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Energy & Commodities

America's Unexpected Wealth

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Posted by Keith Schaefer: Oil & Gas Investments Bulletin

on Monday, 11 February 2013 06:34

Condensate Part I  explained what this hot new commodity is; Part II outlined the bullish case for Canadian condensate demand, and in this third and final article on condensate, I review American efforts to move their glut of condensate north.

Condensate is making uneconomic gas wells profitable for producers in the shale basins of northern BC and Alberta, and creating some great investment opportunities for informed investors.
 

The reason condensate is king in Canada is that oil sands producers need piles of this light oil to dilute their heavy bitumen for transport, and Canadian production can’t keep up with demand. 
 
How long can this party last? Shale oil and gas basins in the United States are churning out condensate, where demand is very limited. A glut is developing.
 
That glut is needed up north, so infrastructure players are busy planning, permitting, and building pipelines to move America’s piles of condensate to the Canadian oil sands producers that need it. Once that happens, will condensate’s Canadian price premium evaporate?  
 
It’s an important question, as strong condensate prices are the only leg many Canadian gas producers have to stand on right now.
 
America’s Unexpected Condensate Wealth

The Shale Revolution has transformed America’s energy scene. After decades of decline, US oil production is again on the rise. The turnaround has been even more dramatic on the natural gas front: shale wealth has transformed the country from an importer to an exporter and pushed prices to historic lows.

 
Condensate production is an unexpected sideshow of the shale phenomenon – but it is starting to steal some of the limelight because shale wells are producing just so much of it. 
 
Take the Eagle Ford shale basin, which stretches across much of south and east Texas. The basin’s tight sedimentary rocks contain a range of hydrocarbons: wells on the southeastern flank generally produce dry gas, wells in the middle produce gas, natural gas liquids (NGLs), and condensate, and wells to the northwest generate oil and condensate.

Eagle Ford producers drilled their wells looking for oil or gas. Condensate was an unexpected bonus – but it now makes up as much as 40% of the hydrocarbons produced from the formation.  

 
Forecasters predict that total Eagle Ford oil output will reach 500,000 to 800,000 barrels per day (bpd) by 2020. A large number of those barrels – somewhere between 250,000 and 400,000 bpd – will be condensate. Compare that to 2011, when condensate production from the formation averaged 130,000 barrels per day. 
 
It means condensate production from Eagle Ford will likely grow by 150% in less than a decade. And Eagle Ford is just one of a slew of shale basins being drilled and fracked apace in the United States to produce oil, natural gas, NGLs, and condensate.
 
It sounds great, right? Not only are shale basins producing the natural gas and crude oil expected, they are also churning out piles of condensate, a hydrocarbon mixture so light you could often pour it straight into your tractor. Condensate must be making US shale producers happy, right?
 
Wrong. 
 
Condensate and US Refineries – A Poor Match

Since it is produced alongside oil and since it is in fact oil, producers lump condensate with oil when reporting production volumes. As a result, it seems like US oil production is shooting through the roof. But while domestic output is certainly rising, lumping condensate in with crude is misleading because not every hydrocarbon molecule is created equal – especially through the eyes of a refinery.

 
Half of America's refineries lie along the Gulf Coast. With the ability to process 8 million barrels of crude oil every day, this industrial complex truly sets the tone for oil pricing across the country. And guess what? Gulf Coast refineries don't like condensate. 
 
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-------------------------------------
Refineries are picky beasts, each one only able to process crudes within a particular API range. The Gulf Coast army of refineries used to love light oil, but over the last 25 years the world burned through many of its high-quality deposits of light crude. That forced producers to shift towards heavier and sourer crudes.
 
In response, US refineries invested billions in upgrades to be able to process these more complicated crudes. In fact, from 2005 to 2009 the US refining industry spent $47.6 billion on heavy oil upgrades.
 
Then came the Shale Revolution. Fracking technology is the engine for America's drive for increased energy independence.  Suddenly producers were pumping good quality oil from shale basins across the continent.

The refineries can handle shale oil. They cannot, however, handle much condensate. 

 
The only way to feed condensate into these medium and heavy oil refineries is to mix the light oil with a heavier crude, to produce a mid-weight blend. But even that is not ideal, because it turns out a mixture of heavy oil and condensate does not produce the same products as a straight crude of similar weight. 
 
Specifically, a mixture of light condensate and heavy crude produces lots of very light products, such as naphtha, and little to none of the heavier and more valuable distillates used to make diesel and jet fuel. 
 
So, since a crude-condensate blend produces less valuable products than a straight crude of the same average weight, refiners discount the price they're willing to pay for blends.
 
The unexpected surge in condensate production has collided head-on with low demand from US refineries, resulting in poor pricing. In general, Gulf Coast crude marketers have been paying about $15 per barrel less for condensate than for the light crude it is produced alongside.
 
Since it is cheaper than crude, refineries are buying some condensate and mixing it with heavier crudes for processing. The products are worth less but input costs are also lower, so it works out ok for refiners' bottom lines. 
 
It does not, however, work out well for producers. Shale producers invest millions of dollars into each multi-stage frac well. They don't want to sell half their production at a discount – they want buyers who are willing to pay top dollar for all this light, sweet condensate. 
 
Those buyers, as we learned last week, are north of the 49th parallel.
 
Getting Condensate to Canada**
 
Canada needs condensate. US producers are flooded with the stuff and want to sell it to Canadian oil sands operators. The challenge is moving it. 
 
The only pipeline currently moving condensate from the US into Canada is Enbridge's Southern Lights line, which runs from Illinois to Edmonton. It can move 180,000 barrels per day, which can more than handle the 110,000 bpd of condensate being imported now and Enbridge is proposing an expansion. 
 
rainbow pipeline
 
The hard part, the bottleneck, is getting it to Patoka, where it can enter Southern Lights. Patoka, it turns out, is not particularly close to the biggest condensate-producing shale in the US, which is the Eagle Ford basin in Texas.
 
There are ways. For example, Plains All American is using the Louisiana port of St James as a staging post to route Eagle Ford condensate into the Capline pipeline for shipment to Patoka. 
 
Others are using existing gathering networks to move condensate to Corpus Christi on the Texas Gulf Coast, where it is loaded onto barges and transported to St James. Magellan Midstream Partners and Copano Energy are taking this one step further, extending one of Copano's pipes by 140 miles to Corpus Christi. That line should soon be moving 100,000 barrels of condensate a day.
 
KINDER MORGAN’S PLANS**
 
Kinder Morgan is also working to establish itself as an Eagle Ford condensate shipper. Kinder is building a condensate pipeline that can move 300,000 bpd from the shale basin to the Houston area, which is already being used to capacity.

From Houston, the condensate from Kinder’s line moves through the company’s Explorer pipeline to Hammond, Illinois. 
 

That’s progress, but Canada is still hundreds of kilometers away. To connect its system to Canada, Kinder has two plans:
 
1. Extend Explorer to connect with Enbridge’s Southern Lights—one ends and another starts in Illinois.  That link  should be in service by early 2014. 
 
2. The other is to connect Explorer to the Cochin pipeline. Cochin moves propane 1,900 miles west to east—from Alberta to Ontario—through the US, crossing the border in North Dakota and skirting south of the Great Lakes before re-entering Canada in Windsor. 
 
Propane volumes have been declining, so Kinder is proposing to reverse and expand part of Cochin—from east to west—to move 95,000 bpd of condensate from Illinois to Alberta.
 
Industry support for the project is clear: when Kinder held an open season on its Cochin proposal, the company received binding commitments for 105% of the proposed capacity. US regulators approved the plan in October; Kinder is now awaiting word from Canadian regulators. If all goes according to plan, the reversed Cochin will start moving condensate from the Midwest into Canada by mid-2014.
 
Plans from Kinder and Plains All American alone will increase Eagle Ford condensate capacity to Alberta by 170,000 bpd by the middle of 2014. Other pipeline projects are also in the works. Not willing to wait, some US producers moving their condensate to Canada by rail. 
 
The upgrades are coming, and all signs indicate that every condensate pipe in the works will be filled to the brim almost from day one. Even without much dedicated infrastructure, condensate sales from the US to Canada have skyrocketed in recent years. Every estimate is different, but some analysts estimate that US condensate exports to Canada have grown 1,000% in the last two years alone.
 
CONCLUSION

Condensate capacity from the US to Canada should increase dramatically—but it is over a year away.  Oil and gas marketers in Alberta tell me oilsands production is rising fast enough to use a lot more condensate—but only time will tell if the market stays in balance, over-supplied, or under-supplied.

 
There’s a lot riding on this equation for Canadian natural gas producers—strong condensate pricing is the only thing between a lot of them and bankruptcy.

- Keith

 
**Much of this information was gleaned from Rusty Braziel’s blog at www.rbnenergy.com.  Rusty and his team put out a free daily blog that is full of GREAT information, though sometimes a bit technical for the retail investor.  I go there every day, and often read it.  Serious energy investors should bookmark it.  Registration is free - just go to: http://www.rbnenergy.com/signup


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Energy & Commodities

How Fracking Differs from Conventional Oil Recovery

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Posted by OilPrice.com

on Friday, 08 February 2013 13:45

Before there were refrigerators folks kept drinks cool by putting them into clay jars that had been soaked in water. The evaporation of the water from the clay cooled the container and its contents, which today includes wine bottles. On the other hand, for many years artisans have taken clay in a slightly different form, shaped it and baked it and provided the teacups which keep the liquid inside until we drink it.

Two different forms of the same basic geological material, with two different behaviors and uses. Why bring this up? Well there is a growing series of articles which continue to laud the volumes of oil and natural gas that the world can expect from the artificial fracturing of the layers of shale in which these hydrocarbons have been trapped for the past few million years. It has been suggested that there is no difference between this “unconventional” oil and the “conventional” oil that has been produced over the past century to power the global economy. And yet, despite the scientific detail which some of these critics discuss other issues, they seem unable to grasp the relatively simple geologic and temporal facts that make the reserves in such locations as the Marcellus Shale of Pennsylvania and the Bakken of North Dakota both unconventional and temporally transient. Let me therefore try again to explain why, despite the fact that the oil itself may be relatively similar, the recovery and economics of that oil are quite different from those involved in extracting conventional deposits.

But, before getting to that, let’s first look at the current situation in North Dakota, using the information from the Department of Mineral Resources (DMR). According to theJanuary Director’s Cut the rig count in the state has varied from 188 in October, through 186 in November, and 184 in December, to 181 at the time of the report. Why is this number important? Well, as I will explain in more detail later, the decline rate of an individual well in the region is very high, and thus the industry has to continue to drill wells at a rapid rate, just to replace the decline. (This is the “Red Queen” scenario that Rune Likvern has explained so well.) The DMR recognize this by showing the effect of several different scenarios as the number of rigs changes.

For example they project that 170 rigs will be able to drill around 2,000 wells a year. At that level, and with some assumptions about the productivity of individual wells that I am not going to address here, but which Rune discussed. I would, however, suggest that it is irrational to expect that new wells will continue to sustain existing first year levels as the wells move away from formation sweet spots. Yet, accepting their assumptions for now, DMR project that the 170 rigs will generate the following production from the state:

AE1385

......read more HERE

 



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Energy & Commodities

Commodities have been in decline for over 20 years

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Posted by Jim Rogers: Rogers Holdings

on Tuesday, 05 February 2013 16:33

commodities-2

The major oil fields are in decline and there haven’t been many new mines opened.In agriculture, the average age of a farmer in the U.S. is 58, and 66 in Japan. “We’re running out of farmers,”I want to own real assets. I want to invest in companies that produce real goods. Shortages are getting worse, not better.”

On the Dollar - The Dollar is not a safe haven but People will flock to it

All of Jim Rogers comments  HERE



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Energy & Commodities

The Metals Report: $4/lb Copper Is on Its Way

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Posted by Kevin Puil: The Metals Report

on Tuesday, 05 February 2013 13:54

hutmen-rod

Kevin Puil thinks analysts need to be realistic when it comes to copper. The Malcolm Gissen & Associates portfolio manager points to copper's historic levels at over $3/lb as proof that there are brighter times ahead for base metals as economies around the world continue to industrialize. On the other hand, with economic projects less abundant than they once were, supply is under severe pressure. The good news is, as Puil remarks in this Metals Report interview, there's money to be made for investors who can pinpoint the right projects. Read on to learn who's on Puil's list - HERE



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Energy & Commodities

The Saving Grace for Canadian Producers

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Posted by Keith Schaefer: Oil & Gas Investments Bulletin

on Monday, 04 February 2013 12:34

When investors ask me about investing in natural gas stocks, I give them the single most important question to ask producers:  How much condensate do they produce?  Ask about condensate.
 

Condensate is essentially a very light oil which is condensed from rich natural gas and solution gas from oil.  And the price of it is skyrocketing, because it’s used to dilute both regular heavy and synthetic oil from the oilsands.  It’s the saving grace for a lot of Canadian producers.

See this chart below.  It shows Canadian condensate prices against WTI—see how the value of condensate is rising rapidly?  In August 2012 it was only $3/barrel more than WTI.  Now it’s $14 more—giving producers with lots of condensate even better economics than most oil producers!

                                                                         condensate-chart

And prices will only get better for condensate producers, one Alberta based oil and gas marketer told me, asking to remain anonymous.

“Supply and demand (for condensate) are just touching each other.  Any more heavy oil coming onto market will have a big impact.  We need to find other sources (of condensate).” 

Or, he says, condensate prices could go even higher.  He estimated that if the oilsands increases production by some 400,000 barrels per day (bopd) a year for the next several years, an extra 100,000 bopd of condensate is needed—each and every year.

I’ll explain in my next story, condensate part III,  how US imports of condensate are happening, but not fast enough.

In Canada, most condensate is found in shale and tight gas formations.  In the US, it’s mostly in gas associated with shale oil, especially the fast-rising Eagle Ford play.

In the United States, all this condensate is almost a problem. US refiners spent billions of dollars over the last decade to process more heavy oil. As a result they can’t really handle this light stuff.

But for Canadian gas producers, condensate is the only product that gives them substantial positive cash flow (a very few producers do make some cash flow on dry gas.)  That’s why it’s so important to know how much condensate the gas producers are flowing.
 
Canada’s Thirst for Condensate

In the oil sands, condensate is used as a diluent to 'thin down' bitumen – a thick, sludgy substance – so it will flow through pipelines. Since bitumen production is climbing steadily, condensate demand is on the rise. Supply is struggling to keep up.

Canada now uses some 275,000 barrels of condensate per day as diluent. Canadian producers churn out 165,000 barrels per day (bpd), meaning oil sands operators already rely on imports to fill a 110,000-bpd gap.

                  condensate-spreads

That's good, but it will probably get even better. Capital spending in the oil sands is expected to exceed $20 billion per year for the next five years. The more bitumen that is pulled from the sands, the more diluent Alberta will need to move all that heavy oil to market.

This year Canadian demand for condensate is expected to average 300,000 bpd. By 2020 demand is expected to reach 670,000 bpd, according to the Canadian Energy Research Institute, which also provided the following chart.

              diluent demand

As you can see from the bottom red part of the chart, Canadian condensate production is not expected to increase much in the coming years.   That in itself is bullish.  But there are two other infrastructure bottleneck that should help keep condensate prices high for at least two more years.

One issue is that Canadian NGL processing facilities are basically full.  That is impacting (reducing) condensate production in the short term—creating further supply stress.

So Canadian producers are shipping in tanks directly to their wellsites, and trucking it to local markets; they’re not sending via pipe to processing plants (fractionation plants).   The other reality is—and I’ve said this many times—the energy game is changing so fast in North America—fast rising production in both oil and gas, new channels to market (rail)—that nobody knows what the landscape is going to look like 2-4 years from now.

That uncertainty is causing Big Energy Money to be cautious about increasing refining capacity for oil and gas in Canada—which again, is good for commodity prices.

The second bottleneck is pipeline capacity INTO Canada. 

The US is actually swimming in condensate--it accounts for as much as half of the output from US shale oil and gas basins. Refiners are buying some of it simply because it is cheap, but a condensate glut is also developing in the Lower 48.

Now however, there is only Enbridge’s Southern Lights pipeline bringing condensate into Canada, and it’s not near enough.  (There is some incoming condensate by rail, but now that is still small.) In Part II of this series, I’ll explain in detail this bottleneck, and what’s happening to get rid of it.

Once that glut starts moving into Canada apace, the price premium that Canadian condensate producers are currently enjoying will shrink. Condensate will still carry a good price, but the edge will be smaller.

But I expect that to be at least two years away, and if oilsands production keeps increasing, it may be even longer.
In conclusion—the growing demand for condensate in the oil sands is driving up its price.  This isn’t just saving the lucky Canadian gas producers who have high condensate levels, it’s giving them better economics than most oil producers.

Pipeline bottlenecks in the US and processing plant issues in Canada should conspire to keep condensate prices high—making it the best (and least volatile) upstream commodity stories in North America.

Next, I’ll explain in detail what’s happening to condensate in the US, and the efforts to get as much up to Canada as fast as possible. In general, ‘fast’ means 2014 at the earliest, giving investors lots of time to benefit from strong domestic condensate prices.

Keith

P.S. I think mid-February is one of the BEST times for investors to discover my #1 condensate play in Canada. Learn all about my Top Pick risk-free right HERE.



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