Where will the wealth created by the fast growing Liquid Natural Gas (LNG) market be concentrated in the coming years?

In a word–Australia. It’s the #4 exporter of LNG in the world already, and seven new plants are in various stages of planning and development, which would require $200 billion in capital investment–and lots of jobs.

By comparison, America, which produces massive amounts of natural gas, sends a shockingly small amount of the resource abroad.

Both are close to markets – Australia is closer to Asia, which imports vast quantities of LNG, but the U.S. is also relatively close to these markets and closer to Europe, which holds some major LNG consumers, like Spain and France. Both also have robust natural gas production.

And yet Australia is light years ahead of America in sending LNG overseas. How far? about 800 billion cubic feet (bcf) per year.

Now before we explore that gap further, here’s a short-version background on LNG…

LNG is created by cooling natural gas to minus 256 degrees Fahrenheit, which transforms the gas into a liquid. This liquid has about 1/600th the volume of natural gas, making its transport over long distances much simpler —and much more economic.

While turning a gas into a liquid may seem to be the stuff of science fiction, it has its roots in the 19th century when Carl Von Linde, an engineer in Munich, built the first practical compressor refrigeration machine. The first LNG plant was built roughly a century ago in West Virginia.

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It’s not the Bakken most investors have come to know.

But I expect that all to change, especially now that one small company operating here has just hit TWICE on a HUGE new play–validating thousands of acres.

That’s why company insiders have been loading up on shares… AND why brokerage firms have price targets 50% to 100% higher than today’s share price.

As an OGIB reader, you can get the full update on this high-potential growth play — here in my new findings. Go here for free access.

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Of course, large-scale users of natural gas prefer to deal with the regular kind–not liquid and frozen. Since gas is easier to move and doesn’t need to be refrigerated, companies had to then develop ways to reverse the process. So you have to liquefy the gas to move it, and then “re-gasify” the natural gas to use it.  That’s a lot of work and means large infrastructure investments are required.

The gas is converted to liquid at liquefaction plants (LNG export terminals.) It is then transported in special ships that use auto-refrigeration. These LNG ocean tankers actually use a small amount of the LNG – 3%-4% during an average voyage—to power the ships. These tankers can carry around 135,000 cubic meters of liquid natural gas, which works out to about 3 billion cubic feet of warm natural gas.

To give you an idea of how much gas that is, 23 ships a day could feed ALL the US demand for natural gas.  There are now roughly 375 ships in service worldwide.

The ships then go to an LNG import, or regasification, terminal where the LNG is converted back to a gaseous state and then either stored in tanks or sent through pipelines.

The Asian market is a major destination for LNG exporters. Japan is by far the world’s largest importer of LNG, bringing in nearly 71 million tons (8.52 bcf/d)—or almost 31 percent of all global LNG imports, according to Unit Economics.

South Korea is #2 at 34.5 million tons (4.14 bcf/d), or roughly 15 percent of global imports. Taiwan (11.3 million tons/1.36 bcf/d) and China (9.7 million tons/1.16 bcf/d) also account for a significant portion of LNG imports.

Asia isn’t the only major LNG import market, though. Europe brings in large amounts as well.  Spain is the third largest importer of LNG with 27.3 million tons (3.28 bcf/d) coming in during 2010. The United Kingdom and France are also major importers, bringing in 13.4 million tons (1.60 bcf/d) and 10.2 million tons (1.22 bcf/d) in 2010, respectively.

According to the U.S. Energy Information Administration (EIA), the U.K. received 55 percent of its LNG exports from Qatar in 2009. That same year significant quantities of the hydrocarbon entered the U.K. from Trindad and Tobago (a surprisingly robust LNG exporter with 15.4 million tons (1.85 bcf/d) sent abroad in 2010), Algeria, Egypt and Australia.

Now that we’ve covered the basics of LNG, we can dive into the LNG industry in Australia to see what the U.S. might learn from the Land Down Under.

Australia only trails Qatar, Indonesia and Malaysia in LNG exports. In 2010, Australia sent 872 billion cubic feet (about 19 million tons) abroad, which was a substantial improvement over the 714 BCF exported in 2009, says the EIA.

That’s just over 8% of the world’s LNG exports. By comparison, Qatar does 25% of all LNG exports. Unit Economics states that Australia could contend with the Middle Eastern country for top spot as early as 2016.

Not surprisingly, most of Australia’s LNG exports go to the Top 4 importing countries—all in the Far East. Japan gets about 70% of Australia’s LNG exports, China gets 21%, South Korea 5% and Taiwan 4%.

There are only two LNG liquefaction plants in Australia right now, but seven additional export facilities are under construction, and four more are planned. Unit Economics reports that if all of these facilities come on line and produce their projected capacities, Australia will send a staggering 95.7 million tons (11.5 bcf/d) of natural gas abroad per year, versus the 19 million tons (2.28 bcf/d) it is exporting now—a five-fold increase!

The capital investments—and the jobs created by it—are enormous.  The Australian major Santos Ltd., along with Petroliam Nasional Bhd., are planning on shelling out $45 billion to create three LNG export facilities that would be able to convert 20.8 million tons of coal seam gas into LNG each year, reports the Wall Street Journal.

Other prominent players in Australian LNG are the BG Group PLC and the Australia Pacific LNG consortium, which is led by ConocoPhillips and Origin Energy Ltd.

“LNG is simply in high demand. and it’s not just the consequence of Fukushima,” Jon Skule Storheill, chief executive officer of Awilco LNG, told Reuters, referencing the nuclear disaster in Japan that has prompted the country to rely more heavily on LNG. “There’s Korea, there’s Taiwan, this market is just strong. Gas is clean, it’s available and it’s cheap.”

America, on the other hand, has only two export terminals. The terminal in Kenai, Alaska, which was built in the 1960s, was idled in November of last year. (At the time, ConocoPhillips’ spokeswoman Natalie Lowman told The Associated Press the plant will be in preservation mode until spring 2012, at which time the company will re-examine the facility.)

The other is Cheniere Energy’s Sabine Pass LNG Terminal, near the border of Texas and Louisiana. This station has 4 billion cubic feet per day of capacity.

Overall, the US exported 0.2 bcf/d of LNG in 2011, according to the EIA—a total of 71.5 bcf.  Australia almost does that in just one month.  The U.S. sends most of its LNG exports to Brazil, China, Japan and South Korea.

So How Does the US Get In On the Global LNG Action?

The LNG market is growing, and its future looks bright.

Some industry analysts predict demand for LNG globally will increase 40% in the five-year period from 2010 to 2015. This would make the annual market for LNG roughly 300 million tons.

The U.S. has the fifth-highest amount of natural gas reserves in the world, with the EIA putting the number at 273 trillion cubic feet. By comparison Australia has the 12th-highest natural gas reserves, with “only” 110 trillion cubic feet. But, as  stated above, Australia was able to ship more than 12 times as much LNG overseas in 2010 than the U.S.

The largest obstacle the U.S. faces in the LNG market is its lack of export/liquefaction terminals. With the Kenai facility going idle, the Sabine Pass terminal is the only facility in America even close to being able to regularly send LNG overseas. And even that could still be a few years away.

Now what about building LNG liquefaction plants?  Unit Economics says it can cost $3 billion for each million tons of annual capacity for the entire liquefaction supply chain, which includes production, pipelines, the port and the facility itself.

The Wall Street Journal reports there are seven additional projects seeking approval from the Department of Energy to ship LNG to most foreign nations. If all of these projects gain approval they could handle about 25 percent of U.S. gas production. However, the news source reports that approval for all of the facilities is unlikely.

An additional hurdle to the LNG market in the U.S. is political opposition to sending the energy source overseas. The American Chemistry Council has warned the U.S. government that it “should not undermine the availability of domestic natural gas,” but is not necessarily against exporting the substance.

The Sierra Club is concerned that exporting more natural gas will cause companies to increase their fracking operations. While there has been little to no evidence that fracking itself harms the environment, a groundswell of opposition to the practice has emerged, making investing in greater production difficult for the industry.

Still, for all the hurdles in exporting LNG, the U.S. also many opportunities.

In mid-March Japanese officials planned to meet with a delegation headed by Deputy Energy Secretary Daniel Poneman to reportedly request LNG exports to Japan. This appears to be a major step, as Japan had previously shied away from American LNG due to uncertainty over whether Washington would allow it to be exported.

As mentioned, Japan’s thirst for LNG is insatiable, and it will only grow stronger as the country scales back on its use of nuclear power following last year’s Fukushima Daiichi nuclear disaster. (Before the disaster, nuclear power accounted for about 30 percent of Japan’s energy production. That’s a large hole Japan will need to fill.)

Other markets that could be exploited by the U.S. are the U.K., France and Spain, all three of which are among the largest importers of LNG in the world. While Australia does send some LNG to these European countries, most of the U.S. competition will come from African countries like Nigeria and Algeria, as well as Qatar.

Another positive sign for U.S. LNG exports is that they appear to have the support of Energy Secretary Steven Chu, who has stated that sending the hydrocarbon overseas would allow America to cut into its trade deficit.

“Exporting natural gas means wealth comes into the United States,” he said, reports The Wall Street Journal.

There is much work to be done in the U.S. LNG industry to help it catch Australia—but the economics are powerful if it can.  The gears appear to be moving in the right direction, as both international markets are opening up, domestic production increases and LNG liquefaction facilities gain approval and come on line.

There is a multi-billion dollar water industry forming before investors’ eyes in the oil patch.

It’s a huge opportunity for some great capital gains — but changing regulations, and a very attentive mainstream audience questioning business practises which have been in effect for decades, will will make it choppy water for investors.

“In 2008 there were 25 billion barrels of water handled (by the oil and gas industry) in the US—even at 60 cents a barrel it’s a multibillion dollar business,” says Jonathan Hoopes, President of GreenHunter Energy Inc. (GRH-AMEX). “With the big growth in unconventional since then, it’s likely another 5-6 billion barrels.”

GreenHunter is a pure play on the fast growing water market in the oil patch, along with companies like Heckmann Corp (HEK-NYSE), and Ridgeline Energy Services (RLE-TSXv; RGDEF-OTCQX). There are also many private technology companies with new water treatment processes.

Ridgeline is developing a water purification and recycling technology for the oil and gas sector. CEO Tony Ker says the industry is just beginning to put a formal cost structure on their water, and it’s not always easy to see through the mist to a simple business model.

“Customers in the oil and gas industry are finding their way into the water industry,” he told me in a recent interview. “Two years ago customers didn’t know what the water business meant. At some point they knew they would have to clean and re-use it, but didn’t understand how to do it.

“Now we’re watching it form as we speak. Customers are now starting to define what the water business will be. Before, it had no shape or form. Now we’re seeing various companies put cost structure on the business; put costs on storage, treatment, transportation.”

GreenHunter has put some of these costs in their PowerPoint presentation.

In the Marcellus Shale, they say it costs $3 + per barrel (/bbl) to dispose of water — and $7-$10/bbl to haul it away. If a horizontal well uses 4.2 million gallons of water to frack (that would be a slightly bigger than average well, but it makes my math easy ;-)), then that’s 100,000 barrels (42 gallons=1 barrel).

If you get 30% of that back in the first year, that’s 30,000 barrels x $10+ per barrel hauling and disposal costs=$300,000 in water costs per well. But that’s $300,000 in water REVENUE for the right company. Then there’s another 30% of that water you get back over the life of the well—assuming costs are constant, that’s $600,000 in revenue.

And there are thousands of wells getting drilled in North America each year; more than 80% of them are now horizontal, and most of those require fracking. The dollar value of managing that water multiplies out fast.

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GreenHunter is estimating that the 2011 water disposal market in the Marcellus alone was $1.3-$1.7 billion, and in 10 years the market will be $15-22 billion.

In the Eagle Ford shale play in Texas, they’re quoting a disposal fee of $0.80+/bbl and an average $3.00 – $6.00 /bbl hauling fee. And with an estimated 800 new oil & gas wells drilled there in 2011, the market just keeps getting bigger. In 2011 the water disposal market was estimated to be $500-$800 million, and in 10 years they are guesstimating that local market will be worth $6-9 billion.

They estimate the Bakken will be a $10.6 billion market within 20 years.

And there is just storing all that water until it is ready to be used. With the new pad drilling, where producers drill multiple wells that splay out in different directions from one pad, millions of gallons water can be stored in one spot for up to and over one year. Just storing that water has turned into a $150 million + business with incredible profit margins—in just one year. And it continues to have hyperbolic growth.

“I believe in two years you will see moderate sized water facilities of 50,000 to 100,000 barrels a day, that are permanent, that will process water for re-use,” says Dennis Danzik, a director of Ridgeline and the inventor of their water purification technology.

There are other major revenue sources as well. Sourcing water is a revenue business as municipalities and landowners in the western US sometimes sell their water to the industry for fracking.

Hoopes believes that regulation around water will develop to the point where producers and service companies will have to supply “cradle-to-grave” monitoring of water to prove it is either recycled or disposed of properly–which is great news for GreenHunter and Heckmann.

Next Story: The ‘Holy Grail’ Business Model for Water

Environmental concerns about hydraulic fracturing are impacting shale oil and gas exploration all over the world—Canada, the United States, New Zealand—but none as much as France.

One year ago, the Paris Basin in northern France was one of the top international shale oil plays in the world.  And just like in North America and the Bakken, a junior player was the leader—Toreador Resources, TRGL-NASD.

How this world class play got developed was textbook geological sleuthing.  I wrote a full length story on it HERE.

Toreador’s stock ran from $5 last year to $18 in February this year before the French government took a fast and bold step to ban fracking country-wide—sending the stock to under $3.

How does a junior company survive such a mortal blow?  It’s a question more investors should be asking as environmental concerns surrounding hydraulic fracturing are having a bigger impact on community relations and speed/time of drilling programs.

Only three weeks ago the Environmental Protection Agency (EPA) in the United States suggested publicly that all fracking in the Bakken could stop next month—January 2012.   That was quickly shot down by the North Dakota senator the next day.

Down in New Zealand, TAG Oil shareholders were subject to local residents appealing their permit to drill wells—which will be fracked.  At the last minute, they said they could not afford to prolong their protest.

In the eastern Canadian province of New Brunswick, citizen groups and environmentalists opposed to fracking have been blocking roads and staging demonstrations

The concern around fracking is real, and it’s global.

For Toreador shareholders, it meant an immediate and sustained hit to their wallets, with the stock losing 80% of its value in months.

For management, it meant speeding up their process of trying to diversify out of that one play—even though Hess was spending the next $250 million—and led to a merger with a larger private company with a surprisingly similar play in Texas.

Merger documents filed with the Securities and Exchange Commission in October show that Toreador was already looking at ways to diversify the company.  Their stock price was rising, giving them good currency to do a big deal.  But nothing fit just right.

The French ban on fracking obviously made a second play a lot more important.  You can try to produce a shale-like the Liassic without fracking, but flow rates will be MUCH less than with fracking—and they would still have the steep decline rate regular shale wells have around the world.  It’s not the sexy production growth profile that would entice investors.

So after having in-depth discussions with several groups, Toreador’s CEO, Craig McKenzie, struck a deal with a private company, ZaZa Energy, which had some synergies with Toreador.  They too have a large joint venture with US giant independent producer Hess Corp. (HES-NYSE) – but theirs is in Texas.  And their joint venture is worth $3 billion, 10x what Toreador’s deal was.  ZaZa’s JV with Hess in the Eagle Ford covers 123,000 gross acres with Hess covering all costs related to land, drilling and completions.

Back in 2009 ZaZa’s owners – three seasoned Texas oilmen – and McKenzie’s team were each doing the same thing—getting started on a new frontier play and trying to find a JV partner.

Coincidentally, they both landed Hess around the same time; Hess signed its deal with Toreador about a week after signing with ZaZa.

According to recent filings, that merger should be completed this month, December 2011.  The new company will trade under the symbol ZAZA.  ZaZa gets 75% of the newco, but McKenzie will remain as CEO.

According to merger documents, by the end of 2013 the new ZaZa will be looking at a combined production of 6000 boe/d, fully paid for by its JV partner, Hess. With production today at about 900 boe/d, that represents a six-fold increase in the near future, and an even greater increase in cash flow given the current price of oil and the fact that capital will be provided by its partner.

How do they get there from here? By combining an estimated 1,000 boe/d from the Paris Basin with nearly 5,000 boe/d from the Eagle Ford post-combination, plus any production they get from their 100% owned Eaglebine property—or other acquisitions.  By 2013, the new ZaZa will drill and complete an estimated 280 wells in the Eagle Ford alone—all paid for by Hess.

Hess will spend $2.5 BILLION in the next two years, before Dec 31, 2013, on ZaZa’s Eagle Ford shale properties. ZaZa entered the play early, grabbing 14,000 gross acres, and then adding 109,000 acres with Hess.  Hess can earn 90% of this by spending the money.  To date, ZaZa has drilled 25 wells and has completed approximately twelve in the Eagle Ford with a 100% success rate and the wells are producing above the industry average.

On top of that, ZaZa has 80,000 acres gross, 62,000 acres net, in the emerging Eaglebine play, which is really an Eagle Ford extension. The Eagle Ford started on the southern border of Mexico and has steadily trended north and east until reaching what is historically the Woodbine area.

Now the area is being relabeled as the Eaglebine as it heats up with Eagle Ford type activity.  There are multiple horizons for oil and liquid rich gas in the play.  ZaZa is an early mover in the region and is moving their first rig into the play in Q1 2012.

Production in the area ranges from 150-1350 bopd IP rates for oil, with most in the 600-1000 bopd range, and gas production as high as 19.2 million cubic feet per day IP rates.

The 6000 bopd target rate set by McKenzie doesn’t include any production from the 100% ZaZa owned Eaglebine lands.

Based on Toreador’s most recent corporate presentation, with nine conventional targets and three shales, the Eaglebine is probably more exciting to McKenzie’s team than the core acreage in the Eagle Ford.

Early drilling results in this emerging region are intriguing, with one vertical well only a mile from ZaZa’s acreage producing 900 bopd.  McKenzie has stated that once the companies are combined he expects to grow the Eaglebine position to 100,000 acres in the near-term.

McKenzie has also been clear with investors that his job is not done, post-merger.  With hundreds of small operators in Texas and limited capital, somebody like the new ZaZa can consolidate a lot of land and production.  McKenzie wants to be that Somebody.

The role of consolidator won’t come easy though.  Surprisingly, capital is still very tight in the Eagle Ford–and as companies’ leases expire over the coming years, many CEOs are desperate for funding.  Despite the hot play and 100% success rate in the Eagle Ford, investment bankers aren’t spilling their lattes from jumping all over E&P companies trying to give them money.  There is money available but it’s not cheap.

Because production in Eagle Ford is still young, and services supply is tight, that creates uncertainty.  ZaZa has distinguished itself as being a fast executor and it has all the agreements with the suppliers.  For any private small cap with expiring acreage, bypassing a traditional IPO by merging with a public company, as ZaZa did with Toreador, can be a good option.

As for France, the Paris Basin is now third in line for the new ZaZa.  At Toreador’s annual meeting this year, McKenzie said Toreador has identified 15 conventional prospects targeting 40 million barrels of reserves and will start drilling in early 2012.

Toreador also managed to extend its partnership with Hess to develop the Liassic resource.  Hess will be operating a one-rig, six-well program, beginning in 2012.    How the Liassic responds to horizontals without fracking will be the “tell” on whether this play can really get off the ground.

What’s been happening in France since the fracking ban is also interesting. The media has been asking, was the government too rash?  Is France missing out on something as the country now has a 19% unemployment rate?  The nuclear industry has aging plants and they recently experienced their first radioactive incident.  Rhetoric from the media and certain key politicians has been less rabid.

But until the French political will changes, it’s truly Texas Tea Time for Toreador.

DISCLOSURE: Keith Schaefer owns Toreador Resources

The Surprising News about U.S. Oil Production

Dear OGIB Reader,

The U.S. likes to fancy itself a place that does everything a bit bigger and better than the rest of the world.

And while some of this might just be American bluster, the Yanks have plenty to crow about it when it comes to oil production in recent years.

James Burkhard, the managing director of IHS CERA’s Global Oil Group, said at a Montana Petroleum Association conference that U.S. production of oil increased by 1.2 million barrels per day between 2008 and 2010, reports the Billings Gazette. This reversed four decades of decreasing domestic oil production. 

“Not only have we reversed the trend, we’re reversing that in a very big way,” Burkhard said.

However, the U.S. may not be done when it comes to upping its oil production as The Sunday Times recently quoted a report released by Goldman Sachs that predicts America will become the world’s largest oil producer by the year 2017. This estimate was obtained by using a different definition of oil and utilizing generous estimates for liquids-rich shale production, according to The Oil Drum web site.

Using these new parameters, the report predicts that U.S. daily production of oil will rise to 10.9 million barrels in 2017 from the current level of 8.3 million barrels, according to the media outlet. This estimate is not unreasonable when one considers the growth the country attained between 2008 and 2010.

The news source states that how Goldman Sachs arrived at the current production level of 8.3 million barrels of oil per day is ambiguous. June oil production for the country averaged 5.6 million barrels per day in June, the Energy Information Agency (EIA) reports.

Predictions for U.S. oil production released by the EIA differ from the figures released by Goldman Sachs. U.S. crude oil production will increase to roughly 6 million barrels of oil per day by 2020, according to the agency’s 2011 Annual Energy Outlook. The EIA attributes gains in production to larger shale oil resources and new enhanced oil recovery techniques. The agency states that the Eagle Ford shale, Bakken formation and the Marcellus shale will all contribute to this rise in production.

Thomas Petrie, vice-chairman of global corporate and investment banking at Bank of America, offered another estimate. He told Reuters that over the next five years, U.S. oil production stemming from shale plays such as Eagle Ford, Bakken and Niobrara could potentially increase to 2 million barrels per day.

What makes Goldman Sachs’ prediction even more surprising is that its estimate would place U.S. production higher than that of Saudi Arabia and Russia. Press reports stated that Russia will not increase its current production of 10.7 million barrels of oil per day by any more than 100,000 barrels in the coming years. For what it’s worth, Saudi Arabia says it can produce 12 million barrels of oil per day by 2020, reports The Oil Drum.

This huge increase in U.S. oil production hinges on a number of important plays located across the country.

One of these plays, the Bakken shale, has grown rapidly in recent years. Production at Bakken-Three Forks has climbed to around 400,000 barrels per day and some industry insiders believe that number could eventually be greater than 1 million barrels of oil per day. The Permian basin will significantly contribute to rising production of U.S. oil. Permian production was at 841,000 barrels per day in 2004, according to Well Servicing Magazine. The Oil Drum estimates that in 2010, this figure crept up by 100,000 barrels.

Another play that could contribute significantly to production is the Marcellus shale. A United States Geological Survey report released in August estimates that the Devonian Marcellus shale formation holds 84 trillion cubic feet of natural gas that could be recovered and 3.4 billion barrels of untapped natural gas liquids.

The Utica shale, which exists below Marcellus, is another play that holds significant potential. Aubrey McClendon, President of Chesapeake Energy, told The Gartman Letter that it currently has 12 horizontal drills that are active in its section of the Utica. Some estimates put the amount of oil in the Utica formation at 5.5 billion barrels.

Regardless of what U.S. oil production is predicted to reach within the next decade, it is clear that the country will be one of the largest producers of oil in the world for years to come.

Retail consumers of oil – and retail investors of oil – are the big losers now that oil has become a financial product, says Dan Dicker, author of Oil’s Endless Bid.

But the irony is they’re doing it to themselves—by buying oil ETFs (Exchange Traded Funds) and ETNs (Exchange Traded Notes) and other financial derivative products based on oil.

I only came up for three gulps of air while reading the book, and I emailed Dan immediately afterwards asking for an interview.  He writes in a simple, earthy and honest way—that I wouldn’t have expected from an oil trader on the floor of the New York Mercantile Exchange.

One point he explained so well to me was that the investment banks that now dominate trading have created a massive new market of buyers, and only buyers – no sellers – with their financial products like ETFs.  And that has inflated the price of oil for consumers.  The oil price nowadays is not just based on fundamental supply and demand.

“In 1980 oil demand was about 60 million barrels a day.  In 1990 it was 70 million and in 2010 it was about 90 million.  What’s interesting is that demand has been fairly steady in how it’s increased; about 10 million barrels a day each decade.

“But the oil price has been entirely flat for 20 of those 30 years.  What that says to me is that something clearly changed in how we’re pricing the stuff in the last 10 years.”

And that something is the involvement of the financial industry, he says.  “It’s all about the pricing mechanism, who’s involved and the money being thrown at it.”

That money comes in the form of ETFs and index funds all geared around the price of oil, and are obviously set up by the big investment banks.

But Dicker says that is ALL “long” interest, meaning they are all BUYERS and not SELLERS.  And we all know what happens to the price of something when are more buyers than sellers.  The price goes up.

“What has happened in last 10 years, those who have been setting price based on fundamentals in the market have been swamped out by the financial sector, who have very little engagement with the physical product.  Yet their input is equally important to the price of oil as those physically involved in the sector.

“The market is democratic, but it wasn’t designed to be democratic.”

And there is the irony!  Oil becomes a democratic market—where institutional and retail investors get to help set the price by all of their buying in these indexes, ETFs and ETNs to gain exposure to the oil price (which isn’t possible, Dicker writes) but in effect drive the price up.  So they pay more at the pump.  Democracy at work!

And sadly, the other side of the coin is that the investment banks make a nice share of the coin in the oil trade.

“The stock market can theoretically have a whole group of winners as the stock market goes up—forever.  With oil that’s not true.  When someone buys oil, someone has to sell it to them.  At the end of the day or month or year when trades settle the amount of money won equals the amount of money lost.  When institutions make money trading oil, that eventually comes out of the pockets of people filling their tanks, refrigerating their meats— it’s a zero sum game.”

Well, wait a minute Dan—you just said everybody in oil is long, i.e. they’re buyers, but then you just said there has to be a buyer for every seller.

“Yes, almost everyone who is investing and even hedging oil is long, so the market has to somehow generate sellers, something the stock market for example doesn’t need to do.  So how do you generate sellers where there aren’t any to begin with?

“Well, first, you must make the price pretty high:  Imagine you own a $100,000 house in a neighbourhood of $100,000 houses and all of a sudden, a new group of home buyers wants to have your house, for whatever reason.

What will get you to sell?  Well, someone knocking on your door with a $200,000 check might get you to think about it.  So, price is driven artificially higher, that’s the first thing.”

“But sellers in an oil market also don’t have physical assets.  Even when enticed by a high price, they need a hedge for those sales, because they don’t have oil to deliver, any more than buyers want to actually accept deliveries of oil.”

“So, in generating sellers, you also generate trade correlations. Like, the corn chart and oil chart look almost exactly the same. And the correlation between oil and oil stocks become uncannily close.”

“So you get these trade correlations, but not a fundamental correlation.  So we now have a very different correlation between the oil market and the stock market than what we had before.

“The oil market-stock market trade looks like a correlation, it’s perceived as one, but it doesn’t make sense, because high oil prices are intuitively not good for the stock market.  So they call it a measure of growth.

“Now we’re looking at a double dip recession and EU going down and oil prices more than $110—how does that fundamentally make sense.  It doesn’t because the marketplace designed for producers and consumers is overrun by people who are financially engaged.”

OK, now I am a believer that there is big premium in oil because it has become a financial product.  How big is that premium and how does… can it ever go away… can we ever end The Endless Bid on Oil?

“You’ll never know what the premium is until you remove this financial mechanism.

“The chances of ending it IMHO are pretty slim.  The path to fixing this is simple to see—but making it happen is nearly impossible in practice.

“You would need to restore the market to close to the way it was before these financial influences took control of it, and let commodity markets operate the way they were intended.  The financial industry will say that’s a destructive rollback of investment trading.  The banks and the entire financial industry have big stake in this.”

In his book, Dan tells some great and funny stories about how he won and lost lots of money (for him) on the old NYMEX floor, despite being a very small independent oil trader. In between the wry smiles, you will get his core message:

“Treating what was a commodity as if it was a stock, is inherently a bad path toward a pricing model that will be volatile, unreliable and unfairly high.

“This is a commodity that people rely on (in their daily lives), and they’re treating it like it’s investable—and the outcomes are fairly obvious to see.”

You can buy Dan’s book — again, it’s very simple English — at Amazon. Here is the link:
Oil’s Endless Bid: Taming the Unreliable Price of Oil to Secure Our Economy

Oil and stock indexes (such as the TSX Composite) are gauges that can be used for picking individual stocks. Since certain stocks will perform better than these benchmarks, and other stocks will perform worse. We want to find the ones which show the most promise. This is done by comparing the price action of individual stocks to oil and stock indexes.

Oil and stock indexes are highly correlated (move with each other) over the last decade. This was not always the case, pre-1999 oil and stock indexes had a very tenuous correlation, often moving inversely. By using both oil and stock indexes we can improve our chances of picking quality stocks.

What I like to see when oil and the TSX Comp are falling is an individual stock that has sold off, but is no longer dropping. If it is no longer falling as oil and overall stock market continue to fall it is a good sign. This phenomenon is known as “relative strength.”

Here is a recent example: Canadian Energy Services (CEU.TO) has performed better — in percentage terms — than oil and the TSX Composite over the last year. Recently when the oil and stocks declined rapidly in early August, CEU.TO sold off as well. The interesting thing is that while the TSX and oil made new lows for the year, CEU.TO did not even make it to the low it saw in June. (Disclosure: CEU is an OGIB stock, and Keith Schaefer owns shares).

Figure 3 shows this visually. CEU.TO is the green and red bars, oil is the purple line and the TSX is the yellow line.

Figure 3 – CEU.TO vs.TSX and Oil

Source: Freestockcharts.com, August 17, 2011

Figure 3 shows an example of the type of action we are looking for. By finding stocks with similar patterns over the long-term, positions can be taken for when equities and oil begin to trend higher once again. That trend may be some months away as there exists the potential that stocks and oil continue to move lower over the next several months.

CEU.TO is a short-term example, but as the stock market and oil continue to decline (in my opinion) what are we looking for down the road? In the 2008 decline CPG.TO showed great strength as oil and the TSX Comp continually made new lows. Figure 4 shows CPG (red and green bars) vs TSX (yellow line) and Oil (purple line).

Figure 4. CPG.TO vs TSX and Oil

Source: Freestockcharts.com, August 17, 2011

CPG made lows in early December of 2008 (circle labeled “1”), and oil and stocks continued to decline into February and March respectively. The fact CPG would not go lower as these two benchmarks went lower was a signal to buy the stock.

Be afraid of stocks that have been hit and hard and continue to fall. Love stocks that have fallen and stopped falling as oil and the broader market continue to decline. This shows selling is exhausted and any positive news or push higher in oil prices, stocks or the sector will raise the price of the stock.

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Exploration/Production or Services – Is there is there a return advantaged sector?

On a final note, I wanted to look at the performance of the Oil Services Sector and the Oil Exploration & Production Sector to see if there is an edge to be had by one or the other.

Going back to January 2007 (the starting point of the trend which brought $100+ oil) there are several points of interest:

Both sectors are highly correlated to each other and to oil. The only real difference is slight-moderate variations in performance.

In early stages of an uptrend in oil prices the Service sector performs very well. At the major low price in oil prices in January 2009, the Services hit bottom first (December 8, 2008) and showed early strength. Exploration/Production bottomed 3 months later but caught up and two sectors moved in virtual lock step to the recent April, 2011 highs in oil and the sectors.

From when Services bottomed in 2008 Exploration/Production outperformed just slightly, but that can be a bit deceiving…

Over the last 12 months and also year-to-date, Services have been outperforming, indicating a shift may be occurring and Services may begin performing better during all stages of the oil trend.

Any stock can outperform at a given time, but there is evidence there may be a slight performance edge in the Oil Services sector. Not only does the sector as a whole usually bottom first, but it is now performing well across all stage of oil bull markets. Stocks that bottom early and stop falling as oil continues to decline are exactly the type of stock you are looking for to buy.

Investor Take Away

Oil and the stock market are correcting and there is potential of a recession. This provides a great opportunity over the next several months to begin looking for oil related stocks which are no longer moving lower, even though crude prices and the stock market indexes may continue to decline. This is called “relative strength.” It is a sign that this stock is strong and if it can’t fall even when market conditions are unfavourable it means the next likely direction is up. The more companies we see that start to show relative strength to crude and stock market indexes falling the closer the markets are to a full reversal.

The Oil Services sector as a whole generally bottoms before oil prices, therefore looking for stocks within the sector that hold their ground will likely provide positive returns when oil and stock indexes begin to move higher. Regardless of where oil prices or stock indexes go, it is always advantageous to buy stocks which have relative strength.

Today’s story comes from guest writer Cory Mitchell, who gives us an in-depth look at Bankers Petroleum — one of the most widely followed international junior oil companies in the world.

- Keith

Bankers Petroleum Stock (BNK – TSX) Disappoints – Is it still a Buy?
By Cory Mitchell, CMT

Bankers Petroleum (BNK – TSX) provided an update on second quarter (Q2) operations after the market close on Tuesday, July 5 – causing a huge down-spike in price on big volume. This former OGIB pick has become one of the most highly followed junior oil producer in the North American markets – covered by 16 analysts and owned by many Canadian, US and European small cap energy funds.

Bankers’ is developing Europe’s largest onshore field, which is in Albania. Three things have made the market very excited about this field, and therefore Bankers’ stock:

1. This huge field (called Patos-Marinza) has over 7 billion barrels of Original Oil in Place

2. Horizontal drilling has dramatically improved production rates per well, so that wells pay out in 6-11 months. (Anything under 24 months is considered good)

3. Production declines much more slowly out of these horizontal wells than the light oil wells of the Bakken and other horizontal plays around the world.

It was originally a stock based on the huge reserves in the Albanian fields, but now is becoming a cash flow growth story as well – especially as heavy oil has been getting a better price around the world.

Yet, while the company did increase production handily over last year, it did miss the production estimates it gave to the market and downgraded its own expectations for year-end production volumes.

The disappointing current and forward looking guidance dropped the stock to its lowest level in 16 months. Based on the fundamental data of the company and technically analyzing the stock performance I will look at whether buying (or holding if already owned) at the 16 month lows is likely to be a profitable endeavour.

Was the Sell-Off Warranted?

BNK reported below expected production and sales levels, producing an average of 12,973 bbl/day, a 7% improvement over Q1, but missing the company’s own forecasts by 1200 bbl/day. Current production is at 13,150 bbl/d, which is up 44% from the same quarter last year.

The company could had have actually come closer to hitting the target (would have missed by about 500 bbl/d) but shut-in production was 60% higher than normal. Shut-in production is when the company pulls out less oil than what the available output is.

Bankers’ management gave three reasons for this:

1. Several wells required service rigs

2. Others were in proximity of new drilling

3. Wells were also shut in because they couldn’t get rid of all the water for wells with high water production.

The company has sourced another service rig which should arrive in Q3, and one or two more in Q4.

Service rigs are required to maintain producing rigs and complete new wells. Wells require regular maintenance including pump changes, with re-activation wells often needing additional work due to deterioration over time. These service rigs should bring the shut in production down to normal levels of 1050-1100 bbl/d but service rig requirements will continue to grow as more production comes online.

Wells being shut in due to proximity to new wells – they are draining the same area of the reservoir and the new wells are modern and do a better job. This is common in the global oilpatch and largely considered good oilfield management.

Water disposal wells are being equipped to handle additional water volumes which should alleviate this issue.

With oil prices higher, especially Brent crude, BNK was able to get better pricing with the average price received increasing 13% over Q1. Despite this increase in revenue per barrel, overall sales lagged. One key factor for this is a major order which was delayed and will be included in Q3 results instead – this accounted for about 600 bbl/day leaving 221 bbl/d unsold.

With increased oil production, Bankers now has the critical mass that it can get several refineries to bid against each other for their heavy crude. Between this competition and overall higher oil prices, its profit per barrel (called the NETBACK) has increased year over year from $20.98 per barrel to $37.22 per barrel – a 77% increase.

Company oil inventory levels went to 239,000 barrels, up from 168,000 barrels on March 31. This is not an issue if it is short-term, as new site and storage tanks required certain operational minimums. If inventories continue to climb, affecting sales, this would have a dampening effect on financial and stock performance.

Several analysts dropping price targets also likely played a role in BNK’s stock value decline, yet ultimately shouldn’t have, as analysts continue to like the stock. According Thompson/First Call, the 16 analysts covering the stock hold a median and average price target of $11 and $12 respectively.

New Projects with Promise

Successful new projects on different areas of Patos-Marinza field will be major factors driving Bankers’ oil production higher.

New test wells in the northern Gorani area of the field is one such project where the company is looking to expand production–if those well tests continue to produce good results. Gorani has heavy oil which is accessed by vertical and horizontal wells.

A third Gorani well is awaiting completion in (Area-1) with the first two wells already producing 170 and 180 bbl/day. Canadian brokerage firm Raymond James says this is a big positive, as those rates are higher than what the independent reservoir engineer used to calculate reserves here. The company stated in their Q2 (2011) Operational Update:

The success of these two wells has now validated primary productivity from the Gorani formation in the northern area of the field and the Company intends to further develop this formation with the addition of a large number of horizontal wells to access more than 220 million barrels of oil in place.

BNK also maintains plans to drill six to eight Driza and/or Gorani wells in another area (Area-2) of this field which, according to Raymond James, could allow for even further reserve potential. Successful results will lead to a much larger program with expectations in the 50-100 well range over the next several years, saysDundee Securities Ltd. “Driza” wells refer to the vertical or horizontal drilling of the area below the Gorani formation where the oil is less heavy, or lighter.

As mentioned, the company plans to drill 82 re-activations of old wells, and to drill 79 horizontal new wells. Bankers’ says 34 horizontals have been drilled through Q2 making it possible to hit the 79 target, yet they are currently behind. Well re-activations are well behind management’s projections, with only 22 so far this year.

That said, they have many re-activation candidates as the company announced in April it would be acquiring 140 active Albpetrol (former sole-operator in the Patos-Marinza field) wells. So the number of re-activations could increase quickly.

NEXT STORY: Part 2 — The technical outlook and conclusions for Bankers Petroleum’s stock.

– Cory Mitchell, CMT

Disclaimer: The information provided is as of the date above and subject to change, and it should not be deemed a recommendation to buy or sell any security. Much of the fundamental information is based on company statements and therefore are dependent on company honesty. Trading involves substantial risk and may not be right for everyone. Certain information has been obtained from third-party sources we consider reliable, but we do not guarantee that such information is accurate or complete.

Cory Mitchell owns zero Bankers Petroleum. Keith Schaefer owns zero Bankers stock. Neither the author nor the publisher have any affiliations or associations whatsoever with the company.

With an oil pipeline to the west coast, Canada’s oil sands could be the big swing producer in the global energy market, says Ralph Glass, Director Energy Valuation and Operations of AJM Deloitte, an oil and gas technical consulting firm in Alberta.

But without a pipeline Canadian oil production could actually get shut in, he warns, as US oil demand is flat four years in a row and their Cushing oil storage facility in Oklahoma is almost full. 

It is a feast or famine future scenario for Canadian oil sands production.

“If we had alternative markets, Canada could possibly be the swing producer in the world, not the Saudis,” says Glass.  “We would have enough spare capacity that we could help fill the (world demand) gap and influence prices.”

Right now all western Canadian oil is shipped to one place: The USA.  Alternative markets means: Asia, via a pipeline to the west coast where tankers would transport it across the Pacific.

Glass points to the oil sands projects that are now on the table (you can see them all here: http://www.oilsandsdevelopers.ca/index.php/test-project-table/) which total over 7.5 million barrels a day of production (bopd), though much of that won’t be online for years.  Current oilsands production is roughly 1.5 million bopd.

All this oil supply will be great for consumers and Canada’s economy (jobs and royalties) and for geo-political stability in energy prices.

But with the US increasing oil production for the first time in 40 years – thanks in large part to the shale revolution in the Bakken oil formation in North Dakota – Glass says there is a chance that the US might not need Canadian oil as much – in the same way he says Canadian natural gas is vulnerable to being shut out of the US market because of increased US natural gas production.

“There is more than ample (oil) supply in North America, so everybody is going to have to line up as take less, and they’ll have to produce less,” he says.  “And as with natural gas, the US will take their product first.”

He adds this problem is mostly long term, but there could a short term production glut in North America as soon as the next six-nine months.

“We’re coming into a lull now – Q3 is usually a slow point in world demand.  But then we see a dramatic increase in Q4 of 4 million more barrels per day of demand over Q3.  What I don’t know now is, can supply meet that increased demand in Q4/Q1 2012 in the world?

“If it cannot then this is a mute point – but if can then Cushing could get filled (and producers) may get their product reduced.”

Not everybody agrees with Glass’s concerns on Canadian crude.  Adam Bedard is Senior Director with Bentek Energy, an energy market analytics company based in Denver Colorado.

“Canadian heavy crude trades back about $20 from WTI, which makes it very competitive to bring to market.”

If any foreign crude gets shut out of the US, says Bedard, he expects it would be imports from Nigeria.

“I think Canadian crude squeezes out other crudes.  I would sure be surprised” if Canadian crude was displaced out of the US.  He added that doesn’t see Cushing ever being full – the builds in supply are slowing, and rail and pipeline capacity out of Cushing is being developed.

Bedard said he didn’t think that storage at Cushing will be the bottleneck, but there could be a limit on refining capacity which could push back on demand for Canadian crude – though the U.S. Gulf Coast refining complex has added capacity allowing them to refine heavy crude.

There is no stranded oil sands production right now, but Glass says that $20/barrel discount that Canadian heavy crude is getting compared to other world oils is costing the Canadian economy.  Assuming 1 million barrels a day of oil sands production going overseas, instead of down into the US, Canada could stand to gain about $3.65 billion for every $10/bbl more revenue it could get than it’s receiving now.

“Price and volume (of Canada’s oil exports) are being impacted without a pipeline to west coast.  We’re getting significantly less for our products than they could on the world stage.”

This chorus is getting louder.  Scotiabank’s head commodities analyst, Patricia Mohr said in a June 28 note that “In my view — given the substantial forecast growth of Alberta oil sands production in the next 5-10 years… in the face of only limited U.S. consumption gains — building further export infrastructure… to the B.C. Coast to reach fast-growing Asian markets is vital for the Canadian economy.”

She estimates oil sands production will grow by 600,000 bopd per day by 2015 and by 1.2 million bopd by 2020.

Currently Light Sweet Crude futures remain in an uptrend, over the last month price has tumbled from former highs at $114.83 in May to $95.25 currently on the July contract.  The two-year chart below, in 2-day increments, shows the course of oil prices with a continuous futures chart.

ETFs allow individual investors to partake in the price fluctuation of oil in a way very similar to simply purchasing a stock.  (For further information on ETFs, see Keith Schaefer’s report: ETF Investing in the Oil & Gas Market).

The chart below shows the price of light sweet crude in yellow/red, and two ETFs – USO-NYSE, which is the United States Oil Fund (purple), and an ETF which gets far less attention – XOP (light blue).  XOP is the symbol for the SPDR S&P Oil & Gas Exploration & Production ETF traded on the NYSEArca exchange – so it is an ETF that covers oil stocks/equities, whereas USO tries to track the commodity.

How to use ETFs to predict moves in the price of oil How to use ETFs to Predict Moves in the Price of Oil

Source: Thinkorswim

General Chart Comments

From the chart above much information can be extrapolated.  Namely we can see that at this time oil still remains in a primary uptrend, even though we have seen a sizable correction.  There are two trendlines shown on the chart – the first one is red and indicates an aggressive upward trend.

At some point all aggressive moves slow down.  The green trendline is also present which marks the more stable rise of oil prices over the last year.

If oil prices move below that red line, currently intersecting at $92 (this will change over time as the line is sloping), it indicates that oil is correcting to its primary uptrend level (green line).

The green line currently intersects at $80, but will rise over time as the line is sloping. An upward sloping trendline such as this helps a trader gauge when longer term trends are shifting.  Markets move in waves – in an uptrend, markets have progressively higher low prices and progressively higher high prices.

If oil can hold above the $92 level it indicates strength, based on this simple method derived from former price action.  On the other hand, if the commodity moves below that level we could see prices in the low$80s, where there is likely to be buying interest once again.

Using ETFs as a Form of Analysis

The ETFs shown in the chart are not only investment vehicles, but they are also analysis tools.  USO (purple on chart) has already broken below its trendline (yellow line) indicating that lower prices are likely for that security.  This provides some confirmation of the decline in oil, although XOP is a better gauge.

XOP provides valuable information.  Not only has it been the far more profitable play from rising oil prices, but also generally leads oil prices – providing a bit of a snapshot into potential moves in crude.

This occurs because XOP is an ETF that doesn’t track crude – it tracks oil exploration and production companies – which provide a large input the for the oil market as a whole and thus the price of oil.  If investors are buying these securities, which are held by a sector ETF such as XOP, it indicates that the market is anticipating rising oil prices.  The same situation applies if investors are selling these securities help by the XOP ETF in anticipation of falling oil prices.

Looking at the chart, XOP (light blue) has moved aggressively higher over the last year.  Rarely did it pull back significantly, even when oil declined.  I have highlighted a few sections of the chart for educational purposes.  The first, light blue highlighted box on the left s (#1) hows XOP making a lower price high, while oil made a higher price high (all contained within the rectangle).  This was a warning for oil prices and quickly oil prices corrected by about 15%.  This is commonly called divergence.

The next box to the right (#2) shows oil correcting to the prior low yet XOP pulled back very little in comparison – oil quickly moves higher following XOP’s lead.  The next highlighted blue box (#3) shows a similar situation to the last – XOP leading oil higher.

The final box is highlighted in white (#4) and is a potential warning signal similar to our first highlighted area.  For the first time in over a year XOP made a lower high, while oil made a new high.  This was a warning signal for the correction in oil, and remains a warning signal.  XOP has shown a strong tendency to lead oil prices and now it is retreating, leading oil lower.

You will notice at the far right of the chart, which shows June 15 price action, that while oil has paused near recent lows, XOP has retreated below its recent low.  This makes further declines in oil likely, as long as XOP continues to decline or fails to rally on oil price rises.

Tying it together

Investors can use the XOP ETF to help them see the likely course the commodity will take.  XOP has been a sound indicator for the strength of oil prices.  It pointed to strong oil prices through the rise, and even when crude corrected, it indicated a correction which has come and currently it is pointing to a further correction in oil.

In the beginning of this report the low $80’s was discussed as a potential target for the oil price.

If oil continues to drop below that level, we can look to the XOP indicator as a sign of a potential bottom.  When oil makes new lows (compared to recent price action), but XOP fails to make new lows, oil prices have a high probability to begin moving higher as well.

While USO comes to mind when looking for a place to take advantage of a rise in oil prices, it has proven not to be the most efficient vehicle.  XOP, when oil prices are rising, has proven to lead oil and also generally outperform.

Investors must remember XOP will also lead on the way down, retreating fast and more aggressively than oil; therefore, a prudent exit strategy is required. XOP also lacks the trading volume that USO has (still 2-10 million shares a day), yet it functions as an excellent analytical tool for oil prices.

http://oilandgas-investments.com/2011/oil-prices/how-to-use-etfs-to-predict-price-moves-in-oil/

Natural gas producers have taken a beating over the past three years but there are encouraging signs that natural gas might be ready for a break to the upside.

Despite a seasonably weaker shoulder season, NYMEX prices are inching above 10-month highs and observers are finally buying into the idea that stronger prices are around the corner.

Longer term outlook expected to strengthen

The International Energy Agency (IEA) said this week that natural gas is about to enter a “golden age” with world-wide gas use to increase by 50 per cent by 2035.

That might seem far away, but the immediate present has also been encouraging of late.

Calgary based energy economist Peter Tertzakian is now predicting declines in existing production will trump new production adds from the big new shale plays, driving prices higher.

All the while, US industrial demand growth is the highest in a decade, according to the Energy Information Agency.

Add some hot weather in big consuming markets and we’ve seen a nice steady rise since May.

The contrarian view: buy low sell high

Already we’re starting to see some movement on analyst price forecasts.

FirstEnergy is a boutique brokerage firm in Calgary specializing in oil and gas.  Their analyst Martin King said Tuesday that a longer-term average gas price of $5.50 is “reasonable” heading into 2012, although his own 2011 forecast still calls for an average of $4 for the year.

The difference between the two numbers sums up the opportunity in a nutshell–almost 30 per cent on price alone. It’s not unreasonable to expect stocks to follow suit with higher multiples and valuations.

Unfortunately the pure play gas producer has become an endangered species and it’s hard to find a lot of names with growing production exposed to rising spot prices.

The gas trainwreck survivors: lean and mean

The good news is that the producers that managed to stick around over the past three years are bonafide survivors. They’ve taken a beating and still managed to be profitable through the down cycle.

In fact, many have thrived and have quietly posted nice share price appreciation. (See our story on the Surprise Junior Stock Performers)

Although some, like Birchcliff Energy (TSX-BIR), are near 52-week highs, there could be even bigger upside around the corner. In fact, there WILL be more upside with higher gas prices.

The company has been furiously developing its Montney play in Alberta and says it can still make money at a natural gas price of $3/mmcf . The company has posted positive earnings for nine consecutive quarters and has all of its production un-hedged to sell into a rising market.

It’s spending more than $260 million this year to double its processing capability which will give it room to ramp up volumes.

Peyto Exploration (TSX-PEY) has been in the wilderness forever it seems, but it is also testing year-highs. Both companies have made solid share price gains Peyto alone has quadrupled since the market low in 2009.

Crocotta Energy (TSX-CTA) is another survivor that was forced to sell assets and recap the company in September of 2009.

Since then its share price has doubled while it works liquids rich gas near Edson in central Alberta.  Liquids are in big demand in the heavy oil patch and amounted to almost a third of Crocotta’s first quarter production. Notably, Tourmaline (TXS-TOU), which just bought out Cinch Energy (TSX-CNH), is just to the west of them.

Advantage Oil and Gas (TSX-AAV) posted a small loss of three cents in Q1, which wasn’t bad considering it spun off its oil assets to focus on its core Montney development. It has 28 million cubic feet a day hedged at Canadian prices of $6.25 a gJ, which will protect the balance sheet until a full-blown recovery takes hold.

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Longer-term exports hold promise

Looking even longer term, big players like Encana, Apache and EOG are looking at exporting LNG, or Liquid Natural Gas, off the West Coast of Canada.  Natural gas prices in Asia are about double what they are in North America, and even after shipping costs producers will be making a lot more money selling gas in Asia.

But smaller players have bought in as well.  Earlier this month Progress Energy (TSX-PRQ) teamed up with a Malaysian company, Petronas, one of the world’s largest LNG companies, to develop unconventional gas and build a second LNG export terminal in B.C..

These are huge multi-billion dollar investments, and the risk is all going to be project execution and raising enough money to stay in the game. Having a huge multi-national for a partner is a huge plus in that regard. But this is definitely a five-year payback; patience is the key here.

But it suggests things are looking better in a previously dead-end sector with nowhere to go but down. Six months ago, few if any analysts gas prices would be close to $5/mmcf in North America – almost everybody was predicting lower prices.

It remains to be seen if this is a sustainable recovery for producers and their investors. Timing and finding ways to profit from a rebound will be the test.

http://oilandgas-investments.com/2011/investing/the-outlook-for-natural-gas-the-stocks-with-upside-around-the-corner/

In terms of fundamentals, this really is a cry for help.

a. 60 million barrels equals about 18 hours of global production – hours, not days or weeks. It’s inconsequential.

b. The world is already well supplied with oil – there is no shortage of oil anywhere on earth that I can see.  North America in particular is overflowing with oil.

c. Oil doesn’t trade on its fundamentals, or it would be $60-$70 a barrel right now. Or pick your own number.  But it would be lower.

In terms of market psychology however, the IEA may be smarter than the pundits think.

Oil, like all markets, trades on fear.  And there is now so much liquidity in the world that often (if not usually) the tail wags the dog in commodity markets.  What I mean by that is that the financial derivatives surrounding oil – the ETFs, the futures contracts etc. – help determine the price of commodities as much as the underlying demand.  So managing their fear and greed of investors in those products is a bigger job than ever before.

With this new reality that has developed over the last decade, but especially since QE1 & QE2, I would suggest the governing elites of the world (DAD) need a new way to communicate to the capital markets (MUSCULAR INDEPENDENT TEENAGER) to really get their attention that they will pull out all the stops to obtain a semi-permanent lower oil price.

But what it could do is convince many of the new entrants in the futures market to dump their “oil long” holdings.  Speculators have been buying oil long contracts in record amounts up until a few months ago. See this chart from Canadian brokerage firm Canaccord Genuity:

Now, the chartist in me says that after a recent round of weakness, a dive in oil prices will weed out the latent longs – cause them to give up hope.  And then the liquidation of ETF holdings, of futures contracts, begins in earnest and causes a waterfall effect on oil prices.

If/when that speculative liquidation happens, trend lines get exacerbated – things go up higher than fundamentals would say they should, and go lower than what fundamentals indicate.  So I suggest that when oil traders and other market players say oil is going HERE, wherever here is, you can likely count on it going 10% past that.

That’s the tail wagging the dog, and why we have so much more volatility in the commodity markets now.

So in one sense, this chart tells me the timing of the IEA announcement was perfect, if they were targeting a large part of the market – the speculators.  They’re saying we will do everything we can to keep oil lower for longer than you think, this lower oil price scenario is not short term, so you will lose money on your trade.

(I have this mental image of the head of the IEA saying to oil long speculators – SOLDTOYOUSUCKA!)

Perhaps the IEA was looking at fundamentals saying hey, there is no need for this oil price as supplies are plentiful and the western world’s economy is weak, so if we can just change market psychology a bit, we can get what we want – $80 oil.

So who will benefit from today’s news, i.e. how can I use today’s news to make money?

One place is obvious, the other one is…counter-intuitive.

Certainly if you want lower prices, bring on more supply.  And that means more drilling, which should be music to the ears of investors in energy services stocks – the drillers and their sub-trades, like the fracking companies and the supply companies to them.

The energy producers of the world ARE increasing their spending to find new supply – a whopping 25% more in 2011 over 2010 to $133 billion, says US securities firm Raymond James.  Here in western Canada, producers will be spending 32% more this year over last, according to Canadian brokerage Wellington West Capital Markets.

But the strangest sector to benefit from lower oil prices, I think, will be junior oil stocks.   For the last two months the overriding psychology in this space has been backward.

That is – the oil price has to go down before junior oil stocks can go up.

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Junior oil stocks were having the same inverse relationship to oil that the Dow Industrials were; a high oil price will cause recession so sell riskier and junior stocks – including junior oils.

The first clue that this thinking was affecting junior oil stocks was when they did not benefit from the last $20 move in the price of oil, up to $125/barrel.

Then as the Arab Spring did NOT move into Saudi Arabia, the world’s largest oil producer, the political risk premium came out of the global oil price, and oil fell back to $100.

But that was not enough for junior oil stocks to move again.  Partly that’s because it’s summer – many investors leave for holidays, and trading volumes dry up.  A lot of these stocks have raised hundreds of millions of dollars and now have hundreds of millions of shares issued – and need lots of volume to keep their share price up.  So in one sense, the value reset button has already been pushed on many junior oil stocks.

For over a month now I’ve been reading into the junior energy markets that until oil gets under $90 and stays there for a short while, the market is not willing to buy the juniors in such a wave that a rising tide will lift all boats like it did from September 2010 to March 2011.

Another way of saying this is that junior oil stocks aren’t low because the market has no faith in the oil price; rather, it’s because the market has too much faith in it.

So once the market is convinced the oil price will stay low enough to not cause recession, it will again buy the juniors, as even at $80/bbl these companies make GREAT money.  Some valuations will get reset (though much of that is now done), but the fast growing, discovery making juniors will once again get rewarded.

http://oilandgas-investments.com/2011/investing/how-the-iea-announcement-could-affect-junior-oil-stocks/

This hot new play is being touted as a probable look-alike for the Saskatchewan-North Dakota Bakken.  But there is very little public information to back up these claims, as no well rates have been announced on the Montana side of the play, and only one well on the Canadian side.

That could soon change, however.   GMP Securities reported that Crescent Point (TSE:CPG) was issued licenses to drill two wells – one license on October 29, the other on November 5 -  into the Alberta Bakken.  One will be at the north end of the play on the Alberta side, and the other in the south very near the Montana border.

Crescent Point is arguably the most respected and most successful Bakken producer in Saskatchewan, and trades at one of the highest valuations of any producer on the Toronto Stock Exchange.  Their presence in the Alberta Bakken in such a big way is a good omen for the play.   They were able to acquire over 1 million acres in the play; almost all of it via purchasing a distressed private company out of receivership – for only $96 million, which included 900 bopd production.

You could say the land was basically free or if you don’t back out the production the cost was around $10/acre.  Recent land sales have attracted bids as high as $1500 an acre.  So the Alberta Bakken has the potential to be extremely accretive to CPG – if it works. Crescent Point plans 19 wells into the Alberta Bakken in 2011.

GMP says one of the best positioned juniors to benefit from this new play – and Crescent Point’s activity – is Bowood Energy (CVE:BWD).

“We view any incremental drilling activity that helps prove up the play as a positive for Bowood Energy” GMP states, “who’s lands are clearly on trend with the two latest wells licensed by Crescent Point.  We continue to view BWD as one of the best levered ways to play this new light oil development.”

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Bowood has partnered with the Blood Tribe First Nation in southern Alberta for much of their land – they have 94.75 contiguous sections (60,640 acres) there, and total Alberta Bakken acreage of 162 sections (104,000 net acres). Bowood intends to drill its first horizontal oil well into the play by late 4Q10 or early 1Q11.   Macquarie Capital says Bowood “has no sizeable expiry issues to deal with across their land base in the near term” so they can take their time drilling.

DeeThree Explorations (TSE:DTX) says they have 300 sections (in this area of Canada that’s one square mile) of prospective Alberta Bakken lands.  Haywood Securities says they have half of it in the main fairway of the play, and that the company will drill 3 vertical wells by the end of 2010 to test some of their ground.

Neil Roszell’s Wild Stream Exploration (CVE:WSX) has just over 30,000 undeveloped acres in southern Alberta right along the Montana border – very close to where Rosetta is drilling on the US side – and has identified 15 net conventional drilling locations.

BLACKSTEEL ENERGY (CVE:BEY) has 2,530 net acres that is prospective for the Alberta Bakken.

On the US side, Primary Petroleum (CVE:PIE) was one of the early movers in the play and has now assembled more than 230 net sections, President Mike Marrandino says.

(I alerted OGIB subscribers to Primary Petroleum at 16 cents a share in May 2010 because of their large land position in this play, and I am now taking partial profits – over 500% in six months!)

Primary intends to find a partner for their large land position.  This is not unusual for juniors in emerging shale plays – I have written about the Paris Basin shale play in France, where junior producer Toreador Resources (TRGL-NASD, $14.48 and another OGIB portfolio pick at $8.81 only two months ago) brought in Hess Corp (HES-NYSE) to joint venture 50% of their play – for a whopping $265 million.

Murphy Oil (MUR-NYSE), Rosetta Resources (ROSE-NASD), Quicksilver (KWK-NYSE) and Newfield Exploration (NFX-NYSE) are the larger producers on the Montana side of the play.  Rosetta has publicly stated they expect 12-13 million barrels of oil per section.  Newfield has said they now have one horizontal well producing from the play – they just didn’t give an IP rate.

Rosetta and Newfield have  been the most active in the US side, with each drilling about eight wells this year – most of them vertical test wells, or “strat” wells as the industry calls them, to test for rock stratigraphy – a geological term that means studying how rocks are laid down; studying the layers of rock.

Covenant Resources (CVE:CVA) and Mountainview Energy (CVE:MVW) are also active in the US side – Covenant will be spending $3 million in 2010-2011 to drill at least eight vertical test wells on their 41,500 acres (64 sections; 640 acres in one square mile).  In their corporate presentation, Mountainview says they own 74,000 net acres in the Alberta Bakken and will be spending $5.8 million there in 2011.

ARKANOVA ENERGY (OTC:AKVA) has 6400 acres, and Abraxas Petroleum (NASDAQ:AXAS) has 3000 acres.

Macquarie Capital says in a report dated October 18 2010 that shareholders in these juniors could be happy as they get bought out by more senior companies looking to get involved in the play:

“What’s next?

“…Consolidation. Junior companies with meaningful, strategically situated lands will be purchased outright by mid/large cap producers who seek to bolt on additional acreage to already established positions. The potential exists that players who were late to the game may try to establish a position in the play via a small corporate acquisition, once some of the associated risks have been mitigated by the early-comers.

“Farm-ins. We believe some select junior/midcap companies will execute strategic farm-ins on super-major companies or freehold owners as they look to either expand their land position as an early-comer or establish a position as a player late to the game.”

Of course, this is music to the ears of junior oil and gas investors.  This is what we do – find early entrants with big positions in good emerging plays, and (pray they work) wait patiently as the play develops and we get bought out for a premium by a larger company.

Keith Schaefer
www.oilandgas-investments.com

Part I of the Alberta Bakken series, please click here.

Part II, please click here.

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