Saudi Arabia’s oil minister said he’s confident that an agreement by producers to curb crude output and shrink a market glut will be extended into the second half of the year and possibly beyond.

While U.S. shale output growth and the shutdown of refineries for maintenance have slowed the impact of cuts by OPEC and its partners, producers are determined to reach their goal of reducing bloated stockpiles, Khalid Al-Falih said at the Asia Oil and Gas Conference in Kuala Lumpur on Monday. He said he’s confident the global oil market will soon rebalance and return to a “healthy state.”

Surging U.S. production has raised concern the Organization of Petroleum Exporting Countries and partners are failing to reduce an oversupply and prop up prices. Oil has surrendered all its gains since their deal late last year to cut output and with OPEC meeting in Vienna later this month, several nations have said they’d support an extension of the 6-month agreement that began in January. This is the first time the Saudi minister has suggested it could be extended beyond 2017.

“Based on the consultations I have had with participating members I am rather confident the agreement will be extended into the second half of the year and possibly beyond,” Al-Falih said. “The producer coalition is determined to do whatever it takes to achieve our target of bringing stock levels back to the five-year average.”

West Texas Intermediate crude rose 1.2 percent to $46.76 a barrel by 12:20 p.m. Singapore time on the New York Mercantile Exchange. Brent, the benchmark for more than half the world’s oil, was up 1.3 percent to $49.73 a barrel on the London-based ICE Futures Europe exchange. Both are still more than 50 percent below their peaks in 2014, when the U.S. shale boom exacerbated a market glut and triggered the biggest price crash in a generation.

Al-Falih said last month that OPEC and its partners have failed, after three months of limiting output, to achieve their target of reducing oil inventories below the five-year historical average. Group member United Arab Emirates said earlier in May that the producer group should extend the collective production cuts into the second half of the year when an expected upturn in demand will help to re-balance the crude market.

Vienna Meeting

Russia, which is not member of OPEC but is part of the deal, also thinks it will be necessary to extend the reduction deal, according to Energy Minister Alexander Novak. The producers agreed last year to curb output by as much as 1.8 million barrels a day starting January. OPEC will meet in Vienna on May 25 to decide whether to prolong the deal beyond June.

While the producers curbed supply, production in the U.S., which is not part of the agreement, has risen to the highest level since August 2015 as drillers pump more from shale fields. But American crude inventories are showing some signs of shrinking, falling for the past four weeks from record levels at the end of March.

Despite lingering headwinds, the oil market is improving from early last year when markets were at a low, Al-Falih said. Stockpiles at sea have declined and U.S. inventories will continue their downward trend, he said. Global demand, meanwhile, will probably be stable from the “healthy rate” seen last year, driven by China and India, the Saudi minister said, adding that Asia was the most important market.

There’s about 20 million barrels a day of combined demand growth and natural oil-field output declines that need to be offset, Al-Falih said. “No matter how fast U.S. shale grows, it wont make a dent in that number,” he said.

https://www.bloomberg.com/news/articles/2017-05-08/saudi-oil-minister-says-output-cuts-may-extend-beyond-2h-of-2017

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The price swoon of the last few weeks has no doubt disappointed -- if not frustrated -- OPEC's 13 members, who have seen their efforts to cut production to support prices seemingly thwarted by stubbornly high inventories.

But all along, OPEC officials have maintained that their goal with the production cut deal can not and should not be measured by how the market reacts day to day, or even week to week.

Their eyes are focused on the third quarter, when OPEC's own analysis, as laid out in its most recent monthly oil market report, estimates global demand for OPEC crude will rise to 33.13 million b/d, some 1.3 million b/d above current levels.

OPEC will issue its newest monthly oil market report next Thursday.

"The good news is that the market is moving towards rebalancing," Saudi Aramco CEO Amin Nasser said at the International Oil Summit in Paris last week. "There has also been a rapid drawdown of floating storage in the first quarter of this year. This is being driven by improving fundamentals and the OPEC deal."

Iranian deputy oil minister Roknaddin Javadi added: "I am very optimistic that good days for the oil and gas industry are ahead."

The deal, signed late last year, calls on OPEC to cut 1.2 million b/d from its October levels, while 11 non-OPEC countries led by Russia agreed to cut 558,000 b/d in concert.

To be sure, OPEC had intended its production cuts to have brought down global oil stocks to their five-year average by mid-year. That has not been the case, particularly in the US, where bloated gasoline stocks, in particular, has given the market jitters.

US gasoline stocks were 19.5 million barrels above the five-year average at 241.2 million barrels the week that ended April 28, according to the US Energy Information Administration.

Analysts with PIRA, a unit of S&P Global Platts, say the market's fretting over US inventory statistics may be overblown.

"The lack of visible stock declines have undermined oil market confidence and dragged prices lower," PIRA said in a recent note. "Market jitters are unwarranted; oil on the water is declining, OPEC output is declining and surplus stocks are declining. Onshore stock declines are inevitable, though the exact timing is tricky."

EXTENSION TALKS

The production cut deal, as signed, was to last from January to June, although ministers have said they reserve the option to extend the deal if market conditions have not been to their satisfaction.

OPEC appears to be moving towards an extension, with Saudi Energy Minister Khalid al-Falih recently saying there was a growing consensus that one was needed.

But still unresolved are the particulars of any extension -- its length, the level of cuts, and whether Libya and Nigeria, which were given exemptions from the cuts, and Iran, which was allowed a slight rise in production, will continue to receive special dispensation.

Falih has floated the idea of a three-month extension, instead of a six-month one, while Kuwaiti oil minister Essam al-Marzouq has said that if demand is healthy in the second half of the year, the production cuts may not need to be as deep.

Iraqi officials, however, have indicated they are not on the same page, having insisted the deal concerns exports, not production, contrary to the text of the agreement posted on OPEC's website.

"We are committed to the agreement with OPEC. Still, our internal demand is increasing, so our production can be increased without affecting our commitment," Naufel Alhasan, deputy chief of staff to Iraqi Prime Minister Haider al-Abadi, told Platts in Houston this week.

OPEC, along with the 11 non-OPEC deal participants, will meet in Vienna on May 25 to review the deal and negotiate any extension.

Given the resilience of US producers, who have ramped up output by some 600,000 b/d since the deal was signed, according to the EIA, OPEC may need to show the market a stronger hand with a more stringent extension, said Mohammed al-Sabban, a former advisor to the Saudi oil ministry.

This may include sharper cuts or a requirement that Libya, Nigeria and Iran join in, he said.

"The agreement extension should not be an automatic rollover, we may need to have deeper cuts," he told Platts. "The competition with American oil is going to be more severe in the coming months."

Nigeria and Libya, which have seen their oil sectors hit hard by militancy over the past year, will seek a renewal of their exemptions, even with their prospects improving recently.

Their combined production this year, while volatile, has averaged just 6,300 b/d more than October, the benchmark month that the production cut deal is measured from, according to the latest Platts OPEC survey.

Iran, meanwhile, has yet to be asked to join in the output cuts as part of an extension, "to my knowledge," Javadi told Platts.

COMPLIANCE UNREWARDED

On compliance, OPEC has performed very well.

The Platts OPEC survey for April, released Thursday, found that the 10 members required to lower output under the deal achieved 105% of their cuts.

As a whole, OPEC's total April output of 31.85 million b/d remains 80,000 b/d above the organization's stated ceiling of about 31.77 million b/d, not including Indonesia, which suspended its membership in November and is not counted in the Platts survey.

That has exceeded the expectations of many OPEC watchers, given the organization's tattered history of adhering to previous production agreements. Nevertheless, the market has stopped rewarding OPEC for its high level of compliance, amid the US shale rebound. Analysts say an extension of the cuts is already priced into current market expectations, even with prices having given up all of their gains since the OPEC/non-OPEC deal was signed.

ICE Brent futures were $48.57/b at 1015 GMT Friday, recovering from a sharp fall in earlier trading.

Even as they remain resolute on their intermediate-term goal of drawing down inventories, OPEC is likely to be mindful of 2016's price volatility when the bloc's members were engaged in a brutal market share battle.

"They'll have to extend [the deal], or the show's over," one Platts survey participant said. "The market will fall very quickly if they don't."

https://www.platts.com/latest-news/oil/london/analysis-as-prices-fall-opec-looks-to-q3-for-27826622

The energy industry scrutinizes U.S. oil stockpile data every week for evidence that OPEC supply cuts are ending a global crude glut, but growing domestic output means the world's largest oil consumer may be the last place to feel the cuts.

Stubbornly high U.S. inventory levels have shaken market confidence that a deal by the Organization of the Petroleum Exporting Countries (OPEC), Russia and other top producers to cut 1.8 million barrels per day (bpd) from supply will end the two-year glut.

This week, benchmark Brent crude prices slipped below $50 a barrel. Brent has given up all the gains made since the supply cuts were agreed late last year. [O/R]

U.S. inventories are a trusted barometer for the health of global oil markets because of the transparency of the data and their location in the country that consumes around a fifth of the world's oil.

But U.S. crude inventories have only grown since the supply cuts took effect. The initial spike in oil prices after the deal reinforced already resurgent production from the U.S. shale industry.

The rush back into the fields boosted U.S. shale output to an estimated 5.2 million bpd in May from 4.5 million at the end of 2016. The increase of 700,000 bpd in U.S. supply has replaced much of the output cuts delivered under the OPEC-led agreement.

Offshore production in the Gulf of Mexico has also hit a record, bringing total U.S. output to 9.3 million barrels a day, its highest since August 2015.

That has helped keep U.S. stockpiles full.

"As long as U.S. producers are able to pump oil at a profit then the rebalancing in the U.S. is going to take time," said Mark Watkins, regional investment manager at U.S. Bank.

"It's going to be an extended period of time still. I would look to at least the end of the year."

In addition, producer countries that pumped a lot of their own oil into storage at home have recently been exporting from those tanks to consumer countries such as the United States.

OPEC members typically do not disclose their stock levels. So even though the export of stored oil is part of the effort to draw down global inventories, it also has pushed previously invisible inventories into global storage data.

Those OPEC shipments may now be easing. Thomson Reuters shipping data shows crude exports from the group dropped from March to April by about 50 million barrels to 741.2 million barrels.

U.S. STOCKPILES RISE

U.S. crude inventories hit records earlier this year, and remain up 10 percent since the OPEC-led supply cuts took effect on Jan. 1.

U.S. crude stocks stand at 527.8 million barrels, nearly 30 percent higher than the average of the past five years, according to government data.

Exports from the United States have been steadily rising and have also regularly reached records this year. If markets tighten elsewhere, U.S. exports will increase and this should drain domestic inventories more quickly.

"What you're going to have to see is global supply across the world drop and U.S. crude ship out before you start to see a meaningful drop in U.S. inventories," said Watkins.

"And that's something that's started a little bit, but it's pretty marginal."

Despite the high domestic output, there are some signs that efforts to reduce the global glut may be having an impact in the United States.

A recent four-week run of U.S. inventory draws has been larger than the 2011-2016 average for this time of year, said Credit Suisse in a note on Friday.

IMPACT ELSEWHERE

More tangible impacts on inventories can be seen elsewhere, some analysts said; inventories simply need more time to return to average levels.

There have been some signs of drawdowns in global inventories, particularly in floating storage, when oil is stored in a tanker anchored offshore. According to Clipperdata this type of storage has been falling near the refining hub of Singapore.

Singapore "acts as such a parking lot for tankers and should we see Singapore floating storage be drawn down materially that would indicate that the market is tightening," said Matt Smith, director of commodity research at Clipperdata.

Clipperdata estimates that 50 million barrels are floating off Singapore, down sharply from February's peak of 64 million barrels, which was the highest point in at least a year.

"The lack of visible stock declines ... undermined oil market confidence and dragged markets lower," said oil consultants PIRA Energy in a note this week.

"Market jitters are unwarranted; oil on the water is declining, OPEC output is declining and stocks are declining. Onshore stock declines are inevitable, but the exact timing is tricky."

May 8 China's crude oil imports during the January to April period this year gained 12.5 percent over a year earlier to 139 million tonnes, Chinese customs said on Monday.

Natural gas imports during the same period were up 5.4 percent from a year ago to 20.11 million tonnes, the customs said.

http://www.reuters.com/article/china-economy-trade-crude-idUSB9N1HZ01T

China’s April Crude Oil Imports -11.71% M/m to 34.39m Tons

@zerohedge

Australia's top energy retailer, Origin Energy, said on Friday it doubled its stake in the Beetaloo Basin shale gas field in Australia's Northern Territory.

The company said it increased its share in the undeveloped prospect to 70 percent, after purchasing a 35 percent share from Sasol Petroleum Australia Ltd. It did not disclose a purchase price and said the transaction is subject to "certain conditions," without elaborating.

"It is not expected to impact on Origin's short-term focus on debt reduction as there are no immediate capital requirements in the Beetaloo," Origin said in a statement.

In February, Origin said it estimates contingent resources in the field to be 6.6 trillion cubic feet. But its extraction depends on the Northern Territory government lifting a ban on hydraulic fracking. The government is reviewing the ban but has set no deadline for making a decision.

Origin last week reported soaring gas revenues, thanks to a sharp rise in sales, as a supply crunch in Australia pushes prices higher.

Falcon Oil and Gas Australia owns the remaining 30 percent of the joint-venture.

http://www.reuters.com/article/origin-energy-gas-idUSL4N1I70ET

Shell's realised natural gas price in Europe rises in Q1 to $5.08/Mcf

Shell saw its average realised gas price in Europe in the first quarter of 2017 edge up to $5.08/Mcf ($4.94/MMBtu) compared with the previous quarter, the company said in its Q1 earnings statement Thursday.

The gas price increase was triggered by increased demand on cold weather across Europe in January and the early part of February, which saw wholesale gas prices surge.

Its European realised price was $4.94/Mcf in Q4 2016.

However, Shell's realized European price in Q1 was still below the spot price average in Q1.

According to Platts assessments, the Dutch TTF spot price averaged $5.77/MMBtu in Q1, up from $5.41/MMBtu in Q4 2016, while the UK NBP spot price averaged $6.00/MMBtu in Q1 compared with $5.62/MMBtu in Q4 2016.

Shell's European gas price boost helped push its global average realized gas price to $4.29/Mcf in the last quarter, up from $4.03/Mcf in Q4 last year.

Europe accounts for a significant chunk of Shell's gas production -- it averaged 3.43 Bcf/d in Q1 out of a total of 10.94 Bcf/d.

GRONINGEN 'CONVERSATION'

But Shell warned that its gas output in the second quarter would be impacted by some 50,000 b/d of oil equivalent due to the production cap at the giant Groningen field due to the earthquake risk.

CFO Jessica Uhl, speaking to reporters on a webcast later Thursday, said Shell -- which is part of the NAM operating venture with ExxonMobil -- would continue to engage with the Dutch authorities on the subject.

"NAM is an important investment for Shell, and this is a very important issue for the country," Uhl said.

"We are working closely to ensure the asset is operated appropriately and sustainably. We are continuing to engage in that conversation. That's the focus -- meeting the needs of the various stakeholders," she said.

The Dutch government is making preparations to introduce a 10% cut in the production quota for gas from Groningen field from the start of the next gas year on October 1 following an increase in earthquakes in the area around Loppersum.

If adopted, the move would see the production quota cut from the current level of 24 Bcm/year to 21.6 Bcm/year.

In addition, a Dutch appeals court on April 20 ruled that NAM should face an investigation into whether it has been criminally negligent in causing earthquakes in the region.

LNG SALES

Shell, which became a much bigger player in gas with the acquisition last year of the UK's BG Group, is now also a leading LNG company.

LNG liquefaction volumes were 8.18 million mt in Q1, up 16% year on year, but down from 8.57 million mt in the previous quarter.

LNG sales in Q1 were 15.8 million mt, up by 29% year on year and by 3% quarter on quarter.

"Compared with the first quarter 2016, LNG liquefaction volumes mainly reflected the start-up of Gorgon in Australia and the contribution of BG assets for an additional month," Shell said.

"LNG sales volumes mainly reflected increased trading of third-party volumes and higher liquefaction volumes compared with the same quarter a year ago."

https://www.platts.com/latest-news/natural-gas/london/shells-realized-natural-gas-price-in-europe-rises-26728042

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Russia's largest oil producer Rosneft posted a worse than expected rise in first-quarter net income on Friday, hit by a stronger rouble despite higher output and crude prices.

While the price of Russian Urals oil rose 28 percent year on year in rouble terms, Rosneft said that the currency's strength had a negative impact on its performance in the first three months of 2017.

Though a stronger rouble helps to lower payments of debt denominated in foreign currencies, it also reduces revenue from exports.

"The environment remains difficult. Continuing world commodity markets volatility, rouble appreciation -- all of this impacted the company's financial results," Rosneft's Chief Executive Igor Sechin said on Friday.

Net income rose 8.3 percent year on year to 13 billion rubles ($221.4 million), against a consensus forecast of 22 billion rubles among analysts polled by Reuters. [nL8N1I65K4]

Rosneft shares were down 0.6 percent at 308.10 rubles in early trade as Russian assets were pressured by a drop in oil prices amid a global supply glut.

Rosneft also said that first-quarter free cash flow declined by 22.6 percent from a year ago to 89 billion rubles.

The company said on Wednesday that its oil and gas condensate production rose by 13 percent in the first quarter to 4.62 million barrels per day.

http://www.reuters.com/article/us-rosneft-oil-results-idUSKBN1810TM

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Drilling activity in the U.S. has increased yet again, with Baker Hughes weekly rig count reporting seven additional rigs this week. The total number of rigs active in the U.S. is now 877, more than double the 415 rigs that were operating this time last year.

Oil-targeting rigs increased by six this week, totaling 703 rigs. Gas-targeting rigs added two to end the week with 173 active rigs. One “miscellaneous” rig came offline, leaving only one miscellaneous rig active in the U.S.

Four directional and horizontal rigs came online this week, while one vertical rig shut down. Drilling offshore increased, with one “inland waters” and two offshore rigs coming online this week.

Texas again saw the largest increase in rigs, with six added this week bringing its total to 443. Louisiana added four rigs, while Wyoming and Alaska each added two and Colorado and New Mexico each added one. Seven rigs shut down in Oklahoma, and North Dakota and West Virginia both had one rig go offline.

Permian, minor basins add rigs

Rigs moved away from major basins, with only the Permian and the Haynesville adding rigs. Seven additional rigs in the Permian and one more in the Haynesville were offset by four shutdowns in the Cana Woodford, three Marcellus rigs coming offline, and one less in the Ardmore Woodford, Arkoma Woodford, Mississippian and Williston. Ten rigs moved to basins not individually tracked by Baker Hughes.

Canadian rigs continued to decrease, albeit at a slower pace than previous weeks. Three rigs shut down in Canada this week, leaving 82 active. Rigs in Canada have fallen by 77% from a high of 352 in February. This is the standard spring decrease, as seen every year. Historically, the spring drop usually begins to reverse in early May, so Canadian rigs may begin to recover soon.

https://www.oilandgas360.com/u-s-rig-count-climbs-sixteenth-straight-week/

The number of offshore drilling rigs operating in the U.S. waters has climbed this week by two units when compared to the previous week, Baker Hughes reported in its U.S. weekly rig count report.

BHI Rig Count: U.S. +7 to 877 rigs

http://www.offshoreenergytoday.com/weekly-u-s-offshore-rig-count-climbs-to-19-units/

“It will get to a point where it’s actually artificial intelligence that’s drilling our wells for us, with us observing” – Tim Dove, CEO, Pioneer Natural Resources

There are a lot of smart E&P companies rambling around West Texas, the place that has dominated the energy spotlight for the past year or two. Ask anybody who’s been looking at shale: it’s all about the Permian basin.

The basin is booming. It’s crushing most of the others in production numbers, dollars being paid per acre to enter, ability to offer significant stacked pay and strong economics with oil in the $40s-$50. But fast growth comes with plenty of headaches. How are these operators viewing and solving problems they have in common as they step on the Permian accelerator?

Analysts burned up the phone lines on this week’s Q1 earnings calls, asking a lot of questions that brought out sometimes startling viewpoints from some of the top E&P CEOs whose companies are smashing records in the too-hot-to-touch Permian.

How will you source water in the Permian?

Pioneer Natural Resources (ticker: PXD) President and CEO Tim Dove

Q – Jeffrey L. Campbell: On water investment, while the cost savings certainly shouldn’t be ignored, isn’t it fair to see your water effort as necessary to secure supply for future growth? In other words, that it’s an important exercise in risk management?

A – Timothy L. Dove: Well let me put it this way: Water is perhaps the most misunderstood and undervalued aspect of the impediments that the industry could face. As Joey said, when we are today sourcing 350,000 barrels a day, if nothing changes to how we do things, 10 years from now that’s 1.4 million barrels a day. Today we represent 8% of the Permian rig count. So when you start doing the math, you realize, oh my gosh, we’re in a difficult situation to be able to source that kind of water. Which means we’re going to have to go, as I mentioned, more towards the recycling of produced water that also comes back to us after the frac. And so that has to be in our thoughts long term. But I think being ahead of this is tantamount to substantial risk avoidance going forward. We are just not going to be put in a position where we have that kind of impediment that’s unsolvable. We’re solving it ourselves.

WPX Energy (ticker: WPX) Sr. VP and Chief Operating Officer Clay Gaspar, Sr. VP Business Development Bryan Guderian

Kashy Harrison: So, can you update us on just what the A&D market looks like right now in the Delaware for – specifically for acreage swaps to help you build a more contiguous acreage position in the region?

A – Bryan K. Guderian: Sure. I think I’d just start out by saying the availability of acreage for transaction continues to surprise us. The buy-side resilience, I think, continues to surprise us as well. So, near-term, our focus is really what we would call kind of blocking and tackling. We have our footprint in place. We’re really nicely blocked up in Stateline and some of the nearby areas there. We have some other acreage that is a little bit more one-off, but we see really nice opportunities dealing with probably four or five different trading partners in and around Stateline, and in particular, the northern part of the Texas side of our position. And we’ve had some great success already dealing with those folks to block up and drill longer laterals.

Kind of along those lines, we are also finding that there is still some additional acreage, generally smaller tracts, some expirations, still opportunity to bolt-on and add to those positions in small ways. The same is probably true up in New Mexico, although I would say that, given the Federal lands and some of the larger tracts that we deal with in New Mexico that has not been as much of a focus for us recently.

Looking more broadly across the basin, there are a number of fairly sizeable deals that are in the market currently or that we expect to come to market. I’m going to say that they tend to be a little more fringy. There are a couple of deals over in the eastern side of the basin that we would anticipate being marketed this year. I won’t go into names because I don’t know the exact status of those, but likewise still I think some opportunities over on the west side of the basin and obviously we took advantage of one with our Taylor Ranch acquisition.

And then, I would expect to continue seeing some private equity monetization. I think we all realize, we’re probably in the seventh or eighth inning of that process, but, again, the availability of acreage as much as we think we know about the basin, things continue to come to market, but more in small packages at this point.

And I think back to sort of the theme of our story, we’re going to stick to our knitting. We really like the footprint that we have. And so, our primary objective is bolting on and adding efficiency to the position that we already have.

Concho Resources (ticker: CXO) Chairman of the Board, Chief Executive Officer and President Tim Leach

Concho Resources Permian basin acreage

Q – Brian Singer: There have been a couple of acquisitions of assets that would seemingly show up on your maps in Lea and Eddy County. And as a company that’s been very, very active in consolidation, I wonder if you could just talk about your interest in consolidation and why maybe sometimes it does or doesn’t make sense for operators that have acreage in the region to be consolidated in that acreage versus new entrants?

A – Timothy A. Leach: All right. Well, as we’ve highlighted, having big, blocky acreage positions with high ownership is very important to development. So I think you’ll see a lot of trading going on between the big operators to block up their acreage.

When things come up for sale, we have a very high bar on since we have so much opportunity. Things that are contiguous to properties we already own, things that allow us to extend our lateral length are much more valuable to us than kind of scattershot acreage. And also, I’d say with the inventory we have today, it depends on what price you have to pay to get acreage and whether or not we’d be interested in it. So, we’re in a good position to evaluate does making acquisitions add value to our company. And we are very, very focused on these big, blocky, machine-like development projects we’re going to have in the future and making sure that we have all the blocky acreage we need for those things. So, I think we’re in good shape.

As we’ve said in the past, we look at everything in the Permian Basin because it’s our backyard. And so, it’s not unusual for us to be in data rooms and things like that, but we’ve been very picky on what makes sense for us to buy.

https://www.oilandgas360.com/permian-thought-leaders-talk-turkey/

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Profitable WPX Sees 3 Keys for Ramping Up in the Delaware

In today’s conference call, WPX discussed three main requirements for ramping up production.

Geology

First and foremost is the local geology. However, WPX believes that it has mostly solved this question. While spacing and a few other nuances will require further investigation, the geology itself is well-established.

“There is no question,” WPX COO Clay Gaspar commented, “especially where we’re at in the Delaware Basin is world-class rock and there is tons of opportunity.”

Hedging providing confidence

The second primary determining factor for development is commodity price. WPX responded to this factor with aggressive hedging to lock in economic prices. The company has about 72% of its expected 2017 oil production hedged at an average of $50.84/bbl and 76% of its gas production hedged at $3.02/MMBTU. With oil currently trading below $46/bbl, this hedge position is paying off for WPX.

Clay Gaspar remarked that this position gives the company confidence. Mentioning the recent dip in oil prices, Gaspar noted, “I imagine there are a lot of our peers that are fully exposed that are really pulling their hair out, and I can tell you it’s very reassuring to have that confidence to be able to go to the team and say, yep, we’re still doing, [and] go to our key vendors and say, guys, we’re still plowing ahead, stay with us.”

Permian needs takeaway capacity

The massive increase in Permian activity has also created a situation that is usually restricted to the Marcellus. Permian midstream capacity must be able to grow and keep up with development, or Permian producers would be stuck with large differentials like those seen by Marcellus producers.

Gaspar reported that the company has been working on several deals to deal with transportation before it becomes a problem. Most significant among these is a potential midstream joint venture. WPX is considering a JV to handle takeaway from its core Delaware Basin assets, which would ensure transport remained available. While the company declined to provide further details, an agreement is expected midyear.

Multiple Permian acquisitions in Q1

WPX has been very active in the Permian this year, with several major acquisitions. In January the company acquired Panther Energy and Carrier Energy, adding about 120,000 net acres for $775 million. More recently, the company purchased 17,900 acres in Culberson County for $38 million. This acquisition is exploratory in nature, and is farther west than the core of the Delaware Basin. With an acreage cost of about $2,000/acre, however, this is much less expensive than many Permian transactions in recent months.

The company now owns about 135,000 net acres in the Delaware basin, and is producing a total of 90 MBOEPD from its Permian, Bakken and San Juan properties. WPX will spend about $620 million over the rest of the year to grow production by about 20%.

WPX Energy reported first quarter earnings yesterday, showing net income of $88 million, or $0.22 per diluted share. This significantly exceeds the $175 million loss the company took in Q4 2016, or the $17 million loss in Q1 2016.

https://www.oilandgas360.com/profitable-wpx-sees-3-keys-ramping-delaware/

U.S. shale exploration company Marathon Oil Corp reported a smaller-than-expected quarterly loss on Thursday, helped by higher crude prices.

In the wake of rising crude prices, oil and gas producers have increased their capital spending to acquire shale-rich properties, especially in the Permian basin, and have put more rigs back to work.

The company in March bought about 70,000 acres for $1.1 billion, and in a separate deal acquired 21,000 acres for $700 million, both in the top U.S. shale field, the Texas Permian basin.

Average realized prices for crude oil and condensate in North America was $48.46 per barrel in the quarter ended March 31, up from $28.21 a year ago, the company said.

Total production at Marathon Oil averaged 338,000 barrels of oil equivalent per day (boe/d) in the quarter, marginally below the 339,000 boe/d in the year-ago period.

However, the company's net loss widened to $4.96 billion, or $5.84 per share, from $407 million, or 56 cents per share, a year earlier, due to an impairment charge related to the sale of its Canadian oil sands business.

Marathon Oil sold its Canadian oil sands business to Royal Dutch Shell (RDSa.L) in March in a deal valued at $7.25 billion.

Excluding one-time items, the company lost 7 cents per share, beating analysts' average estimate of a loss of 10 cents per share, according to Thomson Reuters I/B/E/S.

Houston-based Marathon Oil's revenue rose 88 percent to $1.07 billion.

http://www.reuters.com/article/us-marathn-oil-results-idUSKBN1802QD

Great Scott! Eclipse Drills New Longest Lateral in World – in Utica

Eclipse Resources, a Marcellus/Utica pure play driller headquartered in State College, PA that drills mostly in Ohio, has done it again. Yesterday as part of Eclipse’s first quarter 2017 update, the company announced it has broken its own record for drilling the longest land-based lateral well in the world by drilling a Utica well with a lateral that’s 19,300 feet long (3.7 miles). Incredible!

You may recall Eclipse was the previous holder of that record with their Purple Hayes well (18,500 feet long), drilled one year ago. Eclipse seems to have taken a chapter from Rice Energy by naming their wells with creative names. Purple Hayes, named after the landowner (Hayes). The new record-holder? Great Scott–presumably named after the landowner (Scott).

Eclipse reports drilling its newest record setting “Super-Lateral” well, the Great Scott 3H, with a total measured depth of 27,400 feet and completable lateral extension of 19,300 feet in less than 17 days from the drill bit hitting the ground to total depth (called spud to TD) in the company’s Utica Shale condensate area.

If you’re an MDN subscriber, you were already expecting this big news. Back in April MDN editor Jim Willis attended the Oil & Gas Investment Symposium in New York City and reported on Eclipse’s session. At the time Jim reported: “They [Eclipse] plan to drill 11 “super lateral” wells that exceed 15,000 feet long. Two wells they hope to drill will break the existing Purple Hayes record–by going to 19,000 feet!”.

Just a month later and the company is already delivering on its promise. Even bigger news: Eclipse is currently drilling a second well of the same length next to Great Scott!

http://marcellusdrilling.com/2017/05/great-scott-eclipse-drills-new-longest-lateral-in-world-in-utica/

TransCanada Corp's quarterly profit more than doubled, as Canada's No. 2 pipeline operator incurred lower charges.

The company's net profit attributable to shareholders rose to C$643 million ($467 million), or 74 Canadian cents per share, in the first quarter ended March 31 from C$252 million, or 36 Canadian cents per share, a year earlier.

The latest quarter included about C$48 million in charges, mainly related to the acquisition of Columbia Pipeline Group. The year-ago quarter included charges of about C$211 million, mainly related to the termination of Alberta power purchase agreements.

Revenue rose 35.5 percent to C$3.39 billion.

http://www.reuters.com/article/transcanada-results-idUSL4N1I73D9