Tag Archives: Midland

West Texas Bust – “We Never Expected The Good Times To End”

The residents of West Texas are accustomed to a life dependent on hydrocarbons. As Bloomberg reports, the small communities built into the flat West Texas desert are dotted with oil pumps and rigs, and the chemical smell of an oil field hangs in the air.

Here the economy rises and falls on drilling.

When the drilling is good, everyone in the town benefits. When it’s bad, most of West Texas feels the pinch.

Oil prices have plunged as much as 75 percent since June 2014. That drop has dismal consequences for residents, and not just the ones working in oil fields. Bloomberg spoke with some of the people trying to endure the historic dip in oil prices. This video tells some of their stories….

In sharp contrast, click the following to enjoy this bitter sweet October, 2013 oil boom report by (CNN Money) titled ‘Moving in droves’ to Midland, Texas

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Junk-Rated Oil & Gas Companies in a “Liquidity Death Spiral”

by Wolf Richter

https://ashwinikumar007.files.wordpress.com/2011/06/blackmoney.jpg?w=355&h=284

On the face of it, the oil price appears to be stabilizing. What a precarious balance it is, however.

Behind the facade of stability, the re-balancing triggered by the price collapse has yet to run its course, and it might be overly optimistic to expect it to proceed smoothly. Steep drops in the US rig count have been a key driver of the price rebound. Yet US supply so far shows precious little sign of slowing down. Quite to the contrary, it continues to defy expectations.

So said the International Energy Agency in its Oil Market Report on Friday. West Texas Intermediate plunged over 4% to $45 a barrel.

The boom in US oil production will continue “to defy expectations” and wreak havoc on the price of oil until the power behind the boom dries up: money borrowed from yield-chasing investors driven to near insanity by the Fed’s interest rate repression. But that money isn’t drying up yet – except at the margins.

Companies have raked in 14% more money from high-grade bond sales so far this year than over the same period in 2014, according to LCD. And in 2014 at this time, they were 27% ahead of the same period in 2013. You get the idea.

Even energy companies got to top off their money reservoirs. Among high-grade issuers over just the last few days were BP Capital, Valero Energy, Sempra Energy, Noble, and Helmerich & Payne. They’re all furiously bringing in liquidity before it gets more expensive.

In the junk-bond market, bond-fund managers are chasing yield with gusto. Last week alone, pro-forma junk bond issuance “ballooned to $16.48 billion, the largest weekly tally in two years,” the LCD HY Weekly reported. Year-to-date, $79.2 billion in junk bonds have been sold, 36% more than in the same period last year.

But despite this drunken investor enthusiasm, the bottom of the energy sector – junk-rated smaller companies – is falling out.

Standard & Poor’s rates 170 bond issuers that are engaged in oil and gas exploration & production, oil field services, and contract drilling. Of them, 81% are junk rated – many of them deep junk. The oil bust is now picking off the smaller junk-rated companies, one after the other, three of them so far in March.

On March 3, offshore oil-and-gas contractor CalDive that in 2013 still had 1,550 employees filed for bankruptcy. It’s focused on maintaining offshore production platforms. But some projects were suspended last year, and lenders shut off the spigot.

On March 8, Dune Energy filed for bankruptcy in Austin, TX, after its merger with Eos Petro collapsed. It listed $144 million in debt. Dune said that it received $10 million Debtor in Possession financing, on the condition that the company puts itself up for auction.

On March 9, BPZ Resources traipsed to the courthouse in Houston to file for bankruptcy, four days after I’d written about its travails; it had skipped a $60 million payment to its bondholders [read… “Default Monday”: Oil & Gas Companies Face Their Creditors].

And more companies are “in the pipeline to be restructured,” LCD reported. They all face the same issues: low oil and gas prices, newly skittish bond investors, and banks that have their eyes riveted on the revolving lines of credit with which these companies fund their capital expenditures. Being forever cash-flow negative, these companies periodically issue bonds and use the proceeds to pay down their revolver when it approaches the limit. In many cases, the bank uses the value of the company’s oil and gas reserves to determine that limit.

If the prices of oil and gas are high, those reserves have a high value. It those prices plunge, the borrowing base for their revolving lines of credit plunges. S&P Capital IQ explained it this way in its report, “Waiting for the Spring… Will it Recoil”:

Typically, banks do their credit facility redeterminations in April and November with one random redetermination if needed. With oil prices plummeting, we expect banks to lower their price decks, which will then lead to lower reserves and thus, reduced borrowing-base availability.

April is coming up soon. These companies would then have to issue bonds to pay down their credit lines. But with bond fund managers losing their appetite for junk-rated oil & gas bonds, and with shares nearly worthless, these companies are blocked from the capital markets and can neither pay back the banks nor fund their cash-flow negative operations. For many companies, according to S&P Capital IQ, these redeterminations of their credit facilities could lead to a “liquidity death spiral.”

Alan Holtz, Managing Director in AlixPartners’ Turnaround and Restructuring group told LCD in an interview:

We are already starting to see companies that on the one hand are trying to work out their operational problems and are looking for financing or a way out through the capital markets, while on the other hand are preparing for the events of contingency planning or bankruptcy.

Look at BPZ Resources. It wasn’t able to raise more money and ended up filing for bankruptcy. “I think that is going to be a pattern for many other companies out there as well,” Holtz said.

When it trickled out on Tuesday that Hercules Offshore, which I last wrote about on March 3, had retained Lazard to explore options for its capital structure, its bonds plunged as low as 28 cents on the dollar. By Friday, its stock closed at $0.41 a share.

When Midstates Petroleum announced that it had hired an interim CEO and put a restructuring specialist on its board of directors, its bonds got knocked down, and its shares plummeted 33% during the week, closing at $0.77 a share on Friday.

When news emerged that Walter Energy hired legal counsel Paul Weiss to explore restructuring options, its first-lien notes – whose investors thought they’d see a reasonable recovery in case of bankruptcy – dropped to 64.5 cents on the dollar by Thursday. Its stock plunged 63% during the week to close at $0.33 a share on Friday.

Numerous other oil and gas companies are heading down that path as the oil bust is working its way from smaller more vulnerable companies to larger ones. In the process, stockholders get wiped out. Bondholders get to fight with other creditors over the scraps. But restructuring firms are licking their chops, after a Fed-induced dry spell that had lasted for years.

Investors Crushed as US Natural Gas Drillers Blow Up

by Wolf Richter

The Fed speaks, the dollar crashes. The dollar was ripe. The entire world had been bullish on it. Down nearly 3% against the euro, before recovering some. The biggest drop since March 2009. Everything else jumped. Stocks, Treasuries, gold, even oil.

West Texas Intermediate had been experiencing its biggest weekly plunge since January, trading at just above $42 a barrel, a new low in the current oil bust. When the Fed released its magic words, WTI soared to $45.34 a barrel before re-sagging some. Even natural gas rose 1.8%. Energy related bonds had been drowning in red ink; they too rose when oil roared higher. It was one heck of a party.

But it was too late for some players mired in the oil and gas bust where the series of Chapter 11 bankruptcy filings continues. Next in line was Quicksilver Resources.

It had focused on producing natural gas. Natural gas was where the fracking boom got started. Fracking has a special characteristic. After a well is fracked, it produces a terrific surge of hydrocarbons during first few months, and particularly on the first day. Many drillers used the first-day production numbers, which some of them enhanced in various ways, in their investor materials. Investors drooled and threw more money at these companies that then drilled this money into the ground.

But the impressive initial production soon declines sharply. Two years later, only a fraction is coming out of the ground. So these companies had to drill more just to cover up the decline rates, and in order to drill more, they needed to borrow more money, and it triggered a junk-rated energy boom on Wall Street.

At the time, the price of natural gas was soaring. It hit $13 per million Btu at the Henry Hub in June 2008. About 1,600 rigs were drilling for gas. It was the game in town. And Wall Street firms were greasing it with other people’s money. Production soared. And the US became the largest gas producer in the world.

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But then the price began to plunge. It recovered a little after the Financial Crisis but re-plunged during the gas “glut.” By April 2012, natural gas had crashed 85% from June 2008, to $1.92/mmBtu. With the exception of a few short periods, it has remained below $4/mmBtu – trading at $2.91/mmBtu today.

Throughout, gas drillers had to go back to Wall Street to borrow more money to feed the fracking orgy. They were cash-flow negative. They lost money on wells that produced mostly dry gas. Yet they kept up the charade. They aced investor presentations with fancy charts. They raved about new technologies that were performing miracles and bringing down costs. The theme was that they would make their investors rich at these gas prices.

The saving grace was that oil and natural-gas liquids, which were selling for much higher prices, also occur in many shale plays along with dry gas. So drillers began to emphasize that they were drilling for liquids, not dry gas, and they tried to switch production to liquids-rich plays. In that vein, Quicksilver ventured into the oil-rich Permian Basin in Texas. But it was too little, too late for the amount of borrowed money it had already burned through over the years by fracking for gas below cost.

During the terrible years of 2011 and 2012, drillers began reclassifying gas rigs as rigs drilling for oil. It was a judgement call, since most wells produce both. The gas rig count plummeted further, and the oil rig count skyrocketed by about the same amount. But gas production has continued to rise since, even as the gas rig count has continued to drop. On Friday, the rig count was down to 257 gas rigs, the lowest since March 1993, down 84% from its peak in 2008.

US-rig-count_1988_2015-03-13=gas

Quicksilver’s bankruptcy is a consequence of this fracking environment. It listed $2.35 billion in debts. That’s what is left from its borrowing binge that covered its negative cash flows. It listed only $1.21 billion in assets. The rest has gone up in smoke.

Its shares are worthless. Stockholders got wiped out. Creditors get to fight over the scraps.

Its leveraged loan was holding up better: the $625 million covenant-lite second-lien term loan traded at 56 cents on the dollar this morning, according to S&P Capital IQ LCD. But its junk bonds have gotten eviscerated over time. Its 9.125% senior notes due 2019 traded at 17.6 cents on the dollar; its 7.125% subordinated notes due 2016 traded at around 2 cents on the dollar.

Among its creditors, according to the Star Telegram: the Wilmington Trust National Association ($361.6 million), Delaware Trust Co. ($332.6 million), US Bank National Association ($312.7 million), and several pipeline companies, including Oasis Pipeline and Energy Transfer Fuel.

Last year, it hired restructuring advisers. On February 17, it announced that it would not make a $13.6 million interest payment on its senior notes and invoked the possibility of filing for Chapter 11. It said it would use its 30-day grace period to haggle with its creditors over the “company’s options.”

Now, those 30 days are up. But there were no other “viable options,” the company said in the statement. Its Canadian subsidiary was not included in the bankruptcy filing; it reached a forbearance agreement with its first lien secured lenders and has some breathing room until June 16.

Quicksilver isn’t alone in its travails. Samson Resources and other natural gas drillers are stuck neck-deep in the same frack mud.

A group of private equity firms, led by KKR, had acquired Samson in 2011 for $7.2 billion. Since then, Samson has lost $3 billion. It too hired restructuring advisers to deal with its $3.75 billion in debt. On March 2, Moody’s downgraded Samson to Caa3, pointing at “chronically low natural gas prices,” “suddenly weaker crude oil prices,” the “stressed liquidity position,” and delays in asset sales. It invoked the possibility of “a debt restructuring” and “a high risk of default.”

But maybe not just yet. The New York Post reported today that, according to sources, a JPMorgan-led group, which holds a $1 billion revolving line of credit, is granting Samson a waiver for an expected covenant breach. This would avert default for the moment. Under the deal, the group will reduce the size of the revolver. Last year, the same JPMorgan-led group already reduced the credit line from $1.8 billion to $1 billion and waived a covenant breach.

By curtailing access to funding, they’re driving Samson deeper into what S&P Capital IQ called the “liquidity death spiral.” According to the New York Post’s sources, in August the company has to make an interest payment to its more junior creditors, “and may run out of money later this year.”

Industry soothsayers claimed vociferously over the years that natural gas drillers can make money at these prices due to new technologies and efficiencies. They said this to attract more money. But Quicksilver along with Samson Resources and others are proof that these drillers had been drilling below the cost of production for years. And they’d been bleeding every step along the way. A business model that lasts only as long as new investors are willing to bail out old investors.

But it was the crash in the price of “liquids” that made investors finally squeamish, and they began to look beyond the hype. In doing so, they’re triggering the very bloodletting amongst each other that ever more new money had delayed for years. Only now, it’s a lot more expensive for them than it would have been three years ago. While the companies will get through it in restructured form, investors get crushed.


Oil Production Falling In Three Big Shale Plays, EIA Says

HOUSTON – It’s official: The shale oil boom is starting to waver.

And, in a way, it may have souped-up rigs and more efficient drilling technologies to thank for that.

Crude production at three major U.S. shale oil fields is projected to fall this month for the first time in six years, the U.S. Energy Information Administration said Tuesday.

It’s one of the first signs that idling hundreds of drilling rigs and billions of dollars in corporate cutbacks are starting to crimp the nation’s surging oil patch.

But it also shows that drilling technology and techniques have advanced to the point that productivity gains may be negligible in some shale plays where horizontal drilling and hydraulic fracturing have been used together for the past several years.

Because some plays are already full of souped-up horizontal rigs, oil companies don’t have as many options to become more efficient and stem production losses, as they did in the 2008-2009 downturn, the EIA said.

The EIA’s monthly drilling productivity report indicates that rapid production declines from older wells in three shale plays are starting to overtake new output, as oil companies drill fewer wells.

In the recession six years ago, the falling rig count didn’t lead to declining production because new technologies boosted how fast rigs could drill wells.

But now that oil firms have figured out how to drill much more efficiently, “it is not clear that productivity gains will offset rig count declines to the same degree as in 2008-09,” the EIA said.

Energy Information Agency

Overall, U.S. oil production is set to increase slightly from March to April to 5.6 million barrels a day in six major fields, according to the EIA.

But output is falling in the Eagle Ford Shale in South Texas, North Dakota’s Bakken Shale and the Niobrara Shale in Colorado, Wyoming, Nebraska and Kansas.

In those three fields, net production is expected to drop by a combined 24,000 barrels a day.

The losses were masked by production gains in the Permian Basin in West Texas and other regions.

Efficiency improvements are still emerging in the Permian, faster than in other oil fields because the region was largely a vertical-drilling zone as recently as December 2013, the EIA said.

Net crude output in the Bakken is expected to decline by 8,000 barrels a day from March to April. In the Eagle Ford, it’s slated to fall by 10,000 barrels a day. And in the Niobrara, production will dip by roughly 5,000 barrels a day.

But daily crude output jumped by 21,000 barrels in the Permian and by 3,000 barrels in the Utica Shale in Ohio and Pennsylvania.

Read more at MRT.com

Texas Home Buyers Are Better Off Than National Average

by Rye Durzin

Texas homebuyers

The March 2015 Texas Home buyers and Sellers Report from the Texas Association of Realtors shows that between July 2013 and June 2014 median household income for Texas home buyers increased 5.9 percent year-over-year compared with a national increase of only 1.4 percent.

Home buyers in Texas are older, more likely to be married and make more money than the national averages, according to the March 2015 Texas Home buyers and Sellers Report from the Texas Association of Realtors.

The study shows that between July 2013 and June 2014 median household income for Texas home buyers increased 5.9 percent year-over-year compared with a national increase of only 1.4 percent. However, the percentage of first-time home buyers in Texas fell 4 points to 29 percent, compared to a 5 percent decline nationally to 33 percent.

Home buyers in Texas are also two years older compared to the previous period, edging up to 45 years of age, and 72 percent of home buyers are married, compared to 65 percent nationally.

Texans are also buying larger and newer homes than other buyers across the U.S. In Texas, the typical three-bedroom, two-bathroom home had 2,100 square feet and was built in 2002, compared to the typical national home built in 1993 with 1,870 square feet.

Forty-seven percent of first-time home buyers in Texas said that finding the right property was the most difficult step in buying a home, as did 48 percent of repeat home buyers.

For Texans selling homes, 21 percent said that the reason for selling was because of job relocation, followed by 16 percent who said that their home was too small. The median household income for a Texas home seller was $120,800, compared with a national media income of $96,700 among home sellers.

Texas home buyers (overall): July 2013 – June 2014

  • Median household income: +5.9% to $97,500
  • Percent of homes bought that were new: 28% (-1% from July 2012 – June
  • 2013)
  • Percentage of first-time home buyers: 29% (-4% from July 2012 – June
  • 2013)
  • Age of typical home buyer: 45 years old (+2 years from July 2012 – June 2013)
  • Average age of first-time home buyer: 32 years old (+1 year from July
  • 2012 – June 2013)
  • Average age of repeat home buyer: 50 years old (unchanged from July 2012 – June 2013)
  • Median household income for first-time home buyers: +5.8% to $72,000 (compared to July 2012 – June 2013)
  • Median household income for repeat home buyers: -8.9% to $97,500 (compared to July 2012 – June 2013)
  • Percent of married home buyers: 72% (+1% from July 2012 – June 2013)
  • New homes purchased: 28% (-2% from July 2012 – June 2013)
  • Median household income for home sellers: $120,800
  • Age of average home seller: 49 years

National home buyers (overall): June 2013 – July 2014

  • Median household income: +1.4% to $84,500
  • Percent of homes bought that were new: 16% (constant from July 2012 – June 2013)
  • Percentage of first-time home buyers: 33% (-5% from July 2012 – June 2013)
  • Age of typical home buyer: 44 years old (+2 years from July 2012 – June
  • 2013)
  • Average age of first-time home buyer: 31 years old (unchanged from July
  • 2012 – June 2013)
  • Average age of repeat home buyer: 53 years old (+1 year from July 2012 – June 2013)
  • Median household income for first-time home buyers: +2.3% to $68,300 (compared to July 2012 – June 2013)
  • Median household income for repeat home buyers: -1% to $95,000 (compared to July 2012 – June 2013)
  • Percent of married home buyers: 65% (-1% from July 2012 – June 2013)
  • New homes purchased: 16% (unchanged from July 2012 – June 2013)
  • Median household income for home sellers: $96,700
  • Age of average home seller: 54 years

Increasing Rent Costs Present a Challenge to Aspiring Homeowners

https://i1.wp.com/dsnews.com/wp-content/uploads/sites/25/2013/12/rising-arrows-two.jpgby Tory Barringer

Fast-rising rents have made it difficult for many Americans to save up a down payment for a home purchase—and experts say that problem is unlikely to go away any time soon.

Late last year, real estate firm Zillow reported that renters living in the United States paid a cumulative $441 billion in rents throughout 2014, a nearly 5 percent annual increase spurred by rising numbers of renters and climbing prices. Last month, the company said that its own Rent Index increased 3.3 percent year-over-year, accelerating from 2013 even as home price growth slows down.

Results from a more recent survey conducted by Zillow and Pulsenomics suggest that rent prices will continue to be a problem for the aspiring homeowner for years to come.

Out of more than 100 real estate experts surveyed, 51 percent said they expect rental affordability won’t improve for at least another two years, Zillow reported Friday. Another 33 percent were a little more optimistic, calling for a deceleration in rental price increases sometime in the next one to two years.

Only five percent said they expect affordability conditions to improve for renters within the next year.

Despite the challenge that rising rents presents to home ownership throughout the country, more than half—52 percent of respondents—said the market should be allowed to correct the problem on its own, without government intervention.

“Solving the rental affordability crisis in this country will require a lot of innovative thinking and hard work, and that has to start at the local level, not the federal level,” said Zillow’s chief economist, Stan Humphries. “Housing markets in general and rental dynamics in particular are uniquely local and demand local, market-driven policies. Uncle Sam can certainly do a lot, but I worry we’ve become too accustomed to automatically seeking federal assistance for housing issues big and small, instead of trusting markets to correct themselves and without waiting to see the impact of decisions made at a broader local level.”

On the topic of government involvement in housing matters: The survey also asked respondents about last month’s reduction in annual mortgage insurance premiums for loans backed by the Federal Housing Administration (FHA). The Obama administration has projected that the cuts will help as many as 250,000 new homeowners make their first purchase.

The panelists were lukewarm on the change: While two-thirds of those with an opinion said they think the changes could be “somewhat effective in making homeownership more accessible and affordable,” just less than half said the new initiatives are unwise and potentially risky to taxpayers.

Finally, the survey polled panelists on their predictions for U.S. home values this year. As a whole, the group predicted values will rise 4.4 percent in 2015 to a median value of $187,040, with projections ranging from a low of 3.1 percent to a high of 5.5 percent.

“During the past year, expectations for annual home value appreciation over the long run have remained flat, despite lower mortgage rates,” said Terry Loebs, founder of Pulsenomics. “Regarding the near-term outlook, there is a clear consensus among the experts that the positive momentum in U.S. home prices will continue to slow this year.”

On average, panelists said they expect median home values will pass their precession peak ($196,400) by May 2017.

OPEC Can’t Kill American Shale

https://i2.wp.com/static3.businessinsider.com/image/542c5b786da8118e288b4570/morgan-stanley-here-are-the-16-best-stocks-for-playing-the-american-shale-boom.jpgby Shareholdersunite

Summary

  • OPEC is supposedly out to beat, or at least curtail the growth of American shale oil production.
  • For a host of reasons, especially the much shorter capex cycle for shale, they will not succeed unless they are willing to accept permanent low oil prices.
  • But, permanent low oil prices will do too much damage to OPEC economies for this to be a credible threat.

We’re sure by now you are familiar with the main narrative behind the oil price crash. First, while oil production outside of North America is basically stagnant since 2005.

The shale revolution has dramatically increased supply in America.

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The resulting oversupply has threatened OPEC and the de-facto leader Saudi Arabia has chosen a confrontational strategy not to make way for the new kid on the block, but instead trying to crush, or at least contain it. Can they achieve this aim, provided it indeed is their aim?

Breakeven price
At first, one is inclined to say yes, for the simple reason that Saudi (and most OPEC) oil is significantly cheaper to get out of the ground.

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This suggests that all OPEC has to do is to keep output high and sooner or later the oversupply will work itself off the market, and expensive oil is more likely to see cutbacks than cheaper oil, although this critically depends on incentives facing individual producers.

Capex decline
It is therefore no wonder that we’ve seen significant declines in rig counts and numerous companies have announced considerable capex declines. While this needs time to work out into supply cutbacks, these will eventually come.

For instance BP (NYSE:BP) cutting capex from $22.9B in 2014 to $20B in 2015, or Conoco (NYSE:COP) reducing expenditures by more than 30% to $11.5B this year on drilling projects from Colorado to Indonesia. There are even companies, like SandRidge (NYSE:SD), that are shutting 75% of their rigs.

Leverage
It is often argued that the significant leverage of many American shale companies could accelerate the decline, although it doesn’t necessarily have to be like that.

While many leveraged companies will make sharp cutbacks in spending, which has a relatively rapid effect on production (see below), others have strong incentives to generate as much income as possible, so they might keep producing.

Even the companies that go belly up under a weight of leverage will be forced to relinquish their licenses or sell them off at pennies to the dollar, significantly lowering the fixed cost for new producers to take their place.

Hedging
Many shale companies have actually hedged much of their production, so they are shielded from much of the downside (at a cost) at least for some time. And they keep doing this:

Rather than wait for their price insurance to run out, many companies are racing to revamp their policies, cashing in well-placed hedges to increase the number of future barrels hedged, according to industry consultants, bankers and analysts familiar with the deals. [Reuters]

Economics
Being expensive is not necessarily a sufficient reason for being first in line for production cuts. For instance, we know that oil from the Canadian tar sands is at the high end of cost, but simple economics can explain why production cuts are unlikely for quite some time to come.

The tar sands involve a much higher fraction as fixed cost:

Oil-sands projects are multibillion-dollar investments made upfront to allow many years of output, unlike competing U.S. shale wells that require constant injections of capital. It’s future expansion that’s at risk. “Once you start a project it’s like a freight train: you can’t stop it,” said Laura Lau, a Toronto-based portfolio manager at Brompton Funds. Current oil prices will have producers considering “whether they want to sanction a new one.” [Worldoil]

So, once these up-front costs are made, these are basically sunk, and production will only decline if price falls below marginal cost. As long as the oil price stays above that, companies can still recoup part of their fixed (sunk) cost and they have no incentive to cut back production.

But, of course, you have tar sand companies that have not yet invested all required up-front capital and new capex expenditures will be discouraged with low oil prices. So, there is still the usual economic upward sloping supply curve operative here.

Swing producer
The funny thing is American shale oil is at the opposite end of this fixed (and sunk) cost universe, apart from acquiring the licenses. As wells have steep decline curves, production needs constant injection of capital for developing new wells.

Production can therefore be wound down pretty quickly should the economics require, and it can also be wound back up relatively quickly, which we think is enough reason why American shale is becoming the new (passive) swing producer. This has very important implications:

  • The relevant oil price to look at isn’t necessarily the spot price, but the 12-24 months future price, the time frame between capex and production.
  • OPEC will not only need to produce a low oil price today, that price needs to be low for a prolonged period of time in order to see cutbacks in production of American shale oil. Basically, OPEC needs the present oil price to continue indefinitely, as soon as it allows the price to rise again, shale oil capex will rebound and production will increase fairly soon afterwards.

So basically, shale is the proverbial toy duck which OPEC needs to submerge in the bathtub, but as soon as it releases the pressure, the duck will emerge again.

Declining cost curves
The shale revolution caught many by surprise, especially the speed of the increase in production. While technology and learning curves are still improving, witness how production cost curves have been pushed out in the last years:

There is little reason this advancement will come to a sudden halt, even if capex is winding down. In fact, some observers are arguing that producers shift production from marginal fields to fields with better production economics, and the relatively steep production decline curves allow them to make this shift pretty rapidly.

Others point out that even the rapid decline in rig count will not have an immediate impact on production, as the proportion of horizontal wells and platforms where multiple wells are drilled from the same location are increasing, all of which is increasing output per rig.

Another shift that is going on is to re-frack existing wells, instead of new wells. The first is significantly cheaper:

Beset by falling prices, the oil industry is looking at about 50,000 existing wells in the U.S. that may be candidates for a second wave of fracking, using techniques that didn’t exist when they were first drilled. New wells can cost as much as $8 million, while re-fracking costs about $2 million, significant savings when the price of crude is hovering close to $50 a barrel, according to Halliburton Co., the world’s biggest provider of hydraulic fracturing services. [Bloomberg]

Production cuts will take time
The hedging and shift to fields with better economics is only a few of the reasons why so far there has been little in the way of actual production cuts in American shale production, the overall oil market still remains close to record oversupply. The International Energy Agency (IEA) argues:

It is not unusual in a market correction for such a gap to emerge between market expectations and current trends. Such is the cyclical nature of the oil market that the full physical impact of demand and supply responses can take months, if not years, to be felt [CNBC].

In fact, the IEA also has explicit expectations for American shale oil itself:

The United States will remain the world’s top source of oil supply growth up to 2020, even after the recent collapse in prices, the International Energy Agency said, defying expectations of a more dramatic slowdown in shale growth [Yahoo].

OPEC vulnerable itself
Basically, the picture we’re painting above is that American shale will be remarkably resilient. Yes, individual companies will struggle, sharp cutbacks in capex are already underway, and some companies will go under, but the basic fact is that as quick as capex and production can fall, they can rise as quickly again when the oil price recovers.

How much of OPEC can the storm of the oil price crash, very much remains to be seen. There is pain all around, which isn’t surprising as one considers that most OPEC countries have budgeted for much higher oil prices for their public finances.

(click to enlarge)
You’ll notice that these prices are all significantly, sometimes dramatically, higher than what’s needed to balance their budgets. Now, many of these countries also have very generous energy subsidies on domestic oil use, supposedly to share the benefits of their resource wealth (and/or provide industry with a cost advantage).

So, there is a buffer as these subsidies can be wound down relatively painless. Some of these countries also have other buffers, like sovereign wealth funds or foreign currency reserves. And there is often no immediate reason for public budgets to be balanced.

But to suggest, as this article is doing, that OPEC is winning the war is short-sighted.

Conclusion
While doing damage to individual American shale oil producers and limiting its expansion, the simple reality is that for a host of reasons discussed above, OPEC can’t beat American shale oil production unless it is willing to accept $40 oil indefinitely. While some OPEC countries might still produce profitably at these levels, the damage to all OPEC economies will be immense, so, we can’t really see this as a realistic scenario in any way.

Oil Glut Gets Worse – Production, Inventories Soar to Record

https://i1.wp.com/bloximages.newyork1.vip.townnews.com/oaoa.com/content/tncms/assets/v3/editorial/9/14/914424e8-aaf0-11e4-ac1c-b74346c3e35b/54cf9855658eb.image.jpgby Wolf Richter

February 4th, 2015: Crude oil had rallied 20% in three days, with West Texas Intermediate jumping $9 a barrel since Friday morning, from $44.51 a barrel to $53.56 at its peak on Tuesday. “Bull market” was what we read Tuesday night. The trigger had been the Baker Hughes report of active rigs drilling for oil in the US, which had plummeted by the most ever during the latest week. It caused a bout of short covering that accelerated the gains. It was a truly phenomenal rally!

But the weekly rig count hasn’t dropped nearly enough to make a dent into production. It’s down 24% from its peak in October. During the last oil bust, it had dropped 60%. It’s way too soon to tell what impact it will have because for now, production of oil is still rising.

And that phenomenal three-day 20% rally imploded today when it came in contact with another reality: rising production, slack demand, and soaring crude oil inventories in the US.

The Energy Information Administration reported that these inventories (excluding the Strategic Petroleum Reserve) rose by another 6.3 million barrels last week to 413.1 million barrels – the highest level in the weekly data going back to 1982. Note the increasingly scary upward trajectory that is making a mockery of the 5-year range and seasonal fluctuations:

US-crude-oil-stocks-2015-02-04
And there is still no respite in sight.

Oil production in the US is still increasing and now runs at a multi-decade high of 9.2 million barrels a day. But demand for petroleum products, such as gasoline, dropped last week, according to the EIA, and so gasoline inventories jumped by 2.3 million barrels. Disappointed analysts, who’d hoped for a drop of 300,000 barrels, blamed the winter weather in the East that had kept people from driving (though in California, the weather has been gorgeous). And inventories of distillate, such as heating oil and diesel, rose by 1.8 million barrels. Analysts had hoped for a drop of 2.2 million barrels.

In response to this ugly data, WTI plunged $4.50 per barrel, or 8.5%, to $48.54 as I’m writing this. It gave up half of the phenomenal three-day rally in a single day.

Macquarie Research explained it this way:

In our experience, oil markets rarely exhibit V-shaped recoveries and we would be surprised if an oversupply situation as severe as the current one was resolved this soon. In fact, our balances indicate the absolute oversupply is set to become more severe heading into 2Q15.

Those hoping for a quick end to the oil glut in the US, and elsewhere in the world, may be disappointed because there is another principle at work – and that principle has already kicked in.

As the price has crashed, oil companies aren’t going to just exit the industry. Producing oil is what they do, and they’re not going to switch to selling diapers online. They’re going to continue to produce oil, and in order to survive in this brutal pricing environment, they have to adjust in a myriad ways.

“Efficiency and innovation, when price falls, it accelerates, because necessity is the mother of invention,” Michael Masters, CEO of Masters Capital Management, explained to FT Alphaville on Monday, in the middle of the three-day rally. “Even if the investment only spits out quarters, or even nickels, you don’t turn it off.”

Crude has been overvalued for over five years, he said. “Whenever the return on capital is in the high double digits, that’s not sustainable in nature.” And the industry has gotten fat during those years.

Now, the fat is getting trimmed off. To survive, companies are cutting operating costs and capital expenditures, and they’re shifting the remaining funds to the most productive plays, and they’re pushing 20% or even 30% price concessions on their suppliers, and the damage spreads in all directions, but they’ll keep producing oil, maybe more of it than before, but more efficiently.

This is where American firms excel: using ingenuity to survive. The exploration and production sector has been through this before. And those whose debts overwhelm them – and there will be a slew of them – will default and restructure, wiping out stockholders and perhaps junior debt holders, and those who hold the senior debt will own the company, minus much of the debt. The groundwork is already being done, as private equity firms and hedge funds offer credit to teetering oil companies at exorbitant rates, with an eye on the assets in case of default.

And these restructured companies will continue to produce oil, even if the price drops further.

So Masters said that, “in our view, production will not decrease but increase,” and that increased production “will be around a lot longer than people are forecasting right now.”

After the industry goes through its adjustment process, focused on running highly efficient operations, it can still scrape by with oil at $45 a barrel, he estimated, which would keep production flowing and the glut intact. And the market has to appreciate that possibility.


Rigs Down By 21% Since Start Of 2015
Permian Basin loses 37 rigs first week in February

by Trevor Hawes

The number of rigs exploring for oil and natural gas in the Permian Basin fell 37 this week to 417, according to the weekly rotary rig count released Friday by Houston-based oilfield service company Baker Hughes.

This week’s count marked the ninth-consecutive decrease for the Permian Basin. The last time Baker Hughes reported a positive rig-count change was Dec. 5, when 568 rigs were reported. Since then, the Permian Basin has shed 151 rigs, a decrease of 26.58 percent.

For the year, the Permian Basin has shed 113 rigs, or 21.32 percent.

In District 8, which includes Midland and Ector counties, the rig count fell 19 this week to 256. District 8 has shed 58 rigs, 18.47 percent, this year.

Texas lost 41 rigs this week for a statewide total of 654. The Lone Star State has 186 fewer rigs since the beginning of the year, a decrease of 22.14 percent.

In other major Texas basins, there were 168 rigs in the Eagle Ford, down 10; 43 in the Haynesville, unchanged; 39 in the Granite Wash, down one; and 19 in the Barnett, unchanged.

The Haynesville shale is the only major play in Texas to have added rigs this year. The East Texas play started 2015 with 40 rigs.

At this time last year, there were 483 rigs in the Permian Basin and 845 in Texas.

In the U.S., there were 1,456 rigs this week, a decrease of 87. There were 1,140 oil rigs, down 83; 314 natural gas rigs, down five; and two rigs listed as miscellaneous, up one.

By trajectory, there were 233 vertical drilling rigs, down two; 1,088 horizontal drilling rigs, down 80; and 135 directional drilling rigs, down five.

The top five states by rig count this week were Texas; Oklahoma with 176, down seven; North Dakota with 132, down 11; Louisiana with 107, down one; and New Mexico with 78, down nine.

The top five basins were the Permian; the Eagle Ford; the Williston with 137, down 11; the Marcellus with 71, down four; and the Mississippian with 53, down one.

In the U.S., there were 1,397 rigs on land, down 85; nine in inland waters, down three; and 50 offshore, up one. There were 48 rigs in the Gulf of Mexico, up one.

Canada’s rig count fell 13 this week to 381. There were 184 oil rigs, down 16; 197 natural gas rigs, up three; and zero rigs listed as miscellaneous, unchanged. Canada had 621 rigs a year ago this week, a difference of 240 rigs compared to this week’s count.

The number of rigs exploring for oil and natural gas in the North America region, which includes the U.S. and Canada, fell 100 this week to 1,837. There were 2,392 rigs in North America last year.

Rigs worldwide

On Friday, Baker Hughes released its monthly international rig count for January. The worldwide total was 3,309 rigs. The U.S. ended January with 1,683 rigs, just more than half of all rigs worldwide.

The following are January’s rig counts by region, with the top three nations in each region in parentheses:

Africa: 132 (Algeria: 97; Nigeria: 19; Angola: 14)

Asia-Pacific: 232 (India: 108; Indonesia: 36; China offshore: 33)

Europe: 128 (Turkey: 37; United Kingdom offshore: 15; Norway: 13)

Latin America: 351 (Argentina: 106; Mexico: 69; Venezuela: 64)

Middle East: 415 (Saudi Arabia: 119; Oman: 61; Iraq: 60)

Odessa migrant worker 1937

Migrant oil worker and wife near Odessa, Texas 1937

Photographer: Dorothea Lange Created: May 1937 Location: OdessaTexas

Call Number: LC-USF34-016932 Source: MRT.com