The global oil market is over-supplied by around 1.8 million barrels per day (bpd), but that glut could be halved if a deal to freeze oil production at last month's levels takes effect, a top Russian energy official said on Friday.

Leading OPEC member Saudi Arabia, non-OPEC member Russia, Qatar and Venezuela this week agreed to freeze output at January levels if others joined in. Iran welcomed the move but stopped short of pledging to act itself and it is unclear whether the freeze will actually happen.

"If the agreement is properly fulfilled and it definitively enters into force then around half of that excess supply may be removed from the market," Alexey Texler, Russia's first deputy energy minister, told reporters in the Siberian city of Krasnoyarsk.

"Even without Iran there will be an effect from the agreement. But Iran ... might also be interested in such a deal," he said, noting Tehran had a choice of increasing output at a time of falling prices, or joining the production freeze and potentially getting a higher price for current volumes.

"We are optimistic," he added.

Russia and OPEC were both pumping oil at near record volumes last month, with Russia reaching another post-Soviet high of 10.88 million bpd.

"We are talking about freezing January production levels. It would be higher than the annual average for 2015 by around 1.5 percent," Texler said. Oil production in Russia last year averaged 10.72 million bpd.

The first mooted global oil pact in 15 years will depend on other producers, but it remains unclear which other countries need to sign up for the deal to be implemented.

Asked if Russia will talk to the United States, Brazil, Mexico and Norway, Texler said: "Any country may join. But we are realists and, in general, we understand which countries it will be. Many of those you named, obviously, will not do that."

He added that some producers, still, were uniting round the idea. Texler did not name them.

"We consider such an agreement useful and necessary. It will allow us to forecast the output volumes of key market players, and such an agreement will allow to continue the market process of influencing expensive projects."

The Russian oil industry would "move forward" at a price of $35-40 per barrel this year, Texler said. Earlier on Friday, he said that investment in the Russian energy sector was likely to be lower this year than in 2015.

http://www.reuters.com/article/russia-oil-texler-idUSL8N15Y2GI

Russian President Vladimir Putin and members of his Security Council exchanged views on the situation on global oil markets as Russia's Energy Ministry holds contacts with foreign partners, Interfax quoted the Kremlin's spokesman as saying on Friday.

Russia and Saudi Arabia, along with two other countries, agreed this week to freeze oil output at January levels if other countries joined in.

Dmitry Peskov, the Kremlin spokesman, told reporters earlier there was no link between Syria and oil production in Russia's dialogue with Saudi Arabia.

http://www.reuters.com/article/mideast-crisis-oil-idUSR4N12X02S

What did Chevron accomplish in 2015 by outspending cash flow by $19 billion?

Increase production a paltry 2%. Barely replace reserves-107% of production.

That is what Chevron managed to achieve in 2015 by spending $31 billion while generating just $19 billion of cash flow. And that is actually incredibly bullish, despite the fact that the oil price has come down hard already in 2016.

Investor sentiment-from both the shareholders and the lenders-is forcing ALL producing companies to move closer to spending within cash flow.

What would Chevron's production and reserve growth look like if they do that? I'm guessing it would be MUCH less.

Their capex in 2016 is going down 22% $26.6 billion, but the savior for the company in 2015-its downstream refinery business-is getting crushed right now.

Refinery margins were huge through most of 2015-they contributed $7.6 billion in profits to Chevron in 2015-but crack spreads have recently fallen a lot. And with a glut of some 160 million barrels of refined products in the USA, that won't change much this year. (I got short refineries in January.)

This all reads like bad news, but it's actually very bullish. These numbers say how far the oil price must go up for western companies to make money. And now asset sales are slow, and lowly priced (everyone is a seller), debt is being reined in and equity is a non-starter for all but the best companies.

If That Was 2015 What Is 2016 Going To Look Like?

If you want the truth you have to look directly at the numbers.

Chevron's Q4 and full year 2015 numbers speak volumes. They tell us that something has to give. And as I show you at the bottom here, that may be happening now. In Q4, they generated $4.6 billion in cash flow, and spent $9.4 billion on capital and dividends.

Here is how the full year 2015 cash inflows and outflows look for Chevron:

In Billions                                         2015                   2014
Cash Generated By Operations     $19.5                  $31.5
Capital Expenditures                     ($30.6)               ($36.8)
Dividends Paid                                ($8.0)                 ($7.9)
Share Repurchases                         $0.0                   ($4.4)
Net Cash Outflow                          ($19.1)                ($17.6)


It isn't a pretty picture.

Course summary This module is designed for people interested in the exploration and production of oil and gas who do not have a subsurface technical background. It provides a brief introduction to geology and geophysics for non-ge...

When you include both capex spending and cash required for its dividends, Chevron spent $38.6 billion while generating only $19.5 billion from operations.

That is a net cash outflow of $19.1 billion!

Talk about living beyond your means. The obvious question is how did Chevron finance all of this outspending?

Well, they did it like anyone who lives beyond their means would.

First they dipped into their savings.

Chevron's cash and net working capital balances decreased by $2.6 billion in 2015.

Then they borrowed.

In 2015 Chevron's long term debt increased by $10.8 billion. That is an increase from $27.8 billion to $38.6 billion in total debt.

And then they started selling off some of their belongings.

Proceeds from asset sales in 2015 totaled $5.7 billion.

By massively outspending cash flow, running up debt on its balance sheet and selling assets Chevron managed to maintain its dividend and keep its production basically flat. (At least they didn't spend any money on share buybacks, like the $4.4 billion they did in 2014. Watching these companies buy back stock during the good times when the stock prices are high and then buy back none now must be irksome to more than a few shareholders.)

If Chevron had lived within cash flow, you have to wonder what the dividend might have been and what production and reserve growth would have looked like.

It is not a pretty picture. 2016 is shaping up to be significantly worse considering that oil prices in 2015 were on average $20 per barrel higher than where they sit today.

Last year would have been much worse for Chevron if the company didn't have its own refineries. Chevron's downstream operation (refineries=downstream, pipelines=midstream, producers=upstream) actually benefits from low oil prices and that helped significantly cushion the blow.

Chevron's downstream operations recorded a profit of $7.6 billion in 2015. Without that this company would be in far worse shape.

The Real Battle Is The Fed (Not The Shale Producers) Vs The Saudis

This is what life looks like for Chevron. A company with a very mature low decline production base and the benefit of a profitable downstream operation.

No wonder the shale guys are feeling so much pain. They have young, very high decline production and no diversifying downstream business segment.

Seeing how Chevron allowed its balance sheet to deteriorate in 2015 once again underscores the point....

The biggest threat to the Saudis is not from the shale producers, it is from the Federal Reserve and its ZIRP (zero interest rate policy). Can you imagine Chevron allowing its long term debt to increase by nearly 40% in just one year if interest rates were at 8%?

Chevron's massive outspending in 2015 is how the shale boom was built right from the start. The shale producers had access to billions and billions of dollars of low cost funding.

Low oil prices have ended that party. Reasonable interest rates would have done the same.

What is abundantly clear is that 2016 is going to be a year of very hard decisions for a lot of people in this industry. For Russia and OPEC it is about cutting production.

For Chevron, that hard decision could involve its dividend. If Chevron completely eliminated its dividend in 2015 it would still have outspent cash flow in by $11 billion. That was with considerably higher oil prices.

http://www.oilvoice.com/n/These-Numbers-Show-How-High-Oil-Must-Goand-Fast/89acc1a0d5aa.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

Feb 22 When Sheikh Ali Khalifa al-Sabah of Kuwait thinks about today's plunging oil prices, his mind drifts back to the mid-1980s, when he was forced to sell some of his country's crude for as little as $5 a barrel.

As Kuwait's oil minister at the time, Sheikh Ali had to sell a cargo or two at that price just to keep up cash flow to a country that depended upon oil revenues. "It wasn't because I wanted to; it was because it was the market price," he recalls.

"We really had no alternative."

For oil industry players active during the 1980s bust, the current drop in prices carries echoes of those desperate days. Interviews with some of those involved in that period reveal that while there is little consensus on how long prices will stay depressed, experience suggests the current market glut will not evaporate soon.

Representatives from all aspects of the energy industry will be mulling current low oil prices and the supply glut this week during the IHS CERAWeek gathering in Houston.

Kuwait's struggles in the 1980s are instructive for anyone wondering whether producing countries can tinker their way out of trouble now. In the face of weak prices in the early years of the decade the OPEC production group introduced output cuts in an attempt to mop up oversupply. Kuwait slashed production from nearly 2 million barrels per day to about 600,000 bpd. The top producer Saudi Arabia made even costlier cuts.

Three factors dashed the plan: fellow OPEC members cheated on their own cuts; global thirst for oil had dried up after price spikes in the 1970s pushed consumers to buy efficient cars; and new supplies, particularly from non-OPEC Mexico, Norway, and Alaska threatened to squash gains from any cuts.

By late 1986, Saudi Arabia and other OPEC members opened the taps again to regain market share, and prices did not recover for 20 years.

The memory leaves Sheikh Ali, now 71, feeling grim about a price recovery this time.

"Tomorrow if the price of oil goes down to $20 I would not be surprised," he said. "You don't take excess oil away very quickly. It was true in the 1980s, now it's even worse."

Adrian Lajous was head of crude exports trading for Pemex, Mexico's state oil company in the mid-1980s. He says major oil producers are powerless to tackle the current oversupply by making production cuts, despite an agreement this month between Saudi Arabia and Russia to freeze supply.

Today's bust is driven by uncertainty about demand - mostly China's - and by the threat of a resilient non-OPEC supply, mostly from U.S. shale oil.

http://www.reuters.com/article/ceraweek-glut-idUSL2N15X2RA

Platts JKM for LNG cargoes delivered in April, the new front month, ended the Asian trading week at $4.65/MMBtu Friday, down 5 cents/MMBtu from Tuesday when the assessment for April JKM started.

Platts JKM for March cargoes finished its assessment period Monday at $5.30/MMBtu.

Offers for April cargoes were heard to be in the high $4s/MMBtu by the end of the week while bids were heard to be in the low to mid-$4s/MMBtu.

Expectations that new supply will emerge with new projects such as Australia's Gorgon coming online also weighed on the market.

Throughout the week trade was thin and market participants waited for the results of buy tenders issued by Thailand's PTT and India's Gail.

Thailand's PTT awarded its tender to buy a cargo delivery March 20-28 at slightly below $5/MMBtu to Qatar Gas, according to market sources.

Another tender which drew attention was India's Gail tender, which was awarded at $4.70/MMBtu for one April delivery cargo and at low $5s/MMBtu for two March cargoes.

Another Indian buyer IOC was reportedly awarded an earlier tender that closed on February 2, though details remained scarce.

Meanwhile, Pakistan State Oil cancel led its LNG buy tender for five DES cargoes while Argentina was expected to issue a tender next month for cargoes to meet its summer demand.

In Russia, Sakhalin Energy again postponed the deadline of a sell tender offering one to two cargoes a month over April 2016-March 2017 to March 1. The tender was issued in the week of January 24, with the initial deadline of February 2 postponed to February 24 after a force majeure was declared at the plant in late January.

Sakhalin Energy also moved up the completion data for its repair work to March 4 from the earlier deadline of March 11, sources said.

In other production news, 4.45 million mt/year Peru LNG export plant has resumed normal operations after a month-long unplanned shutdown, a spokesman with US-based Hunt Oil, the plant's operator, said late Wednesday.

And the 3.7 million mt/year Equatorial Guinea LNG plant in West Africa also restarted normal operations after one month of scheduled maintenance, a source close to the facility said Tuesday.

http://www.platts.com/latest-news/natural-gas/tokyo/asia-spot-lng-april-platts-jkm-ends-week-at-465mmbtu-26373907

Pacific Exploration & Production Corp. said holders of a minority of its bonds agreed to hold off on demanding immediate repayment after the driller missed interest payments due last month.

Holders of 42 percent of the 2025 bonds agreed to the extension after a 30-day grace period expire d on a missed January interest payment, according to the statement published Friday. Holders of 34 percent of the 2019 bonds, the grace period on which ends next week, also agreed to the extension. Remaining investors would need the support of 25 percent of a series of notes in order to accelerate the securities, according to the prospectus.

The Bogota-based driller, which trades in Canada and Colombia, is one of the largest independent oil and gas explorers in Latin America. Founded a decade ago by veterans of Venezuela’s oil industry, the company is struggling after crude prices sank to a 12-year low and the contract at its biggest field wasn’t extended past June.

“The extension should allow the company additional time to continue working with the independent committee of the Board of Directors, the company’s financial and legal advisors as well as its lenders and the noteholders to come to a consensual and comprehensive restructuring of the company’s balance sheet,” Chief Executive Officer Ronald Pantin said, according to the statement.

A 30-day grace period after a missed January payment on the 2025 bonds expired Thursday.

Pacific said it’s also in the process of entering into forbearance agreements with its bank lenders. The company’s benchmark $1.3 billion of bonds due 2019 are trading at about 13 cents on the dollar.

Buyout firm EIG Global Energy Partners is offering to buy Pacific’s distressed bonds for 16 cents on the dollar with no accrued interest. While that’s less than a previous bid in January of 17.5 cents plus interest that failed to get much support, EIG says investors would be wise to take the offer as Pacific’s finances will deteriorate further.

Standard & Poor’s lowered the company’s rating to D last month, saying it considered a default to have occurred because it didn’t see the interest being paid within the grace period. S&P said it expected Pacific “to enter into a general default and that it will fail to pay all or substantially all of its obligations as they come due.”

http://www.bloomberg.com/news/articles/2016-02-19/pacific-misses-debt-payment-says-some-investors-grant-extension

Cheniere Energy said it has started producing LNG from the first liquefaction train at its Sabine Pass LNG export terminal in Louisiana.

“Train 1 has begun producing LNG, and the first LNG commissioning cargo is expected to be exported late February or March,” Cheniere said in its fourth-quarter results report on Friday.

The first commissioning cargo from the liquefaction and export facility in Cameron Parish, Louisiana was initially expected to occur by late January. The cargo was delayed due to instrumentation issues that were discovered during the final phases of plant commissioning.

Commissioning for Train 2 at the Sabine Pass plant is expected to commence in the upcoming months, according to Cheniere.

Cheniere is building liquefaction and export facilities at its existing import terminal located along the Sabine Pass River on the border between Texas and Louisiana.

The company plans to construct over time up to six liquefaction trains, which are in various stages of development. Each train is expected to have a nominal production capacity of about 4.5 mtpa of LNG.

Cheniere’s Sabine Pass liquefaction facility will be the first of its kind to export cheap and abundant U.S. shale gas to overseas markets.

Net loss widens

Cheniere reported a net loss of $291 million for the fourth quarter of 2015, compared to a net loss of $159 million for the comparable 2014 period.

For the full- year 2015, the company posted a net loss of $975 million, compared to a net loss of $548 million a year before.

http://www.lngworldnews.com/cheniere-sabine-pass-train-1-starts-producing-lng/

Within weeks, two low-profile legal disputes may determine whether an unprecedented wave of bankruptcies expected to hit U.S. oil and gas producers this year will imperil the $500 billion pipeline sector as well.

In the two court fights, U.S. energy producers are trying to use Chapter 11 bankruptcy protection to shed long-term contracts with the pipeline operators that gather and process shale gas before it is delivered to consumer markets.

The attempts to shed the contracts by Sabine Oil & Gas (SOGCQ.PK) and Quicksilver Resources (KWKAQ.PK) are viewed by executives and lawyers as a litmus test for deals worth billions of dollars annually for the so-called midstream sector.

Pipeline operators have argued the contracts are secure, but restructuring experts say that if the two producers manage to tear up or renegotiate their deals, others will follow. That could add a new element of risk for already hard-hit investors in midstream companies, which have plowed up to $30 billion a year into infrastructure to serve the U.S. fracking boom.

"It's a hellacious problem," said Hugh Ray, a bankruptcy lawyer with McKool Smith in Houston. "It will end with even more bankruptcies."

A judge on New York's influential bankruptcy court said on Feb. 2 she was inclined to allow Houston-based Sabine to end its pipeline contract, which guaranteed it would ship a minimum volume of gas through a system built by a Cheniere Energy (LNG.A) subsidiary until 2024. Sabine's lawyers argued they could save $35 million by ending the Cheniere contract, and then save millions more by building an entirely new system.

Fort Worth, Texas-based Quicksilver's request to shed a contract with another midstream operator, Crestwood Equity Partners (CEQP.N), is set for Feb. 26.

The concerns have grown more evident in recent days, raised in law firms' client memos and investment bank research notes.

Last week, executives from Williams Companies Inc (WMB.N) and Enbridge Inc (ENB.TO), two of the world's largest pipeline operators, sought to allay growing investor fears, saying they were reviewing contracts or securing additional credit guarantees to minimize the impact of the biggest oil bust in a generation.

So far, relatively few oil and gas producers have entered bankruptcy, and most were smaller firms. But with oil prices down 70 percent since mid-2014 and natural gas prices in a prolonged slump, up to a third of them are at risk of bankruptcy this year, consultancy Deloitte said in a Feb. 16 report.

http://www.reuters.com/article/us-usa-oil-lawsuits-idUSKCN0VV0DK

The total number of active, producing oil wells in the U.S. dropped slightly during 2015, a trend that looks set to sharpen this year, as the oil price decline begins to exact its toll on the industry. According to World Oil’s forecast data, the total number of active oil wells declined to 594,436 from 597,281, a 0.5% decline.

http://www.worldoil.com/magazine/2016/february-2016/special-focus/producing-oil-wells-tick-down-as-price-begins-to-hit

An excellent article appearing on the World Oil Magazine website explores an interesting phenomenon at work in the Marcellus/Utica. The article is wide-ranging and provides an update on the activities and strategies for many of our region’s top producers. But the beginning of the article is what really caught our attention.

The author states that there is a shift happening away from drilling in the liquids-rich (i.e. areas with a higher concentration of natural gas liquids, like ethane, propane and others) to the “core” dry gas areas of the Marcellus/Utica. He quotes Rice Energy CEO Dan Rice in saying, “…there has been a noticeable shift in producer activity away from liquids-rich and non-core dry gas Marcellus and Utica areas, and into the Marcellus and Utica’s dry gas cores.”

We have to confess that’s the first time we’d heard that. We thought it was the reverse–that there was more drilling headed to the wet gas areas. Huh.

 http://marcellusdrilling.com/2016/02/drillers-leaving-wet-gas-areas-of-marcellusutica-for-dry-gas/?utm_source=dlvr.it&utm_medium=twitter

The number of rigs drilling for oil in the U.S. dropped by 26 this week, leaving just 413 rigs still seeking crude, according to Baker Hughes data.

Including gas rigs, the overall rig count of 514 rigs is at its lowest point since the last century, specifically 1999.

The total count is rapidly approaching the 1999 low of 488 rigs, which was the lowest point in Baker Hughes’ recorded history. Another drop of 26 rigs would tie the all-time record low.

Analysts expect the rig count to continue falling through much of the first half of the year. The U.S. benchmark for oil continues to hover at about $30 a barrel.

In the first two months of 2016 alone, drillers have mothballed 123 oil rigs. The natural gas rig count dropped by just one this week down to 101 rigs, which already is at a historic low.

Texas is still home to 46 percent of the nation’s operating rigs, but the biggest losses this week came from the Lone Star State. Seven rigs went dark in the Permian Basin and the Eagle Ford shale lost another four rigs. The Permian and Eagle Ford, in that order, are still the most active plays in the country.

The oil rig count is now down nearly 75 percent from its peak of 1,609 in October 2014 before oil prices began plummeting.

http://fuelfix.com/blog/2016/02/19/oil-rig-count-plummets-yet-again/