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Oil Prices steadied after Kuwaiti workers’ strike

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Monday 18 April 2016 19.13 1 of 2 Brent tumbled as much as 7% earlier after oil majors from the Organisation of the Petroleum Exporting Countries and non-OPEC Russia failed to reach agreement on a plan to freeze output Brent tumbled as much as 7% earlier after oil majors from the Organisation of the Petroleum Exporting Countries and non-OPEC Russia failed to reach agreement on a plan to freeze output Oil prices steadied today after a Kuwaiti workers' strike slashed the country's oil output by more than half, offsetting worries about a scuttled plan by major oil producers to freeze production. The strike cut more than 60% of Kuwait's crude output, lending support to price benchmarks such as Brent and Dubai. Supply of refined oil product from the country also tightened due to scaled-back refinery runs and lower fuel exports. Price of oil has dropped sharply RELATED AUDIO & VIDEO Listen: Price of oil has dropped sharply Brent tumbled as much as 7% earlier after oil majors from the Organisation of the Petroleum Exporting Countries and non-OPEC Russia failed to reach agreement on a plan to freeze output. The producers had gathered in Qatar, Doha at the weekend for what was expected to be the rubber-stamping of a deal to stabilise output at January levels until October. The deal crumbled when OPEC heavyweight Saudi Arabia demanded Iran join the plan, despite Tehran's repeated assertions it would not. "The material loss in production from the Kuwait strike has helped the oil market forget about the farce from Doha," said Matt Smith, director of commodity research at the New York-headquartered Clipper data. Brent was up 20 cents, or 0.4%, at $43.30 a barrel by 5.32pm Irish time. It had fallen $3 earlier in the session. US crude's West Texas Intermediate benchmark was off 31 cents, or 0.8%, at $40.05 a barrel, after sliding to $37.61 at the day's low. Brent's premium versus WTI was at its widest in nearly two months. While fallout from the Doha plan could weigh on a nascent recovery in oil prices, the market may not tumble as much as it did earlier this year, when Brent hit 12-year lows of around $27 in late January, some analysts said. "Gradually declining non-OPEC production as well as planned maintenance in the face of resilient oil demand in Q1 have recently pointed to improving oil fundamentals," analysts at Goldman Sachs said in a note, referring to the first quarter. A weakening US dollar and the mostly steady climb in global equities since February was supportive to oil too, traders said. "While a few forecasters may be dusting off some old $20 WTI expectations as a result of the Doha outcome, we expect solid support in nearby WTI at the $35 mark," Jim Ritterbusch at Chicago oil consultancy Ritterbusch & Associates said. WTI traded off today's lows after data from market intelligence firm Genscape showed crude inventories at the Cushing, Oklahoma delivery point for US crude futures falling by nearly 860,000 barrels during the week to 15 April, traders who saw the data said. Source: Reuters

Oil falls before Doha meeting

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Markets Fri Apr 15, 2016 8:41pm EDT

Oil falls as investors expect little from Doha meeting

Oil prices fell on Friday in subdued trade as traders and analysts anticipate a weekend meeting of major oil exporters to do little to help to clear global oversupply quickly, even though it would provide a floor for the market. All eyes are on Doha as producers, led by top exporters Saudi Arabia and Russia, meet on Sunday to discuss freezing output around current levels in an effort to contain a glut exacerbated by production that exceeds demand by about 1.5 million barrels a day. It would be the first joint action by major OPEC and non-OPEC producers in 15 years, although Iran has refused to participate, saying that it wants to rebuild its output to levels achieved before imposition of the recently lifted economic sanctions. "Unless there's a total surprise, the likelihood is that the Doha meeting on Sunday between OPEC/non-OPEC will produce something very wishy washy and will be nothing more than smoke and mirrors," one trader said. "I therefore want to sell crude today." Traders said profit-taking by funds ahead of the meeting also added to the pressure on prices in the session. Brent crude futures LCOc1 settled down 74 cents at $43.10 while U.S. crude CLc1 ended down $1.14 cents at $40.36. Both contracts lost more than 3.5 percent earlier in the day. However, on a weekly basis, prices were higher for the second week in a row in the run up to the meeting. Oil also trimmed some losses after data from Baker Hughes showed U.S. energy firms cut oil rigs for a fourth week in a row to the lowest level since November 2009. With discussions among producers focusing on freezing output rather than cutting it, most analysts said they had little hope for a deal that reduces the global oversupply. The crude surplus has pulled down crude prices by as much as 70 percent since mid-2014. "A cut in production is very unlikely at this meeting and I would say it will probably not even be a discussion item on the meeting agenda," said Energy Management Institute analyst Dominick Chirichella. "The conclusion for today is to buckle up your seatbelts - the ride could get wild next week." Barclays said that while the Doha meeting does not materially change the oil market balances, if recent supply-side fundamental support holds and the market's expectations for a credible statement and commitment are met, it could help prevent prices from falling back to the low $30 range. Consultancy Petromatrix said it saw the Saudis as a G20 member pushing for a deal to freeze output because both the IMF and the U.S. Federal Reserve are growing increasingly impatient about low oil prices. (Additional reporting by Dmitri Zhdannikov in London and Henning Gloystein in Singapore; editing by Bill Trott and Chizu Nomiyama)

West Texas Shale Moves Forward As Oil Slumps

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12/13/2014 by Andrew Silver   While oil prices slump to lows not seen since the great recession West Texas shale plays seem to be moving full steam ahead.  Fueled by mid-major companies like Cimarex, Devon and Anadarko, West Texas Shale plays like the Wolfcamp and Bone Springs seem to be on schedule as funded by budgets created in 2013. Many experts have predicted benchmark prices falling to as low as $50.00 per Barrel and then rebounding to somewhere in the mid 70's range sometime in 2015.  The prevailing theory is that highly leveraged producing countries like Venezuela, Libya, Iran and then ultimately Russia will see companies back off drilling due to default which will reduce the supply glut as demand rebounds.  American producers will certainly be hurt in the mean time but some stability will be added domestically as larger operators swallow up the smaller injured companies. Kansas Pic 13

The Wolfcamp Shale: The Biggest Shale Oil Play You’ve Never Heard Of

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The Biggest Shale Oil Play You've Never Heard Of

By Frank Curzio, editor, Small Stock Specialist  Friday, August 9, 2013 
Over the past few years, a handful of major oil and gas explorers have quietly accumulated massive amounts of land in a little-known shale area in West Texas...
Early estimates show this small, oil-rich region could contain 50 billion barrels of recoverable oil... making it the biggest oilfield in the country and the second-largest in the world.
And their bet is paying off.
Many of the area's big oil producers just reported blowout earnings from their drilling operations in the region. And it's only the beginning...
As longtime readers know, the "Permian Basin" is an oil-rich region located in West Texas. It consists of multiple shale formations, including the Cline Shale (which we've called "one of the greatest shale areas this country has ever seen.")
But there's another area within the Permian Basin catching the attention of oil producers – the Wolfcamp Shale.
My colleague Matt Badiali told you about the huge potential of this area a few months ago. He explained the Wolfcamp Shale is one of the few shale areas in the U.S. that has several layers in which oil companies can drill.
Think of it as a layered cake...
Each one of these layers has huge potential for oil. The layers include the upper Wolfcamp Shale (4,000 feet below the surface), lower Wolfcamp Shale (6,000 feet below the surface), and the Cline Shale (7,300 feet below the surface).
Like Matt mentioned, these stacked plays are great for oil and gas producers. And if they want to increase production, they don't have to worry about the huge costs of a brand-new exploration program. That's because their exploration is directly under their existing wells.
Over the past few years, oil-producing companies – like Pioneer Natural Resources, Devon Energy, and Energen – have been buying up acreage in the Wolfcamp like crazy.
And this move is paying off big.
Over the past week, every one of these companies reported blow-out earnings. During their conference calls, each highlighted the huge results they are just beginning to see from the Wolfcamp Shale.
I called my friend Cactus Schroeder two days ago to ask him about the Wolfcamp. Cactus has been drilling for oil in Texas for more than 30 years. I've written about him at least a dozen times in these pages. And I toured the Eagle FordPermian Basin, and Cline Shale areas with him several times over the past year.
"Frank, it's pretty wild how much drilling is taking place right now in the southern part of the Wolfcamp," Cactus told me. "It's likely to continue for a real long time."
I agree...
Pioneer Natural Resources owns over 700,000 net acres in the region. And production is soaring. During the company's most-recent quarter, production surged 26% versus a year ago. The wells Pioneer drills in the Wolfcamp are super-productive. Many of the new wells produce more than 1,500 BOE (barrels of equivalent) during the first few days. To put this in perspective, a new well is considered a big success if it hits the 1,000-barrel-per-day mark. Wolfcamp wells are true "gushers."
Last week, management said it plans on spending $425 million of its $1.6 billion budget developing wells in the Wolfcamp. Specifically, the company intends on doubling its rig count over the next two years in the southern part of the area.
Devon Energy is experiencing a similar boom. The company owns roughly 250,000 acres in the Wolfcamp. In the most recent quarter, its production surged 32% versus a year ago. Devon recently drilled 34 horizontal wells in the Wolfcamp and brought 19 online. These wells are also producing up to 1,000 barrels of oil per day. That's huge.
Devon is spending about $1.5 billion to develop its Permian Basin properties – including at least 300 new wells.
Energen is a smaller player in the area. It's a $4 billion oil producer with 40,000 net acres in the Wolfcamp. The company is also drilling in the southernmost part of the area right now. And early results have been nothing short of fantastic. In fact, the stock jumped 17% in one day last week after reporting strong drilling results in the Wolfcamp Shale.
Almost every oil and gas company operating in the Wolfcamp is reporting blow-out numbers. And the three companies I mentioned above are going "all-in" – spending hundreds of millions of dollars to expand operations in the area.
These are three great growth plays in a market where many companies are struggling for growth. Sure, these names have run up since reporting earnings results last week. However, after talking to industry professionals and doing some good old "boots on the ground" research, I believe this growth is likely to continue for many years to come.
I suggest adding at least one of these names to your portfolio today.
Good investing,
Frank Curzio

Early Days Show Promise for Tuscaloosa Marine Shale

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Tuscaloosa Marine Shale

Early Days Show Promise for the Tuscaloosa Marine Shale

By Gregory DL Morris, Special Correspondent

What pleases independent producers about the Tuscaloosa Marine Shale (TMS) in southeastern Louisiana and the southwestern edge of Mississippi is not so much what the formation is, but rather what it is not. Most importantly, they say, it is not the next Haynesville. Neither is it the next Bakken or Marcellus. What the TMS is, according to participants in the basin, is a promising oil play where only a few rigs are working–fewer than 20 wells had been drilled in the play by August–and lease rates still were in the low three figures. To be sure, participants acknowledge, the TMS is in its very early days and there is still a great deal to be learned about stratigraphy, geochemistry and completion techniques. But even the most ardent boosters say they are pleased with a quiet little play they can develop at a comfortable, economical, and technically robust pace. “We have only three or four rigs running in the TMS today,” reflected Louisiana Oil & Gas Association President Donald Briggs in early August. “When a few people started developing the play, other folks started thinking it was the next Haynesville. Some people still might, but the TMS has very different geology.” The play is spread over several Louisiana parishes and spills over the state line into a few Mississippi counties. A couple producers are concentrating their efforts on the Magnolia State side of the border, but the bulk of the acreage and activity has been in the Bayou State, Briggs reports. He says that is good for his state as well as LOGA, but it also has meant some complications. “We have had a bit of trouble with parishes trying to create their own ordinances for different aspects of development,” Briggs says, adding that strikes him, as well as many of his colleagues, as unnecessary on either a practical or regulatory level. “We have had only 18 wells drilled into the TMS–not per year, but in total,” Briggs says. “Of those, 10 are in production, and we are seeing only about two new wells per parish.” He contends that is far too few for local officials to be fussing over. Besides, Briggs adds, Louisiana has been a top producing state for close to a century, and has some of the most detailed and extensive development regulations of any state. That means that with the possible exception of highly localized road or quality of life questions, parish regulations usually are unnecessary. The Big Revelation Briggs says the Tuscaloosa Marine Shale could be considered Louisiana’s Eagle Ford. In one similarity to that marquee Texas development, he notes that when leasing started in earnest in the TMS about a year ago, it did not take long for 3 million acres to be snapped up. That is where the similarity ends, however, because lease bonuses were–and continue to be–less than $400 an acre, he says. And even with 3 million acres leased, Briggs noted in early August, “There have been only eight, 640-acre units formed so far in South Louisiana.” Nevertheless, the flurry of leasing activity drew the attention of legislators and regulators. “People started talking about the TMS, and all of a sudden, (state lawmakers in) Baton Rouge started looking into it, too,” Briggs recalls. “The officials were concerned about congestion and degradation on rural roads, pipeline construction and so forth. But also, everyone in the state knows someone from North Louisiana who became a millionaire from the Haynesville. It was like gold fever.” Part of the TMS’s slower pace of development, Briggs explains, is because the most prospective parts of the Tuscaloosa are 15,000 feet deep, and the big rigs needed to drill it are expensive and slower to move. But regardless of depth, early days for a play are just that. “We are still finding the best landing zones and the best cocktails for fracture fluids,” Briggs says. “The first wells have made 300 to 500 barrels a day, but we don’t know how long that will last. Producers still are trying to define the type curve.” Still, Briggs remains sanguine that the TMS will be a solid play. “People are still leasing, and people are still drilling,” he points out. “Those are the most important things.” Good Early Results According to Robert Turnham, president of Houston-based Goodrich Petroleum, a signal well for the Tuscaloosa Marine Shale could be the Anderson 17H-1 in Amite County, Ms. The well is being operated by Encana Corporation, and Goodrich has a 5 percent interest. Not only was the initial production more than 1,000 barrels a day, the 30-day average held at slightly less than the IP rate, Turnham says. He acknowledges that the low leasing rates are at least partially a result of the play’s youth, but he says there also are many unknowns. “There are some negative perceptions about the play,” Turnham states. “It is deeper than most other shale plays, and that means it is more expensive to drill and complete. Also, the initial concern was that the clay content was high, although we no longer are concerned with that. If it is too high in places, proppant can become imbedded.” More broadly, Turnham adds, “There is a lot we still don’t know, and without a lot of wells drilled, in some cases we are having to rely on old core data. The TMS has something of a checkered past because proper completion techniques were not used. But once this play is proved up, you are going to see things move fast.” For all its variables, Turnham says the TMS is not without analogies. “We have learned some important lessons from the Haynesville nearby, and from the Eagle Ford, where we have extensive operations,” he says. “Values of the wells and of the acreage are not great now, but in time, you will see those rise.” And that, in essence, is Goodrich’s value proposition. “We typically move early on plays such as the TMS,” says Turnham. “We take the risk to prove the play. That is exactly what we did in the Haynesville. We came in early and acquired a strong position at only $200 an acre, then we sold a portion of our block to Chesapeake Energy Corp. for $17,500 an acre. If the same thing can happen in the Tuscaloosa, operators who want to get in later are going to have to bid up the value.” The next steps are being taken already, Turnham reports. “Beyond the first movers taking acreage positions, we are seeing the service companies spreading out. Those are the people who will help us learn how to drill this formation, understand and clearly delineate it. They are the ones who will gain the experience with bits and muds,” he reasons. Generally, Turnham characterizes the TMS as 150-200 feet thick. “At the upper levels, it is black-gray shale. Lower, it is more brittle, like a layer cake with sand and limestone, along with vertical and horizontal fractures. In that sense, it is something like the Bakken,” he describes. “Technically, the Middle Bakken is not even shale, but a fractured limestone. But upper or lower, it is way too early to be able to differentiate acreage within the TMS.” Preference For Partnerships One interesting characteristic of the TMS development so far is that the relatively small number of developing companies report they are quite cooperative, working jointly on wells and sharing data. As an example, Goodrich has 132,000 acres in the Tuscaloosa Marine Shale and is a partner with Encana on the Mississippi side of the state line. Encana operates the Joe Jackson well, in which it has a 75 percent interest to Goodrich’s 25 percent, Turnham notes. Other wells are different ratios, but Turnham says what really matters is that “we invest the best time and money in the science to get the drilling and completion right.” He adds that beyond the four wells Goodrich and Encana plan to develop this year, there will be a handful more wells drilled by other companies over the next few months. That pace is expected to continue through at least this year and into 2013. “We and all the other operators are trying to put together plans and budgets,” Turnham says. “We already have some commercial production, but it is too early for us to make reserve estimates.” Encana has released some information, saying its two Anderson wells hold 730,000 barrels of oil equivalent each. To some degree, the company indicates, the reserve estimates depend on what is found to be the optimum lateral length. Ideas at this point seem to favor 7,300-8,700 feet, as opposed to the 5,000-foot laterals that were used in early wells, Encana reports. On the technical side, Turnham notes the few producing wells in the play thus far are mostly flowing up the casing. Goodrich and other operators say they prefer to shift that to flowing up tubing to better manage flow back and to allow wells to unload better because of higher pressures. Ultimately, all the wells are expected to go on pump, but when has yet to be determined. He says the light, sweet TMS crude enjoys some price advantages. “We are getting Louisiana Light Sweet pricing, which is similar to Brent, which has been carrying a $15-$20 uplift over West Texas Intermediate with very little discount for transportation logistics,” Turnham reports. “There is some infrastructure in the area to move crude north to St. Louis or south to the Gulf Coast, but gas infrastructure will need to be enhanced, once production begins in larger volumes,” he adds. Another aspect of TMS production is the ratio of liquids. “We are seeing about 94 percent oil,” says Turnham. “That compares very favorably with the Eagle Ford, where we see about 85 percent oil. With prices for the two commodities where they are, the TMS carries a big advantage because of its high percentage of oil. However, it is good to have a little gas to help lift the oil.” He also says that Tuscaloosa gas is rich, but that the production volumes so far have been too little for natural gas liquids markets to be interested. “It’s just not enough yet to matter,” Turnham notes. That said, when production does begin to develop, Turnham calculates that producers can anticipate an auxiliary revenue stream from the liquids. But that is in the future. “For now, our goal is to retain 100 percent of our TMS position while we develop and delineate the play,” Turnham outlines. “Down the road, if we sell, it would be a minority interest or a financial partner.” But the payoff could be huge. He calculates the entire TMS play, at $10,000 an acre, is worth $1.3 billion to Goodrich.