yesterday.
In February last year, Muqrin was appointed second deputy prime minister, and was the second member of the royal family to be named to that position by King Abdullah since the monarch came to power in 2005. The second deputy prime minister is usually next in line to become crown prince, pending approval by the Allegiance Council.
Six kings have ruled since the kingdom’s formation in 1932.
Muqrin was educated in Britain and the U.S. He is a former air force officer who has served as governor of the regions of Hail and Medina, and has managed the kingdom relation’s with Afghanistan and Pakistan.
“Muqrin, the youngest living son of the founder of Saudi Arabia, looks like the quintessential Saudi political operator,” said Paul Sullivan, a Middle East specialist at Georgetown University in Washington. “He did his bit in the military and has some credentials from the U.S. and the U.K. for some external flair.”
The 1992 basic law stipulates the king must be a male descendant of the kingdom’s founder, King Abdulaziz Al Saud. King Abdullah, who came to the throne in 2005, is his 13th son.
http://www.bloomberg.com/news/2014-...nts-prince-muqrin-as-second-crown-prince.html
Jan Arps is the most influential oilman you’ve never heard of.
In 1945, Arps, then a 33-year-old petroleum engineer for British-American Oil Producing Co., published a formula to predict how much crude a well will produce and when it will run dry. The Arps method has become one of the most widely used measures in the industry. Companies rely on it to predict the profitability of drilling, secure loans and report reserves to regulators. When Representative Ed Royce, a California Republican, said at a March 26 hearing in Washington that the U.S. should start exporting its oil to undermine Russian influence, his forecast of “increasing U.S. energy production” can be traced back to Arps.
The problem is the Arps equation has been twisted to apply to shale technology, which didn’t exist when Arps died in 1976. John Lee, a University of Houston engineering professor and an authority on estimating reserves, said billions of barrels of untapped shale oil in the U.S. are counted by companies relying on limited drilling history and tweaks to Arps’s formula that exaggerate future production. That casts doubt on how close the U.S. will get to energy independence, a goal that’s nearer than at any time since 1985, according to data from the U.S. Energy Information Administration.
“Things could turn out more pessimistic than people project,” said Lee. “The long-term production of some of those oil-rich wells may be overstated.”
Calculate Reserves
Lee’s criticisms have opened a rift in the industry about how to measure the stores of crude trapped within rock formations thousands of feet below the earth’s surface. In a newsletter published this year by Houston-based Ryder Scott Co., which helps drillers calculate reserves, Lee called for an industry conference to address what he said are inconsistent approaches. The Arps method is particularly open to abuse, he said.
U.S. oil production has increased 40 percent since the end of 2011 as drillers target layers of oil-bearing rock such as the Bakken shale in North Dakota, the Eagle Ford in Texas, and the Mississippi Lime in Kansas and Oklahoma, according to the EIA. The U.S. is on track to become the world’s largest oil producer by next year, according to the Paris-based International Energy Agency. A report from London-based consultants Wood Mackenzie said that by 2020 the Bakken’s output alone will be 1.7 million barrels a day, from 1.1 million now.
U.S. crude benchmark West Texas Intermediate fell 41 cents to $99.21 a barrel at 10:10 a.m London time in electronic trading on the New York Mercantile Exchange. It has risen 0.8 percent this year.
Inherently Uncertain
Predicting the future is an inherently uncertain business, and Arps’s method works as well as any other, said Scott Wilson, a senior vice president in Ryder Scott’s Denver office.
“No one method does it right every time,” Wilson said. “Arps is just a tool. If you blame Arps because a forecast turns out to be wrong, that’s like blaming the gun for shooting somebody. As far as Arps being old, the wheel was invented a long time ago too but it still comes in handy.”
Rising reserve estimates gives the U.S. a false sense of security, said Tad Patzek, chairman of the Department of Petroleum and Geosystems Engineering at the University of Texas at Austin.
“We have deceived ourselves into thinking that since we have an infinite resource, we don’t need to worry,” Patzek said. “We are stumbling like blind people into a future which is not as pretty as we think.”
The Arps formula is only as good as the assumptions a company puts into it, Patzek said. Estimates can be inflated when Arps is based on limited drilling history for data or on a few high-performing wells to predict performance across a wide swath of acreage. Forecasts can also be skewed higher by assuming slower production declines than Arps observed.
Reserves Cut
In November 2012, SandRidge Energy Inc. cut its reserve predictions to the equivalent of 422,000 barrels per well from 456,000. Five months later, the estimate was cut again, to 369,000 barrels, company records show. Oklahoma City-based SandRidge has since made an adjustment upward to 380,000 barrels per well.
The early, more optimistic forecasts were based on a small number of high-performing wells, which led the company to overestimate performance for its other acreage, said Duane Grubert, SandRidge’s executive vice president for investor relations and strategy. The company now has more than 1,100 wells and has improved its drilling. It is confident that current estimates are reliable, Grubert said.
“Nobody knew that until we actually ground-truthed the field by drilling it,” Grubert said. “What we came up was, hmm, that initial estimate was a little high.”
Future Production
SM Energy Co., a Denver-based producer, suffered a similar setback this year when its wells in the Eagle Ford shale in Texas fell short of forecasts. The company on Feb. 18 cut its prediction in one area to the equivalent of 475,000 barrels per well from 602,000. Estimating future production from early data is a challenge for the industry, said Brent Collins, a spokesman for SM Energy.
“This is especially true when you are trying to estimate an average from a limited number of wells,” Collins said.
Both SandRidge and SM Energy use variations of the Arps method, company records show.
Tapping shale formations differs from the drilling in Arps’ day, said Dean Rietz, an executive vice president in charge of reservoir simulation at Ryder Scott. The first commercial shale well was drilled in 2004, 59 years after Arps published his method.
Gas Pockets
In 1945, oil production meant drilling straight down to hit pockets of oil and gas that had become trapped after migrating upward from deep layers of rock. Today’s drilling targets those deep layers, boring through thousands of feet of the earth’s crust, then turning sideways to chew for a mile or more through layers that are harder and less porous than a granite countertop. The rock is shattered by a high-pressure jet of water, sand, and chemicals to create a network of small cracks to allow the oil and gas to escape. The largest fissures are narrower than the width of a paper clip. The smallest are thousands of times thinner than a human hair.
On a graph, these fractured wells appear to follow a different trajectory of decline than the conventional wells Arps studied, said Lee.
To replace the Arps calculation, researchers are testing new formulas with names worthy of indie bands: Stretched Exponential, which Lee helped develop; the Duong Method, devised by Anh Duong, principal reservoir engineer for ConocoPhillips; and Simple Scaling Theory, which the University of Texas’s Patzek worked on.
Rietz has made a well simulation model to predict production.
“Come back to me in 10 years, and I’ll tell you how reliable it was,” he said.
http://www.bloomberg.com/news/2014-...ubt-on-accuracy-of-oil-reserve-estimates.html
U.S. proved reserves of crude oil and lease condensate reached the highest level in 36 years as new technology and high prices made supplies locked in shale formations available.
Reserves increased 4.5 billion barrels to 33.4 billion in 2012, the most since 1976 and the biggest annual gain since 1970, the Energy Information Administration said today in its annual U.S. Crude Oil and Natural Gas Proved Reserves report. Oil deposits in shale rock, also known as “tight oil” formations, more than doubled from a year earlier.
Proved reserves, or resources that can be recovered under existing economic and operating conditions, grew as a combination of horizontal drilling and hydraulic fracturing, or fracking, unlocked tight oil and as crude prices that averaged more than $90 a barrel made drilling profitable. Increasing domestic resources, still small compared with countries like Saudi Arabia and Venezuela, have reduced the U.S.’s reliance on foreign oil.
“As our ability to get oil out of the ground improves and as prices stay high, more and more oil becomes available and moves into the category of proved reserves,” said Julius Walker, a global energy markets strategist at UBS Securities LLC in New York. “It’s just another manifestation of what the shale-oil revolution means. I expect this trend to continue.”
Estimate Uncertainty
Shale drilling, however, poses difficulties when it comes to accurate measurement of how much oil lurks beneath hundreds of feet of rock, according to John Lee, a University of Houston engineering professor. The same methods used for decades to estimate the reserves available to traditional vertical wells is sometimes misapplied to the horizontal wells used to tap shale. The shale wells accounted for about 35 percent of U.S. production in 2012, according the EIA.
Proved reserves climbed 15 percent in 2012 from 29 billion barrels in 2011, the EIA, the Energy Department’s statistical arm, said. Lease condensate, consisting primarily of hydrocarbons recovered as a liquid from natural gas, accounted for 8.6 percent of the total in 2012.
Tight oil reserves jumped to 7.34 billion barrels, or 22 percent of the total, in 2012 from 3.63 billion in 2011. Deposits in the Eagle Ford shale formation in Texas jumped to 3.37 billion from 1.25 billion, and those in the Bakken in North Dakota, South Dakota and Montana grew to 3.17 billion from 2 billion. Eagle Ford surpassed Bakken to become the biggest tight-oil play in the U.S.
‘New Peak’
“A new peak is arising because of this new source of previously bypassed oil,” said Steven Grape, the petroleum engineer at the EIA who wrote the report. “Texas and North Dakota for the past few years were the drivers for the gains.”
The government’s annual estimates of proved reserves are based on survey responses from about 1,100 domestic operators of oil and gas wells, according to the EIA.
U.S. crude-oil imports declined to 7.19 million barrels a day in the four weeks ended March 14, the lowest level since January 1997, the EIA previously reported. The U.S. met 87 percent of its energy needs in 2013, the highest level since 1985, agency data show.
Rising reserves “add to the view that the U.S. is moving toward being a lot less import-dependent,” Walker said. “The thing about reserves is that it’s not just a question of knowing where the oil is, it’s also a function of prices and technology.”
Oil Price
West Texas Intermediate crude, the U.S. benchmark, averaged $94.15 in 2012. The annual average has topped $90 a barrel for the past three years. Futures slipped 20 cents to $103.40 today and have averaged $98.93 this year.
“Proved reserves are very much dependent on prices,” Grape said. “If prices go up, proved reserves can actually increase. With higher prices, you can keep drilling and still make a lot of money.”
Oil reserves in the U.S. are still dwarfed by Venezuela, which held the most in the world with 297.6 billion barrels as of 2012, according to BP Plc’s Statistical Review of World Energy. Saudi Arabia, the U.S.’s second-biggest foreign oil source in 2013 after Canada, held 265.9 billion. Canada had 173.9 billion.
U.S. reserves may continue to rise “for a while” and then will plateau, Grape said.
“We have to keep drilling in order to maintain what just we’ve already got,” he said. “There comes a limit as to how many pipes you can put in the ground to get the oil out.”
http://www.bloomberg.com/news/2014-04-10/u-s-proved-crude-reserves-reach-36-year-high.html
Once again, Ukraine is turning to Europe and the International Monetary Fund for assistance, this time a $15 billion bailout. For years, negotiations with the IMF had stalled over a single point: Ukraine spends 7 percent of its gross domestic product on natural gas subsidies for consumers. The IMF wants that cut by a third before approving any loans.
Violetta Viktorova, a doctor in Kiev, says if the IMF gets what it wants, the utility fees she and her husband pay will go up. “We live from paycheck to paycheck. The rise in price would hurt us,” she says, though not as much as it would the country’s pensioners. Ukraine is balking at the IMF’s request.
In the developing world, it’s tempting for a country to keep the price of fossil fuels artificially low. The subsidy can take the form of a price cap, preventing oil companies from charging too much at the pump. Or it can come as a tax break to a domestic oil producer, which then usually passes on the savings. In both cases, the government has to make up the difference.
Subsidies usually start as an attempt to avoid inflation and shield citizens from the pain of price increases in global energy markets. But energy subsidies are expensive; they eat up national budgets. Benefits end up going mostly to the richest citizens and crowd out more productive government spending on education or infrastructure and reduce energy efficiency. Subsidies mess with the law of supply and demand, discouraging investment in both alternative energy and fossil fuel exploration.
“It’s a failed policy,” says Fatih Birol, chief economist for the International Energy Agency (IEA), “but we see that many countries continue to follow it.” Subsidies endure because, as Ukraine’s politicians know, getting rid of one means immediate pain for citizens, a drop in popular support, and sometimes even civil unrest.
The IMF pegged government support worldwide for petroleum products, electricity, natural gas, and coal at $1.9 trillion, or 2.5 percent of global GDP in 2011. This number includes the costs of damage done by subsidized fuel to public health, the environment, and infrastructure; subtract those costs, and countries still pay $480 billion a year for subsidies, or 0.7 percent of global GDP. The spending is concentrated mostly in the Middle East, Asia, Central Europe, and the countries of the former Soviet Union. The world’s heaviest subsidizer of natural gas, at 26 percent of GDP, is Uzbekistan. Venezuela supports domestic petroleum prices at about 8 percent, Iraq at 14 percent. The U.S., the biggest subsidizer in the developed world after Luxembourg, supports gas and diesel at 2 percent.
The struggle to hold on to fuel subsidies intensified as energy prices rose in the mid-2000s. Developing economies increased their subsidies to keep pace with world prices. In Ukraine, subsidies rose when Russia started charging more in what are now called the gas wars of 2004 and 2009. Since 2007, when the IEA began tracking subsidies, they’ve risen 40 percent in Ukraine. Assessing this troubling trend, the IMF, the World Bank, and the IEA have made cutting subsidies a priority worldwide.
Governments like to describe fuel subsidies as social programs. But the bulk of the assistance doesn’t reach the poor. The IMF says 61 percent of the benefit of gasoline subsidies goes to the richest 20 percent of citizens, who own cars; the number is slightly lower for diesel and natural gas. “The poor go hungry if they miss a day of work,” says Ramadan Mohamed, an apple peddler in Cairo, “and yet the rich enjoy access to subsidies.” Egypt spends 9 percent of GDP to keep gasoline prices low. He says it would be better to spend that money on health care and education—pretty much what the IMF and the World Bank believe. “There’s so much that the poor need,” Mohamed says.
Fuel subsidies also reduce efficiency, says the IEA’s Birol. According to the World Bank, energy intensity, a measure of the amount of energy used per $1,000 of GDP, is twice as high in Ukraine as it is in Latvia or Estonia, post-Soviet economies that have slashed their subsidies. “If something is much cheaper, we humans tend to use it in a wasteful manner,” Birol says. He points to electricity plants in North Africa and the Middle East that are powered by subsidized gasoline, an extravagance when natural gas is the logical choice. “To use oil for electricity is absolutely very uneconomic,” he says. “It’s like using Chanel perfume to fuel your car.”
Price supports for oil and gas suppress investment in both oil exploration and alternative energy. Brazil, which had successfully reduced gasoline subsidies in the 1990s, reintroduced them in 2011 when inflation resurfaced, stoked in part by rising fuel prices. Petrobras (PBR), the state-run oil company, has had to buy gasoline abroad and sell it domestically at a 15 percent discount. The gasoline purchases are causing losses that make it difficult for the company to develop its new offshore oil finds. And the policy has made it harder for Brazil’s ethanol producers to compete. Investments in new ethanol production have fallen since their peak in 2008. The policy “needs to end,” says Adriano Pires, director of the Brazilian Center for Infrastructure, a think tank. “It’s causing many more problems than solutions.”
Consumers, who are also voters, usually see only the benefits of subsidies, making them hard to kill for politicians. Last year the IMF produced a list of energy subsidy reforms by country since the 1990s. Of 22 attempts, the fund deemed 12 successful. Nigeria in 2012 dropped its gasoline subsidy from 4.7 percent of GDP to 3.6 percent. The IMF labels this a partial success; the original plan, to remove subsidies altogether, sent millions into the street in a weeklong general strike.
Both the IMF and the IEA recommend the same basic steps to shed subsidies. Countries should stop hiding the costs of subsidies from their citizens. Both Brazil and Ukraine bury theirs in the accounts of state-owned utilities. Include subsidies as a line-item cost in the budget, Birol says, so citizens understand they’re being charged for a bad policy. The IMF also suggests identifying who will be hurt by a subsidy cut and finding a way to make the transition easier for them. Perversely, though energy subsidies often help the poor the least, removing them hurts the poor the most—a small loss makes a bigger difference on a tight budget.
A 2013 IMF report pointed to Iran’s 2010 fuel subsidy reform as a model. The country ran a public information campaign to explain both the policy change and the schedule for phasing it in, and converted the subsidy to cash transfers directly to citizens. Cash does not warp energy prices as subsidies do.
In Kiev, Violetta Viktorova says she hopes that if the government lowers gas subsidies it will raise salaries to make up the difference. Or at least that a new legal environment could discourage corruption. “If you could really put something in and get something out as a result,” she says, “then we would be willing to pay the price for it.”
http://www.businessweek.com/article...-developing-nations-are-an-economic-addiction
Shale rock underneath some of the wealthiest counties in southern England may contain billions of barrels of oil, a government report said.
The Weald basin, covering counties south of London including Surrey and Sussex, may have oil in place of as much as 8.6 billion barrels, according to a report by the British Geological Survey published today. It didn’t say how much could be extracted profitably. The U.K.’s current extractable oil reserves stand at 3.1 billion barrels, according to BP Plc.
The report is likely to add to the controversy about drilling for shale oil and gas in the U.K. The government wants to develop the resources to cut energy costs and boost the economy. Opponents say the process of hydraulic fracturing used to drill shale can damage the environment.
Last year, the BGS said the Bowland basin, which extends across east and northwest England, may hold as much as 1,300 trillion cubic feet of gas. That’s enough to meet demand for almost half a century with extraction rates similar to U.S. fields, according to Bloomberg calculations.
The U.K. government has offered tax breaks to drillers to stimulate the shale industry amid rising fuel imports and declining reserves from the North Sea, which has yielded about 42 billion barrels since the 1970s.
The likely range of shale oil in place in the Weald basin is 2.2 billion to 8.6 billion, the BGS report said.
The government said today it plans to “simplify” access to property for the shale and geothermal industries.
“The new proposals would simplify procedures which are costly, time-consuming, and disproportionate for new methods of underground drilling,” the Department of Energy and Climate Change said in an e-mailed statement. “Oil, gas and deep geothermal companies will be able to explore their potential, and will in return provide a voluntary community payment for access.”
http://www.bloomberg.com/news/2014-...d-holds-billions-of-barrels-of-shale-oil.html
Petroleo Brasileiro SA’s chances of meeting output targets for the first time in a decade are fading as a rush to dispatch new oil platforms creates headaches miles offshore.
A floating hotel anchored last month at its P-62 platform symbolizes the state-run producer’s predicament. The so-called floatel is housing hundreds of workers sent to fix the new unit that’s already months behind schedule after a fire and emergency maintenance. Other new platforms at the Roncador, Sapinhoa and Lula Nordeste fields have reported safety breaches and equipment delays from suppliers, slowing the output ramp-up.
Petrobras, as the top producer in waters deeper than 1,000 feet is known, is relying on platforms like P-62 to tap vast offshore deposits after missing output targets for 10 straight years. Last year, it said production would start increasing in the fourth quarter as nine new platforms added a million barrels a day capacity. Through June, it’s up 1.4 percent compared with a 7.5 percent annual growth target.
“We are less optimistic with Petrobras’s production growth this year,” Auro Rozenbaum, an analyst at the investment banking unit of Banco Bradesco SA, said by telephone from Sao Paulo. “It failed to boost output in the first four months of the year due to maintenance and equipment delays, making the target less reachable.”
Stock Rally
Petrobras said in an e-mailed reply to questions that 33 new wells will be connected in the second half at P-62 and sister platform P-55, each with the capacity to lift 180,000 barrels a day. The company is sticking with its growth target.
“New production systems will go on stream in 2014 to ensure sustained growth, as outlined in Petrobras’ 2014-2018 Business and Management Plan, which has set a 7.5 percent rise by the end of 2014, with a margin of tolerance of one percentage point upwards or downwards,” according to the Rio de Janeiro-based company’s May output report.
Petrobras, the worst performing stock in the past five years among 15 peers tracked by Bloomberg, has rallied 14 percent this year through yesterday, more than double the 6.2 percent average gain among peers. Brent crude has lost 4.9 percent in 2014.
The stock rose 0.9 percent to 19.62 reais at 4:27 p.m. in Sao Paulo after advancing as much as 3.3 percent, the biggest intraday gain since July 18.
The extra yield, or spread, investors demand to own Petrobras bonds due in 2023 rather than U.S. treasuries fell to 281 basis points from 301 basis points at the end of last year. Brazil’s economic growth will slow to 1.3 percent this year before quickening to 1.7 percent and 2.6 percent in the next two years, respectively, according to estimates tracked by Bloomberg.
Rush Job
Investors aren’t counting on Petrobras meeting its targets this year, Eric Conrads, who helps oversee $500 million in Latin American stocks as a money manager at ING Groep NV, said. The stock has gained on speculation that October’s presidential elections will herald more investor-friendly policies.
“I don’t think the market is expecting the company to meet this guidance at all,” Conrads said by telephone from New York. “Fundamentals have taken a back seat.”
A rush to get P-62 and other platforms on the ocean last year contributed to delays, according to Jose Maria Rangel, a union leader and former board member who visited the platform on July 1 and said he witnessed difficulties connecting the 3rd of 24th wells. The company was also fixing equipment flaws and preparing to receive the vessel full of workers, he said.
It took more than four months to pump the first barrel at P-62, twice as long as initially planned. The floatel was leased to finish installing equipment that should have been done before it left shipyards, Rangel said by phone from Rio.
Trade Surplus
“The amount of repairs needed now aren’t small,” he said by telephone. “They were having problems connecting wells on both P-62 and P-55. Obviously if you have set backs this will reflect on production results.”
In Brazil, platforms are registered as export items and they helped the government post a trade surplus in 2013. The company started operations at P-55 just an hour and a half before the end of the year and sent P-62 offshore unfinished, Rangel said. P-61 also departed shipyards on Dec.31 en route to Campos Basin Papa Terra and missed a first-half production start date given in a January statement. Both P-55 and FPSO Cidade de Paraty at the Lula Nordeste field have suffered equipment delays. The units can cost more than $1 billion each to build.
Petrobras said concluding work when platforms are en route to fields is standard practice.
The company on July 19 shut Sapinhoa, Brazil’s seventh-biggest producing field, for six days to repair a natural gas cooling unit, Petrobras said in a separate e-mailed response to questions.
Target Jeopardized
Brazil’s Labor Ministry sanctioned the P-62 in March and fined Petrobras for five irregularities, including flaws in the gas-leak monitoring, fire fighting and alarm systems. The gas infrastructure still hasn’t been cleared to operate, the ministry said in an e-mailed response to Bloomberg. Officials are now looking into sister platform P-55, already sanctioned by the oil regulator for using inadequate equipment, it said.
Analysts from Banco Santander SA to Bradesco warn the slower-than-forecast expansion so far is putting this year’s goal at risk even though new wells and production vessels are expected to accelerate growth in the second half.
Production was almost unchanged in the first four months of the year and started rising in May when P-62 began extracting crude from Roncador. In June, domestic output surpassed 2 million barrels a day, although it still trailed 2011 levels, prompting Santander analysts to label the performance disappointing.
Natural Decline
Output growth probably will be capped at 5 percent this year because of project delays and natural decline rates at mature fields it has been exploiting for decades, Bernardo Wjuniski, an analyst at Medley Global Advisers, who does research on Brazil’s oil industry, said by phone from Sao Paulo.
At best, Petrobras will add 200,000 barrels a day each year on average, compared with about 300,000 in the company’s business plan, Wjuniski said. Petrobras overestimates how fast it will bring new fields on line and underestimates how much output will fall at older fields with depleting reserves, he said.
Bradesco cut its annual production growth estimate to 6.5 percent, the bottom end of the range forecast by Petrobras, from 8.5 percent.
The company’s decline rates are in line with international levels, Jose Formigli, who heads exploration and production, told reporters last month. Petrobras intends to double local output to more than 4 million barrels a day by the end of the decade.
‘Way Above’
Geology may help the company recover some of the losses, as production in some pre-salt fields beat expectations. Two wells at Sapinhoa are producing more than 30,000 barrels a day, according to regulator ANP. Petrobras reached capacity at FPSO Cidade de Sao Paulo with four wells compared with the six to eight it had estimated.
“Put a time delay on their own assumptions for the new projects, add all of the decline rates, and then you have a very different picture of how much they can add year over year,” Wjuniski said. “They are way, way above what I think they can do.”
http://www.bloomberg.com/news/2014-...ls-output-goals-at-risk-corporate-brazil.html