A recovery in U.S. oil output may deter OPEC and non-OPEC producers from extending production cuts beyond June and might lead to a new price war, Russia's top oil major said on Monday.

U.S. shale oil production had been in retreat as oil prices tumbled from above $100 a barrel in 2014 to below $30 in 2015, making costly fracking processes less profitable.

A deal by the Organization of the Petroleum Exporting Countries with Russia and other producers to rein in output by 1.8 million barrels per day (bpd) for six months from Jan. 1 lifted prices but also encouraged U.S. firms to boost supplies.

"It became evident that U.S. shale oil output has become and will remain a new global oil price regulator for the foreseeable future," Rosneft said in a written response to Reuters.

"There are significant risks the (OPEC-led) deal won't be extended partially because of the main participants, but also because of the output dynamics in the United States, which will not want to join any deals in the foreseeable future."

Russia agreed to join OPEC supply curbs late last year despite initial opposition from Rosneft's boss Igor Sechin, one of President Vladimir Putin's closest allies.

"We think that in the long-term global oil demand dynamics and reduced investment during the period of ultra low prices will balance the market, but that the risk of a price war resuming remains," Rosneft wrote.

Russia has yet to deliver on the pledged cuts, while Saudi Arabia has cut its production far below the levels it had pledged, compensating for waker compliance by other OPEC states.

Rosneft said it came as a surprise to many observers that OPEC's compliance with cuts was more than 90 percent, and said the success was because the Saudi position on reducing production had "changed a great deal" from the past.

The kingdom, the world's biggest oil exporter, had long refused to cut output under veteran oil minister Ali al-Naimi. He was replaced last year by Khalid al-Falih.

"It was Saudi Arabia which initiated the pricing war in the first place with the aim of radically increasing its market share by squeezing out producers of 'costly' oil," Rosneft said, in a reference to shale producers.

"This goal became impossible to reach because of the efficiency and viability of the Russian oil industry," it added.

Naimi had forecast a collapse in output from Russia's mature fields. Instead, production has risen in the past two years to an all-time high of 11.2 million bpd, partly because a devaluation in the rouble reduced production costs.

Rosneft said the only guaranteed route to balance the market was for all producers to limit supplies, but acknowledged this would not happen because U.S. shale producers would not join any such pact. U.S. law bars them from such action.

http://www.reuters.com/article/us-oil-output-russia-idUSKBN16K1MB

Gazprom is ready to comply with EU rules to end a five-year antitrust case and avoid fines, the bloc's competition commissioner said on Monday, signaling a thaw in business ties between Moscow and Brussels despite tensions over Ukraine.

Eight member states in the east, all formerly dominated by Moscow, now have until May 4 to object to the EU executive's view and could try to seek changes in Gazprom's offer.

The Russian state gas exporter, which supplies a third of the EU's gas, has been on the radar of EU regulators since 2012, culminating in charges in April 2015 that it overcharged customers in Central and Eastern Europe and blocked rivals.

Since then, Gazprom has offered concessions aimed at staving off a potential fine of up to 10 percent of its global turnover.

EU Competition Commissioner Margrethe Vestager, who has brought actions and levied fines against major U.S. multinationals such as Google, said Gazprom's offer allayed worries and provided "a forward looking solution".

"Combined we think that these measures are important improvements to ensure the free flow of gas at competitive prices," Vestager said.

Gazprom has agreed to fixed transparent fees and to allow clients the right to price revisions clauses in long-term contracts, EU regulators said.

As part of the deal, Gazprom will also adapt contracts to remove barriers on the free flow of gas across borders and drop clauses in its supply contracts with wholesalers and some industrial customers barring them from exporting its gas to other countries.

Within a bloc divided over its stance on Russia, some EU nations see the move towards a settlement as running counter to calls for more sanctions on Russia over its bombing in Syria.

"The fundamental question is how friendly are we going to be with Gazprom," one senior EU diplomat said. "To some, it looks strange that the Commission is going after Apple and Google but not Gazprom."

Vestager insisted during a news conference that her view was purely based on enforcing EU law and not influenced by politics.

The EU executive is likely to receive tough feedback from the eight states at the heart of the case, with many already locked in a battle with the Commission over what they view as lenient treatment of Gazprom in other cases.

Poland has said it will "play rough" with the EU across the board after a dispute on another matter last week. The other countries being asked for their views on Gazprom are three Baltic states, Bulgaria, Hungary, Slovakia and the Czech Republic.

Vestager responded to criticism by saying the decision was divorced from politics and "would be most helpful to have the future behavior of Gazprom changed".

With a settlement, Russia would accept EU authority in applying competition law - something it has long balked at. If Gazprom failed to comply and meet its commitments, the EU could resort to fines without reopening its case, Vestager said.

http://www.reuters.com/article/us-russia-gazprom-eu-competition-idUSKBN16K15J

Genscape Cushing +1.7mm bbls W/W

 @zerohedge  

U.S. shale oil production in April was set for its biggest monthly increase since October as output in the Permian Basin, America's fastest growing shale oil region, was expected to hit another record high, government data showed on Monday.

Total shale oil production was expected to rise 109,000 barrels per day to 4.96 million bpd, according to the U.S. Energy Information Administration's drilling productivity report.

Oil production in the Permian Basin in Texas and New Mexico, the largest U.S. shale oil field, was set to rise 79,000 bpd to 2.29 million bpd, the highest level on records dating back to 2007.

In the Eagle Ford region in Texas, output was expected to grow nearly 28,000 bpd to 1.14 million bpd, the highest level since November.

Production in the Bakken, however, was set to drop 10,000 bpd to 964,000 bpd, the only month-on-month decline across all seven basins used in the report. That would be the third consecutive monthly decline in the North Dakota basin.

Meanwhile, U.S. natural gas production was projected to increase to a record high 49.6 billion cubic feet per day in April, the EIA said.

That would be up almost 0.6 bcfd from March and would be the fourth monthly increase in a row.

The EIA projected gas output would increase in all of the big shale basins in April, including the Eagle Ford, where production had been declining since January 2016.

Output in the Marcellus formation in Pennsylvania and West Virginia, meanwhile, was set to grow by almost 0.2 bcfd to a record high near 19.2 bcfd in April, a sixth consecutive increase.

EIA also said producers drilled 807 wells and completed 716 in the biggest shale basins in February, leaving total drilled but uncompleted wells (DUCs) up 91 at 5,443, the most since April 2016.

http://www.reuters.com/article/us-usa-oil-productivity-idUSKBN16K2GP

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The presenter who arguably received the best questions at Wednesday’s Crude Oil Quality Association meeting in New Orleans was the US Department of Energy’s economist, Kenneth Vincent.

His presentation was part overview, such as the locations of the four salt caverns that hold the more than 700 million barrels of US oil – Texas and Louisiana, and the maximum drawdown capacity – 4.4 million b/d. But there were also some nuggets not found on factsheets such as the how the physical salt caverns are shrinking due to geological pressures and how “distribution issues are a major concern (for the DOE) currently and going forward.”

Following the presentation, the overflowing room of oil industry participants had plenty of questions for Vincent. And if they didn’t know the answers, and I didn’t know the answers, I reckon you might be interested too:

Q: Are there any restrictions on who you can sell to? Could you export oil anywhere?

A: Vincent said since the US oil export ban has been lifted, the office received a legal opinion that it can’t export but it can sell to anyone, who can then export it.

Q: Do you look at the type of oil you are storing so that it is what we need when the time comes?

A: “Yes,” Vincent said, which got some chuckles from the crowd.

After a brief pause he continued to say the strategic petroleum reserve stores about 60% medium sour and 40% sweet crudes that are amalgams from a bunch of different streams.

“Our goal is to have oil as fungible as possible and support as many types as possible.”

He said a common question is if the SPR should focus more on heavy oils, which account for a bulk of imports and are consumed by USGC refineries. However, he said no, that SPR isn’t focusing on adding more heavy oils. He said that heavy oil is “really hard” to store for long periods of time and that there is a lot more sweet oil going into the US refinery fleet.

“We ultimately decided we weren’t going to put a big stake in the ground for changing the type of oil in the reserve but that is something we follow very closely.”

Q: Do you consider the price of specific crude grades when making sales from the SPR?

A: “Yes. Absolutely.”

Vincent said there is a very rigorous process in place in trying to maximize returns for taxpayers.

Q: Does the DOE have any input on pipeline reversals?

A: “Absolutely not,” Vincent said. “We have no say.”

http://blogs.platts.com/2017/03/10/doe-economist-spr-exports-storage-sales/

It’s small when you compare it to the top ten largest U.S. refineries, most located on the Gulf coast, all having capacities between 300,000 barrels and half a million barrels per day, but a small Texas-based energy company has announced its intention to build a 50,000-barrels per day crude oil refinery in a well-selected location: in the heart of the Permian basin.

MMEX Resources Corporation (ticker: MMEX) said it will need $450 million to build the proposed refinery 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad. MMEX said the 250-acre facility intends to utilize its connection to existing railways to export diesel, gasoline, and jet fuels; liquefied petroleum gas; and crude oil to western Mexico and South America.

Why is this important?

Because the Permian basin, and the Midland basin within it, are extremely fast growing oil plays in which many independent E&Ps can drill wells, produce oil economically at today’s commodities prices—or at least at last week’s oil prices. (Prices for West Texas Intermediate dipped below $49 this week after a larger than expected inventory build, following a consistent ride in the $50-$54 per barrel range in recent weeks.) But takeaway capacity is not keeping up with the Permian basin’s growing oil production.

Calling the Wolfcamp “the largest estimate of continuous oil that the USGS has ever assessed in the United States,” the USGS last fall pegged the Wolfcamp formation in the Midland basin at 20 billion barrels. E&Ps have cemented the reputation by making the Permian a favorite target of M&A and A&D activity. And rig counts have been growing fast.

MMEX Resources President & CEO Jack Hanks said, “The existing facilities and pipeline networks are largely unequipped to handle this growth and are limiting where products can be transported. By building a state-of-the-art refinery along the region’s existing railway infrastructure, we hope to bring a local and export market for crude oil and refined products.”

MMEX said it plans to surround the Pecos County refinery with an additional 250 acres of buffer property and leverage state-of-the-art emissions technologies to yield minimal environmental impact. It also expects to feature closed-in water and air-cooling systems, which will require very little local water resources.

The company anticipates the 18-month construction process will create approximately 400 jobs in the area during peak construction, as well as foster a significant number of indirect jobs and revenue for companies in catering, workforce housing, construction, equipment and other industries.

Once operational, the facility is expected to provide an estimated 100 permanent jobs and generate substantial tax revenue for Pecos County, the company said.

MMEX purchased the rights to the project from Maple Resources Corporation. Construction is slated to begin in early 2018, following the permitting process, and the facility is projected to begin operations in 2019.

MMEX is involved in oil, gas, refining and electric power projects in Texas, Peru, and other countries in Latin America. The company’s ability to build the proposed Permian refinery is subject to the receipt of required governmental permits and completion of required debt and equity financing, MMEX said.

http://www.oilandgas360.com/proposed-permian-refinery-could-take-50000-bopd-from-west-texas-producers/

Planning in the supply chain: industry expects service costs to rise 10%-15%, but WPX has a firm handle on costs in the Permian

Everyone knew it would happen eventually: service costs are going on the rise. Halliburton talked about it as early as July of 2016, and over the course of the EnerCom Dallas oil and gas investment conference we heard it again and again.

As activity continues to pick up on the drilling side of the equation, E&P companies need more services from the oilfield side of the industry. After two years of layoffs and slower drilling programs that will translate into more demand for fewer crews and less equipment, which is starting to play out in a 10%-15% expected increase in service costs for the coming year, according to a number of sources ranging from E&P decision makers to buyside and sellside analysts.

Nowhere is this becoming more apparent than in the Permian, where strong returns have attracted a rush of capital and drilling activity outpaces the next most active basin by 4.5 times, according to information from Baker Hughes Industries . Many companies had the forethought to plan ahead, though, and they intend to reap the rewards moving forward.

WPX Energy operates in the Delaware Basin, right at the heart of the Permian, and the company has been able to contract approximately 70% of its drilling and completion costs through 2017, mitigating the company’s exposure to service cost inflation.

To better understand how WPX keeps its service costs in check in the most active oilfield in the U.S., Oil & Gas 360® spoke with WPX Director of E&P Services Alan Killion about the company’s supply chain management.

WPX Energy offers insight into what it takes to manage costs in the Permian Basin

“WPX has been proactive over the past year to work with the service providers on longer-term partnerships that are shielding WPX from the brisk pace of inflation,” said Killion. “Our goals are to find partners who want to grow with WPX long-term. Contracting with those companies requires an understanding of not only the current marketplace but also an alignment of goals.”

At WPX, Killion’s group specializes in contracts, negotiating, analytics and technical aspects, such as understanding the pipe market all the way back to the mill, according to WPX. Killion’s experience as both a production engineer and trader for Occidental Petroleum  before moving into his role at WPX made him the right fit to understand markets and develop those partnerships.

“The environment at WPX is an advantage because there’s so much emphasis on planning and forecasting. Since things are more predictable, we can make more of an impact,” said Killion.”

Stimulation services and sand look to be the most pressing matters for now

“The stimulation side of the business has seen the most constraint in the supply chain.  As we know from economics, anytime there’s a constraint in an area we tend to see inflationary dynamics,” explained Killion.

“Pressure pumping crews are in short supply. We estimate that the market is approximately at a 95% utilization rate.  Until future crews hit the market, pricing in the marketplace will be pressured. We have seen the pressure pumping market increase approximately 250% to 300% for horsepower since Q4 2016.  As companies continue to add crews some of the price inflation will start to subside.”

Sand will also continue to be a source of cost inflation for many companies moving forward. “Current sand capacity is listed at 110 million tons per year. In 2016, demand was approximately 40 million tons per year.  2017 projections are around 50 million tons per year, with 2018 pushing more toward 80 million tons,” said Killion, but those numbers include all types of sand, not just the fine sand that is in high demand for the increasingly intense frac jobs completed across the United States.

Sand has seen 75%-100% inflation since late 2016

“With this move to finer sand types, longer laterals and higher proppant concentrations, the sand market has experienced inflation of 75%-100% since late in 2016,” said Killion. “We see the same dynamics starting to occur in the OCTG (Oil Country Tubular Goods) market as well.”

Because of the increasing demand in those particular areas, WPX worked to ensure that it would have long-term contracts to mitigate as much inflation as possible, explained Killion. “WPX has hydraulic horsepower and frac sand contracts in place into 2018.”

Killion and his team expect to see similar increases in service cost across all basins, as well. “We have seen the inflation agnostic to basins at this time.  As frac crews and frac sand is somewhat fungible, these services try to migrate toward the most active basins when possible,” he explained.

Don’t discount continued improvements in efficiency

Many E&P companies are already including the 10%-15% increase in service costs in their forward-looking projections, but that does not mean that drilling and completion costs will rise in lock-step with price inflation. Companies continue to improve their drilling designs and increase the speed at which they can drill higher-performing wells.

“It is somewhat difficult to say [what a 10% to 15% increase in service costs would mean for well economics] because each basin and each formation holds different economics, but it could wind up being a wash when you think about how much better we’re getting on the performance side,” said Killion. “The industry continues to find ways to drill and complete wells that yield reduced drill times and increased EURs.

“WPX continues to set the bar higher on each of these fronts.

“Last year we raised EURs in all three of our basins. And we completed a 16-day well in the Permian, and we’re still in the early learning phase. We also reduced drilling times in the Bakken by 5 days from 2015 to 2016. We have seen approximately 10% to 15% increase in the number of stages our stimulation partners can frac in a single day.  These improvements should offset inflation at a minimum,” he said.

It’s all about communication and credibility

Successfully finding the sweet spot between supply chain management, operations and vendors will help Killion and his team continue to improve WPX’s supply chain moving forward, he explained.

“The two most critical pieces to making everything work are the 2 Cs – communication and credibility,” said Killion. “That ongoing, open dialogue is paramount, and the supply chain management team has to be credible and earn the trust of operations. We are not the tail wagging the dog. Our role is to support our asset teams and their business objectives. We make recommendations. They make decisions.”

http://www.oilandgas360.com/wpx-energy-keeping-permian-basin-service-costs-check-oil-gas-360-exclusive/

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The Hague-based LNG giant Shell said on Friday it is ending development of the proposed Prince Rupert liquefied natural gas export project in Canada’s British Columbia.

BG International Limited, a member of the Shell Group, confirmed in a statement that the company would discontinue development of the proposed LNG project, located on Ridley Island at the Port of Prince Rupert.

Acquired as part of the Shell and BG Group combination in 2016, the Prince Rupert LNG project has been part of a global portfolio review of combined assets, which resulted in the decision to discontinue further development, the statement said.

“During the global portfolio review the local project team has continued to engage locally and to support environmental initiative and social investment activities in the area,” the statement said.

The Prince Rupert office will remain open through May 2017 to complete community engagement.

Prince Rupert LNG was planned to be developed in two phases with a production capacity of up to 21 million tonnes of LNG per year. Natural gas to the Ridley Island facility would have been received from northeast British Columbia via pipeline.

The project received authorization in April 2014 from the National Energy Board to export LNG from the proposed liquefaction facility.

http://www.lngworldnews.com/shell-shelves-prince-rupert-lng-project-in-british-columbia/

News Release – TransCanada Corporation (TransCanada) today announced the successful conclusion of a long-term, fixed-price Open Season to transport natural gas on the Canadian Mainline from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The company confirmed that its recent Open Season resulted in binding, long-term contracts from Western Canada Sedimentary Basin (WCSB) gas producers to transport 1.5 PJ/d of natural gas at a simplified toll of $0.77/GJ.

“Today, WCSB producers are facing a much more challenging landscape than they have in the past. This new offering helps our customers compete more effectively by utilizing existing capacity on the Canadian Mainline, and demonstrates the importance and value of this system to deliver their products to markets in Eastern Canada and the Northeast U.S.,” said Russ Girling, president and chief executive officer, TransCanada.

“This long-term agreement provides significant benefits for our customers, shareholders, communities and governments that depend on the economic benefits that are generated by natural gas exploration, production and transportation,” added Girling. “In addition to utilizing existing capacity and pipelines already in operation, the incremental revenue generated from this offering will make the Canadian Mainline more competitive.”

Key highlights of the Revised Long-Term Fixed Pricing Open Season:

Collectively, customers have signed long-term binding contracts to transport 1.5 PJ/d of natural gas from the Empress receipt point in Alberta to the Dawn hub in southern Ontario, at a single toll of $0.77/GJ.
The term of the contract is 10 years and has early termination rights that can be exercised following the initial five years of service (upon payment of an increased toll for the final two years of the contract).
The service can be provided entirely with existing facilities.
The targeted in-service date is November 1, 2017. The company intends to file an application for regulatory approval with the National Energy Board in April 2017.

Today, TransCanada transports more than 25 per cent of the natural gas consumed across North America, and millions of people rely on the energy we deliver every day to heat and cool their homes, fuel industries and generate reliable sources of power, and the Canadian Mainline is a critical piece of energy infrastructure that allows this to happen. The Canadian Mainline is a regulated cost of service system that currently transports about 20 per cent of the natural gas produced in the WCSB to serve Canadian markets and interconnects with the U.S.

http://boereport.com/2017/03/13/transcanada-announces-successful-canadian-mainline-open-season-results/