OPEC must live with the reality of oil prices remaining well below $100/barrel, a level the market no longer recognizes, OPEC secretary general Abdalla el-Badri said as the oil producer group maintained official output at 30 million b/d for the next six months.

Badri stopped short of saying how this new reality might translate to actual price levels. Brent crude appears to have found a trading range -- for the time being, at least -- of $60-$65/b, although this falls considerably short of the $75-$80 suggestions from ministers polled over the past few days in Vienna.

Indeed, current Brent prices are closer to the $65/b plus-or-minus $2-$3/b preferred by key consumer India.

"Now the cycle is down, we have to live with it," Badri told a press conference. "We have to adjust to the new reality. The market does not recognize $100 anymore."

In a communique, OPEC said the sharp decline in oil prices caused by oversupply and speculation had now abated, with prices moving higher in recent months.

But it also noted that stock levels "lie well above the five-year average in terms of absolute volumes, indicating that the market is comfortably supplied."

Member countries, OPEC said, had "confirmed their commitment to a stable and balanced oil market, with prices at levels that are suitable for both producers and consumers," but did not define a suitable price.

Iranian oil minister Bijan Zanganeh, however, said most members believed that $75/barrel was reasonable.

But still smoldering away below the surface are the tensions that run along the fault lines of OPEC's geographical and geopolitical map.

These tensions continue to separate the richer members from those without the financial wherewithal or production capacity to help them ride the tide of what could turn out to be years of below-breakeven prices as world oil markets re-balance alongside changing supply patterns.

OPEC may be congratulating itself for having, through its November decision not to cut output despite the oil price plunge, dealt a blow to US shale oil production, which is now growing more slowly.

Over the longer term, though, shale is likely to continue to challenge OPEC, especially if the United States government decides to allow the export of light crude.

http://www.platts.com/news-feature/2015/oil/opec-guide/index?hootpostid=9780c4aab55e759c885c895317bfc24d

Nigeria can boost its oil and gas production by changing the way capital investments are funded in its joint ventures with energy companies, according to Seplat Petroleum Development Co.

State-owned Nigerian National Petroleum Corp., or NNPC, holds an average 55 percent stake in five joint ventures with Royal Dutch Shell Plc, Exxon Mobil Corp., Chevron Corp., Total SA and Eni

SpA that pump more than 80 percent of the country’s crude. It pays the same share of capital contributions for the operation of the oil ventures.

Seplat, a Nigerian producer now running a joint venture with NNPC after buying assets sold by Shell, wants the current funding arrangement in Africa’s biggest oil producer scrapped in favor of a method less dependent on the government.

The “cash call” requirements are a “constraint” affecting production, Ambroise Orjiako, the company’s chairman, said in a June 5 interview at the World Economic Forum Africa in Cape Town.

“We need to find a situation where the joint-venture partners sit down and agree on what percentage of production should be dedicated on operation and capital expenditures,” Orjiako said.

“That way you ensure that growth in the industry is guaranteed, that the production will increase, that the reserves will be increased and that there will be room for exploration activities as well,” he said.

The Nigerian government struggles to meet its share of funding to the operation of the joint ventures with energy companies, thereby limiting the scope for increasing production. It is currently indebted to companies including Shell, Exxon Mobil, Total and Eni, which had provided loans in the past to fill the funding gap.

“We would like to see government also thinking about divesting some of its joint-venture assets such that the private sector will drive the industry,” Orjiako said.

https://www.energyvoice.com/oilandgas/79709/nigeria-could-boost-oil-output-with-changed-funding-seplat-says/

In a new two-part study, Wood Mackenzie explores the implications of the current low oil price for upstream fiscal terms. Governments dependent on oil taxation income are wrestling with lower oil revenues for public spending and pressure from oil and gas companies for more lenient terms.

Wood Mackenzie's analysis of fiscal changes from 2014 to date concludes that while there has been much talk of fiscal change in response to low oil prices, only a few governments have followed through, most notably the UK, which has made the most extensive changes, encompassing all assets.

"Governments which are less dependent on oil tax for income can afford to play the long game and will be more likely to reduce tax rates or introduce incentives to try to maintain investment while companies cut back on new projects elsewhere. However, their ability to do this may be restricted by contracts with oil and gas operators, which insist that the fiscal terms remain as they are," Kellas added.

Regressive fiscal terms—such as royalty, export duty, cost recovery ceilings and indirect taxes—have the most negative impact on future investment decisions. These are the most obvious targets for fiscal changes, especially in systems where the minimum government share of revenue is particularly high. Equally, high marginal tax rates reduce companies' interest in incremental opportunities and may need to be lowered, or other allowances introduced.

"It's important to note that governments facing declines in oil production would be considering how they can stimulate investment in any circumstances, and depressed oil prices makes this task more difficult and more necessary. Indonesia, in particular, may need to offer more attractive terms to try and stem its expected decline in oil production. Fiscal incentives for new investment—particularly challenging projects such as unconventional resources—are likely to become common," Kellas said.

In fact as Wood Mackenzie's study shows, several countries were already in the process of reviewing their fiscal terms before the oil price plunge, but this is an added complexity.

"Governments now launching exploration licensing rounds face stiff competition in what is a buyers' market. The fiscal terms on offer will play a critical role in determining how attractive the opportunities are perceived," Kellas concluded.

Bechtel is on track to complete the construction of an additional three liquefied natural gas (LNG) production trains on Curtis Island by the end of 2015, quadrupling Queensland's LNG production.

Bechtel is constructing the state's first three LNG plants, the first in the world to convert commercial quantities of coal seam gas into liquid form ready for export. When complete, the operators of the plants - Queensland Curtis LNG (BG Group), GLNG Plant Project (Santos, PETRONAS, Total & KOGAS) and Australia Pacific LNG (ConocoPhillips) - will produce the commodity for export to their global customers.

"The projects will begin producing LNG in rapid succession over the second half of 2015," said Alasdair Cathcart, Bechtel's global LNG general manager. "It's certainly a time of significant milestones on Curtis Island, as we move though final commissioning and eventually into handover of these projects to the operating teams.  It's all part of a carefully planned program to deliver unprecedented capacity to our customers, further building on our extensive global LNG experience."

Six production trains will be operational when Bechtel hands over the LNG plants to the owner teams for long-term operation. Queensland Curtis LNG Train 1 has been producing LNG since December 2014, filling more than 16 ships with cargo to date. Bechtel is now working on delivering the second train for that project. Concurrently, Bechtel teams on the GLNG and Australia Pacific LNG plants recently introduced gas into their systems and began producing their own power as part of commissioning the first of two production trains on each site. The second production trains on each of these projects are expected to be operational in early 2016.

http://www.prnewswire.com/news-releases/bechtel-ready-to-quadruple-queensland-lng-production-this-year-300095638.html

Tuesday skipped publishing monthly data on the average spot prices paid by
buyers in the country for liquefied natural gas (LNG) due to a lack of trades in May, the latest sign of tepid global demand for the fuel.

The LNG market has been struggling with oversupply as Australian projects ramp up output, ahead of more new developments coming online in the United States over the next year.

Japan's Ministry of Economy, Trade and Industry (METI) publishes the price average only when there is a total of at least two spot LNG trades from two companies. A ministry official declined to say whether there had been any trades at all in May.

This marks the first time that no prices have been published since Tokyo started surveying spot LNG prices in March 2014, looking to add transparency to the market amid concerns about rising fuel costs in the wake of the shutdown of nuclear plants after the Fukushima crisis.

Earlier METI data had shown that spot LNG contracted in April for delivery to Japan averaged $7.60 per million British thermal units (mmBtu), down from $8 the month before, less thanhalf the level a year ago.

Asian spot liquefied natural gas (LNG) prices for July were broadly stable late last week as lower production from some export plants still left plenty of supply to meet weak global demand.

The trade ministry survey looks at samples of fixed prices for LNG sold to power companies and utilities among others, and excludes spot deals linked to benchmark prices such as the U.S. natural gas Henry Hub index.

The following table lists monthly prices for LNG per million British thermal units for spot cargoes contracted during the month and those that arrived during the month.
   
  Year   Month   Contract price   Arrival price
  2015     May              n/a             n/a
  2015   April            $7.60           $7.90
  2015     Mar            $8.00           $7.60
  2015     Feb            $7.60          $10.70
  2015     Jan           $10.20          $13.90
  2014     Dec           $11.60          $15.10
  2014     Nov           $14.40          $14.30
  2014     Oct           $15.30          $12.40
  2014    Sept           $13.20          $11.30
  2014     Aug           $11.40          $12.50
  2014    July           $11.80          $13.80
  2014    June           $13.80          $15.00
  2014     May           $14.80          $16.30
  2014   April           $16.00          $18.30
  2014   March           $18.30             n/a

http://www.reuters.com/article/2015/06/09/lng-japan-spot-idUSL3N0YV1OY20150609

The US New Orleans jury has acquitted BP exploration former vice-president David Rainey of lying about the quantity of oil that spilled into the Gulf of Mexico following the explosion of the Deepwater Horizon rig in April 2010.

The US Government filed the case based on David Rainey's statement given to FBI and US Environmental Protection Agency (EPA).

Justice Department lawyer Robert Zink told Reuters that the text messages and testimony from witnesses proved that Rainey understated the flow rate intentionally.

According to Zink, Rainey termed a 5,000-barrel-a-day estimate as BP's 'best scientific guess' at the flow rate and sent it to Congress on 24 May 2010.

The Department of Justice said that a group of government and independent scientists assessed the situation and concluded that a total of over 60,000 barrels per day of oil leaked.

Following the rig explosion, BP said that approximately 1,000 barrels of oil per day were flowing into the Gulf of Mexico.

Rainey's lawyer Reid Weingarten was cited by Reuters as saying that the prosecutors could not prove Rainey will lie to investigators.

"Under the Clean Water Act, BP is facing up to $13.7bn in penalties."

In 2012, the company paid a $4bn settlement to the US and has also put aside $43.8bn to pay for the disaster.

In a regulatory filing in April, BP said it already paid more than $28bn in response, cleanup and compensation. Under the Clean Water Act, BP is facing up to $13.7bn in penalties.

http://www.offshore-technology.com/news/newsus-jury-acquits-bps-executive-of-lying-about-2010-deepwater-horizon-oil-spill-quantity-4595468

Argentine state-controlled oil company YPF said Monday it found unconventional gas in the Vaca Muerta shale play in the southern province of Neuquen.

The La Ribera x-1 well is located about 25 kilometers (15 miles) from the town of Añelo and some 90 kilometers (56 miles) from the capital of the province, YPF said in a statement.

"This discovery raises the expectations about the wealth and productivity of the Vaca Muerta formation in areas near those currently undergoing massive development," YPF said.

Initial tests indicate high potential for gas production, the oil company said.

This is the second unconventional resource discovery made in less than a month in Argentina.

YPF said on May 25 that it discovered unconventional oil in Rio Negro, another province in southern Argentina.

YPF announced the discovery of non-conventional oil and natural gas reserves in Vaca Muerta in 2011 after successful results in the exploration phase.

http://latino.foxnews.com/latino/news/2015/06/08/ypf-finds-unconventional-gas-in-southern-argentina/

The Aphrodite natural gas field off Cyprus is commercially viable and plans call for producing 8 billion cubic metres (bcm) a year and construction of a pipeline to Egypt.

Cyprus, which required an international bailout in 2013, is hoping for an economic turnaround based partly on offshore reserves.

Texas-based Noble Energy and Israel's Delek Group discovered the deposit, estimated to hold 128 bcm of gas, in Cyprus's offshore Block 12 in 2011. It also contains 9 million barrels of condensate.

Plans call for a floating production storage and offloading vessel (FPSO) to process 8 bcm of gas a year and the construction of underwater pipelines connecting the well to Cyprus and Egypt, Delek said in a statement.

The planned Egyptian exports were made possible by a cooperation agreement the countries signed in February, Delek said, adding that the partners would submit their plans to the Cypriot government in the near future.

Noble is the project operator with a 70 percent stake. Delek, through two subsidiaries, holds the remaining 30 percent, but is in early-stage talks to buy an additional 19.9 percent for about $155 million.

Cyprus is seeking to develop its energy sector to bolster an economy that relies mostly on tourism, business services and shipping. The island has, for now, shelved plans to create its own liquefied natural gas terminal.

http://in.reuters.com/article/2015/06/07/delek-noble-cyprus-idINL5N0YT03C20150607

The proportion of distillate cargoes making their way to the Mediterranean from the US has more than doubled this month from the January-May average, according to data on vessels tracked by Platts, drawn by premiums at a 28-week high over Northwest Europe.

Over the first five months of this year about 25% of USGC-originated cargoes bound for Europe discharged into the Mediterranean. So far this month, 54% have done so.

Meanwhile, Mediterranean ultra low sulfur diesel cargoes climbed to a $9/mt premium above Northwest European cargoes Friday, the widest spread between the two regions since November 24 on the back of supportive buying interest in the south against an oversupplied cargo market in the north.

CIF Mediterranean cargoes were assessed at $14.25/mt over front-month low sulfur gasoil futures Friday while CIF NWE cargoes were at a $5.25/mt premium.

"The Med [diesel] market is balanced and north is oversupplied," a source said Monday.

In the Mediterranean, demand remained strong in eastern destinations and the buying interest displayed in the Platts MOC failed to attract sellers.

Refinery turnarounds in Greece and Israel were contributing to tilt the balance to the short side, with firm seasonal demand emphasizing the tightness, notably in Turkey where Tupras was said to have issued a buy tender for 40,000 mt of diesel Friday.

Gasoil 0.1% demand in the Mediterranean has been a significant contributor to the market strength and the pull for distillate cargoes from the US, sources said.

http://www.platts.com/latest-news/oil/london/us-distillate-cargoes-arrive-in-mediterranean-26116567?hootpostid=1cabc6bf69addc47c6e153967a681147

The federal forecast of U.S. shale production is sinking again for the third month in a row, but the decline is still just a thin layer off the top.

Daily oil production at the nation’s six biggest shale plays is set to slip by 91,000 barrels from June to July, the Energy Information Administration says. That’s roughly 2 percent of the 5.48 million U.S. barrels anticipated next month, hardly the kind of decline oil-industry stakeholders had expected for after drillers sidelined nearly 1,000 oil-drilling rigs in the last six and a half months.

“It’s a pretty resilient industry,” said Bill Herbert, an analyst at Simmons & Co. International in Houston. And given the billions that oil producers have raised this year — they still have generous equity investors waiting in the wings — it’s not inconceivable that crude production could start to rise again early next year, especially with oil prices flirting with the $60-to-$65 a barrel range, Herbert said.

“If you send the right price signals, the oil producers are going to start reinvesting, and production will respond,” he said.

Oil traders are watching the shale industry and Baker Hughes’ U.S. rig count closely to see whether the nation’s production, which helped feed a glut of crude and send oil prices plummeting in the last 12 months, will ease up enough to lift prices again. Despite the falling rig count, not much has changed on the production side of the business, largely because oil companies are moving rigs to the sweetest shale acreage and because their rigs are more efficient, analysts say.

So far, falling production from older, deteriorating wells is outpacing the output from newly drilled wells, especially in the Eagle Ford Shale in South Texas, which is expected to see daily production decline by 49,000 barrels by July. Daily output at the Bakken Shale in North Dakota and the Niobrara formation in Colorado, Nebraska and surrounding states is supposed to fall by 29,000 and 17,000 barrels a day, respectively.

The Permian Basin in West Texas, so far the nation’s stalwart oil patch, still pumping out adding crude, is slipping close the point at which its net production will be in the red. Its month-over-month production is expected to be 3,000 barrels a day by July, the EIA estimates.

West Texas Intermediate, the U.S. benchmark crude, fell 99 cents to $58.14 a barrel on the New York Mercantile Exchange. The international standard, Brent, dipped 62 cents to $62.69 on the ICE Futures Europe.

Meanwhile, the nation’s natural gas production is shrinking in all but the Utica Shale in Ohio. From Texas to Pennsylvania, old wells are expected to bring down gas production by 221 million cubic feet a day, or 0.5 percent of the nation’s gas output.

http://fuelfix.com/blog/2015/06/08/u-s-shale-production-could-fall-again-in-july-eia-says/#31744101=0

Big Star Oil & Gas, LLC  today announced that its first Howard County horizontal well, the Ryder Unit A2H, has been successfully drilled and completed in the Wolfcamp A shale.  The well has a productive lateral length of 7500', and was completed using a 30-stage hybrid hydraulic fracture stimulation.  The well achieved a peak 24-hour IP rate of 1725 boepd (2-phase) and had a 30 day IP rate of 1469 boepd, consisting of average rates of 1358 bopd and 670 mcfd (92% oil).

Based upon production data as reported to the Texas Railroad Commission, the Ryder Unit A2H has achieved the highest reported 30-day average rate of any Howard County Wolfcamp horizontal well to date.  According to Railroad Commission data, Big Star's Ryder Unit A2H well produced 23% more oil and gas in its first month than the previous top horizontal Wolfcamp well, Athlon Energy's Tubb 39 #5H.  The Ryder Unit A2H is also performing significantly above the company's 752 MBOE Wolfcamp type curve.

Bradley Cross, President and Partner, Big Star Oil & Gas, said, "We are pleased with the record results that we have been able to achieve to date.  The successful drilling and completion of our Ryder Unit A2H horizontal shale well strategically positions Big Star among a small population of private, independent oil companies with the technological capabilities and resources to be a top-tier shale player in the Midland Basin."

Big Star is currently completing two additional Howard County horizontal wells, one in the Wolfcamp A shale and one in the Lower Spraberry shale.  The company has identified 207 gross development locations within the Wolfcamp A, Wolfcamp B, and Lower Spraberry shale horizons across its approximately 11,000 net acres of Midland Basin leasehold, and is seeking additional horizontal well development opportunities in the Middle Spraberry and Cline formations.

http://www.newson6.com/story/29267575/big-star-oil-gas-announces-record-results-with-first-horizontal-well