- Cory Mitchell, CMT

Canadian natural gas producers are hoping to spend a minimum $20 billion on shipping Liquid Natural Gas (LNG) to Asia in the next 2-9 years. The size of the prize is huge—spot natural gas in Japan can be as high as $17/mcf—more than 10x Canada’s spot price of $1.50 now.  But competition is fierce from Australia, Qatar, and United States…as I wrote about here.

And those prices could be going higher. Asian demand for LNG is expected to increase 45% from the 20 bcf/d (billion cubic feet per day) now to 29.1 bcf/d by 2016—just four years from now.

In this article I’ll outline:
a.     who the Canadian players are
b.     the estimated size and cost of their projects, and tentative timelines
c.     some simple economics
d.     and what has to happen still for shipments to actually start

Shipping LNG to Asia is not just a great opportunity for Canadian producers, it’s a necessity. US gas production is expected to stay strong—and prices low—for years.  In 2008, the U.S. imported 13% of its total natural gas supply–almost all of it from Canada–but the U.S. Energy Information Administration (EIA) estimates that by 2035 that figure will be lower than 1%. And this shift is already happening.

Now, if all of these projects had been fully operational in 2010, Canada would have been the second-largest LNG exporter in the world, behind only Qatar.  Each of these facilities is now forecast to be built in the small town of Kitimat B.C., located at the end of a long narrow (protected) ocean water inlet… where Alcan has had a large aluminum facility for decades.

Here are the three most advanced LNG export projects in Canada:

KM LNG Operating General Partnership

Who:
Apache Corp. (APA-NYSE)           40%
Encana Inc.  (ECA-NYSE; TSX)   30%
EOG Resources (EOG-NYSE)       30%
Capacity:                                        1.4 bcf/d (11.66 million tons annually)
Projected cost of facility:              $10 billion (but $5.6 billion if only do 0.7 bcf/d)
Approved?                                     Yes—20-year license
Projected completion date:           Late 2015

This group—all upstream producers—is also the only one to have approval for a pipeline to transport the gas from the field to the LNG facility—the Pacific Trails Pipeline. Despite the approvals, the partners haven’t made the final decision to build the project.

What’s left to bring the project together? Money and customers. They’re still looking for money, which should come from, potentially, the pipeline company, but certainly from an anchor customer in Asia who would come in for 20% equity on the project AND the upstream resources; the gas itself.  Everybody would reduce their interest pro-rata in that case.

The Globe and Mail reports that the project has two deals already signed with Japanese power producers, and other potential customers are lined up.

But analyst Gerry Goobie with Purvin & Gertz Inc. told the Calgary Herald that the fact that the partnership is looking for equity shows that it still needs to secure long-term customers.

“The bottom line is they’re still trying to strike a deal,” he said. “The assumption is the deal that they have will be sufficient to cover off all the capital costs that they are going to spend to build this thing and give them a reasonable return.”

BC LNG CO-OPERATIVE

Who:        13-member group (includes LNG Partners LLC of Houston and the Haisla First Nation)
Capacity:                                     0.22 bcf/d (1.8 million tons annually)
Projected cost of facility:           $360 million – $450 million
Projected completion date:        2014
Approved?                                   Yes—20-year license

This proposal has the earliest (tentative) start date—early 2014. This is by far the smallest of the three proposals, and would be unique in that they will be located on a barge 7 km south of Kitimat, and grounded on the shore.

“This thing should be fun to get it off,” Tom Tatham, the managing director of BC LNG (and of LNG Partners LLC of Houston), told Reuters. “There’s really nothing that’s ever been done like this in the LNG industry.”

The project is partially intended to allow smaller natural gas producers to ship LNG abroad to more lucrative markets.

Specifically, an operating company at the facility will liquefy a cooperative member’s natural gas for a fee. Companies can buy into the cooperative for $50,000 or can receive membership for free by writing a letter to the National Energy Board stating an intent to buy or sell gas through the terminal (cooperative members can be buyers or sellers).

What’s left to bring the project together?  Pipeline capacity.  It only makes sense for them to use Pacific Trails (I think it would be politically difficult for Apache et al to not allow small producers access, including those with First Nations ties, for a toll fee), but it may not be ready by then.

Shell

Who:                           Royal Dutch Shell   40%
Mitsubishi                    20%
Kogas                           20%
CNPC                           20% (China Nat’l Petroleum Corp)
Capacity:                                     1.44 bcf/d (12 million tons annually)
Projected cost of facility:           $12.35 billion
Projected completion date:        2020
Approved?                                   Pending

What’s left to bring the project together? Approvals, pipeline capacity and pipeline approvals.  All the players together in that consortium have lots of financial ability.

The project could come online at the end of the decade and might be able to send as much as 2 bcf/d abroad per year. Shell has a lot of experience in LNG, operating 2.4 bcf/d export capacity in other areas of the world, and another 2.9 bcf/d coming into production by the end of 2015.

Shell first announced its plan for the venture last fall, shortly after it (and some of its partners) purchased the Methanex marine facility in Kitimat, which is no longer in use.

That’s the Tier 1 list of Canadian LNG exporters.  Other groups looking include:

Petronas-Progress (PRQ-TSX)

Petronas is a large Malaysian oil and gas company with This 80/20 partnership aims to build a 1.0-1.2 bcf/d LNG plant in B.C., bringing the first 0.5 bcf/d online in 2017-2018 and the rest a year later.  A feasibility study on the project should be complete by the end of Q3 2012.

INPEX-NEXEN (NXY-NYSE; TSX)

Inpex is a large Japanese oil and gas producer.  In November 2011 they joint ventured 40% of Nexen’s holding in the Horn River, Cordova and Liard basins, all in B.C.  There is little doubt they will be going after an LNG license. Do they do it on their own or join one of the three more advanced projects?

Potential issues with Canadian LNG projects

There are still potential speed bumps for Canadian LNG exports.  These pipelines need to get built, which means passing through areas that have attracted so much opposition to the Northern Gateway oil pipeline.

Where will all the electricity and power that’s needed come from, and what infrastructure is required for that?

The economics of Canadian LNG exports to Asia should be similar to those of Australia, says Canadian brokerage firm CIBC Wood Gundy in a report earlier this year.

Japan is the largest LNG market, and the shipping route from Canada to there is 4300 km, vs 3100-4300 km for Australian projects.  They add that Japan will want to have several sources of LNG.

Long-term LNG contracts are usually priced at 12-15% of Brent crude, which at $100 Brent means US$12-$15/mcf—still 8-10x Canadian spot prices.  CIBC is forecasting Canadian LNG exports can earn a 17% internal rate of return at $4/mcf gas.  That would be higher at today’s low gas prices.

They broke down how the costs of getting the gas from the field to a Kitimat LNG facility, liquefying it, and shipping it to market would cost:

So you can see a 50% gross margin here, under their pro forma model.  If cost inflation doesn’t escalate out of control, and Asian demand meets expectations, then the size of the LNG will make a very healthy return for Canadian exporters.

The top LNG exporters are Qatar, representing nearly 25 percent of global LNG exports with 7.3 bcf/d.  Then there’s Indonesia (23.7 million tons, 3.03 bcf/d), Malaysia (23.1 million tons, 2.96 bcf/d), Australia (19.1 million tons, 2.45 bcf/d), Algeria (18.7 million tons, 2.39 bcf/d), Nigeria (18 million tons, 2.31 bcf/d) and Trinidad and Tobago (15.4 million tons, 1.97 bcf/d).

Note how Canada – the world’s third-leading natural gas producer – is nowhere to be found on this list. However, that could soon change with the three projects in Kitimat.

- Keith

Editor’s Note:  In 2010, offshore drilling stocks got crushed. A lot of that had to do with the Deepwater Horizon oil spill.  But that tragedy also opened the door for investors to buy into big names like Transocean — at a major discount — which would later offer opportunities for very good capital gains. That’s why today my inbox is often filled with questions about the state of offshore drilling. So, I’ve asked my colleague Michel Massaud, publisher at BeatingTheIndex.com, to give us an overview of the sector — an offshore drilling and deepwater exploration ‘primer.’ Here’s Michel with today’s story…
- Keith

Offshore drilling is the most complex and expensive way of accessing oil and gas reserves, particularly when it comes to deep water and ultra-deep water exploration activities.

While presenting the industry with its biggest challenges, deep water exploration and development yields the greatest potential rewards and healthy profit margins to the oil service companies involved.

The rising complexity and costs of such endeavours demands huge capital investments, long term commitments, higher efficiencies and a growing reliance on technology in order to reduce uncertainties.

The market fundamentals for oil service companies remain solid, oil prices are stubbornly holding their ground above $100 per barrel in a tough macroeconomic environment. The resiliency of high oil prices is fuelling increasing exploration and production spending by operators as the industry pushes further offshore into ever-deeper water. By 2020, offshore oil production is expected to account for 34% of the global output up from 25% in 1990.

Offshore drilling companies are seeing a significant increase in tenders and requests from customers, particularly for the ultra-deep water rigs which are commanding higher daily rates for its units. The brightening outlook mirrored by record backlog orders and rising rates encouraged the industry to focus on adding new equipment in all market segments in a bid to provide the most versatile fleets of mobile offshore drilling units.

Jack-up rigs are mobile, self-elevating drilling platforms that are towed by tugboats to the drill site with water depth of up to 400 feet. Jack-Ups are equipped with tubular structure legs that are lowered to the sea floor where jacking elevates the hull above the water surface before drilling operations begin.

Semi-submersible rigs operate in a semi-submerged position with the lower hull ballasted down below the waterline. The rig consists of a deck which contains working areas, equipment and living quarters that is able to carry drilling operations in deep and ultra-deep waters of up to 10,000 feet in water depth.

Drill Ships are self-propelled ships equipped for drilling in water depths in which jack-up rigs are incapable of working. They can drill in deep and ultra-deep waters in up to 12,000 feet of water depth.

Rising oil prices have also spurred a construction boom in drilling rigs; the cost for a drilling ship easily surpasses $600M per unit where it is leased at $500k/day or more on 2 or 3 year contracts. The Jack-up market is seeing increased demand in Mexico, the North Sea, the Middle East and Asia while the floaters market which includes ultra-deep water rigs has been improving markedly in Brazil, Africa and the Gulf of Mexico.

The New Sweet Spot in North America’s Oil Patch

It’s one of the hottest picks in the OGIB portfolio… A company operating in the heart of one of North America’s fastest-growing shale oil plays — with major short-term gain potential.

And in my newest research, I explain how recent drill success could see this company’s production more than double AND “slingshot” its valuation.

Follow this link to get it.

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On top of strong oil prices, successful exploration drilling results continue to be reported. Last year, 23 discoveries were announced in 12 different countries in an average water depth of 6,200 feet representing the sixth consecutive year of 20+ announced discoveries.  Successful exploration results pave the way for development drilling over the coming years which is another factor in driving future demand.

For instance, Petrobras (a Brazilian semi-public multinational energy company) will be renting 26 rigs for the next 15 years in order to develop its deep water oil field discovered back in 2006. The oildfield known as Tupi holds an estimated 8 billion barrels of light sweet oil.

In contrast to Brazil’s newly discovered deep water prospects, the Gulf of Mexico is an established deepwater region which is also seeing rising activity levels. The industry expects drilling activity to reach and surpass the pre-Macondo level of about 30 wells by early 2013. Ultra-deepwater rig demand is expected to increase dramatically through 2016 as exploration activity drives future development demand growth. Even with the construction boom, the ultra-deepwater utilization is expected to remain tight in the coming years.

Not surprisingly, deep water’s contribution to global oil output is expected to reach 13% by 2020 up from 0% in 1990. Declining production from large onshore oilfields has to be replaced somehow and the era of easy to extract cheap oil is behind us. The following offshore drilling companies provide you with a strong exposure to the offshore oil services sector and a broad geographic reach since the world is their playground:

Finally, there’s no free lunch as investing in any sector carries its risks. For offshore drilling companies, you’ll want to keep in mind every operator faces risks ranging from storm damage to volatile commodity prices. Offshore drilling accidents, while rare, may result in significant damage or a total loss of a rig.

Capital budgets set by E&P companies are dependent on commodity prices; a sharp drop in oil prices will result in an oversupply of drill rigs on the market as capital budgets are scaled down. These companies usually borrow in order to finance construction of new rigs – What happens if prices collapse and contracts are renewed at much lower day rates? Can the company afford to service its debt? For dividend paying companies, future dividends depend on 3 variables of paramount importance: the business outlook, the debt leverage and the contract coverage.

- Michel Massaad
Editor, BeatingTheIndex.com

The water dilemma around fracking in the oil patch is valued in the billions.

And entrepreneurs are quickly developing a suite of technologies to solve it.

The issue is both the quality of water — residents near oil and gas wells want 100% comfort that fracking does not contaminate their groundwater — and quantity.  These wells use anywhere from 2 million to 13 million gallons per well, leaving parched states like Texas scrambling to encourage water conservation in the energy sector.

Which technologies will get adopted and be the winner in this multi-billion dollar industry?  For investors, the stakes are high.  As a company gets discovered, its share price can have big runs — Both GreenHunter (GRH-AMEX) and Ridgeline Environmental (RLE-TSXv) have seen their share prices double in the last four months as investors begin to understand the potential of this space.

Wall Street and Canada’s Bay Street are both just starting to wrap themselves around this sector — deciding which horse (the technology) and which jockey (the management team) — to bet on.

As I explore this hot new sector, I’ll periodically update you on new technologies I see getting some traction in the market.  Here’s a first look at a group of contenders in the water space.

Produced Water Absorbents (PWA)

It sounds like science fiction. The company actually invented a glass that can absorb organic material — such as hydrocarbons — from water, making it safe enough to drink.

“Osorb,” as the glass substance is called, can swell to eight times its size as it absorbs materials from water.

Produced Water Absorbents CEO Stephen Spoonamore says that Osorb can be used for a variety of applications… but its ability to not affect salt and metal while performing its function makes it ideally suited for the oil and gas industry, according to industry trade mag RigZone.

One of the top benefits of Osorb is that it doesn’t leave toxic by-products, doesn’t require landfilling, and — on top of that — minimal energy is needed to use it. This presents an advantage, Spoonamore says, as disposal wells will not be needed for companies managing their water.

——————————————————————–

The substance was discovered by a graduate student working for Dr. Paul Edmiston, chairman of chemistry at the College of Wooster in Ohio, while trying to create a bomb-detection device.

“It works like a nanomechanical sponge,” he says. “I’ve done trace analysis, and the water’s totally clean.”

Edmiston has an online video shows him mixing motor oil with water in a bottle, inserting some grains of Osorb, shaking it up, straining the swollen particles and then drinking the water.

Practical testing has also revealed positive results, as a prototype system using Osorb treated 60 gallons of water per minute, reducing its petroleum content from 227 milligrams per liter to just 0.1 milligrams per liter, according to Popular Mechanics.

The water is treated and then given back to customers as brine, which can be used for fracking, according to Rigzone.

PWA is in the process of opening a water treatment facility in Ohio to treat flowback water from the Utica shale, and has plans to open additional facilities in the coming years. Spoonamore says that the company is “very interested” in promoting Osorb for the Bakken and EagleFord plays as well, reports the news provider.

PWA’s web site:  www.pwabsorbents.com

VIDEO: http://www.youtube.com/watch?feature=player_embedded&v=czZD-meOfkU

Rettew Flowback, Inc.
 
Chesapeake Energy Corp. recently unveiled a new wastewater treatment system in Ohio that it has been using to treat water from its operations in the area.

Rettew Flowback Inc. designed and operates the facility for Chesapeake. According to the Beacon Journal, the facility is the first of its kind in the state and can handle as much as 300 barrels of waste per hour.

General manager of the facility Chris Foreman told the news provider that chemicals and filters clean about 95 percent of the wastewater, with the remaining 5 percent needing to go to a landfill for disposal.

The chemical used in the treatment is reportedly proprietary, but a 20-
micron filter and a 5-micron filter are also used in the process.

Keith Fuller, Chesapeake Energy’s director of corporate development, says there are plans to add additional water treatment facilities in Ohio.

Consequently, it’s worth noting that recycling water in the Marcellus formation has reportedly saved Chesapeake some $6 million per year.

Rettew’s web site:  www.rettew.com/oil-and-gas/

Ecologix Environmental Systems

Atlanta based Ecologix uses air flotation in a mobile treatment system, which is easily transported and set up on site.

“Dissolved air flotation” removes oil that is suspended in water by dissolving air into the wastewater under pressure and then releasing that air into a tank at atmospheric pressure. The air then forms bubbles that sticks to the oil, floating to the surface where they are removed by skimming.

This system — which is focused on treating water from fracking — can treat up to 900 gallons of water per minute. (42 gallons=1 barrel.)

A re-design of the system allows the treated water to be used again for fracking in a short period of time.

Website: http://www.ecologixsystems.com/system-its.php

Abanaki Oil Skimmers

Most wastewater treatment methods require that the affected water at least be brought back to the surface before it is treated, but one Ohio-based company gets the process going before the water even sees the light of day.

Abanaki Oil Skimmer’s use a High Temp Polymer Belt for fracking sites. This belt — which is able to withstand temperatures of 180 degrees Fahrenheit continuously — is attached to an engine of sorts and is put down into the well. The machine is turned on and the moving belt pulls oil and other contaminants from the flowback water as it reaches the surface. It may be useful to think of it as a long belt attached to an out-board motor that you put down the well.

“Oil skimmers work by making use of the differences in specific gravity and surface tension between oil and water,” says the company. “These physical characteristics allow the belts to attract oil and other floating hydrocarbon liquids from the surface of the fluid. Abanaki belt oil skimmers can be used in applications as deep as 100 feet.”

According to Abanki this method is economical due to its low-energy use, low maintenance and can be operated 24 hours a day, seven days a week.

Website: http://www.abanaki.com/industries-fracking.html

Product Animation: http://www.abanaki.com/petrox_animation.html

Ridgeline Energy Services (RLE-TSXv; RGDEF-OTCQX)

The nature of science is such that it is common that the initial intended use of a technology is not what it is ultimately used for. That is the case for Ridgeline Water Inc. – a division of Ridgeline Energy Services Inc. – and its water treatment solution… which uses a method developed for extracting biofuels from fat.

During the middle of the 2000s American engineer Dennis Danzik created a technology that could extract biofuels from cooking oils deposited in grease traps used by restaurants at a relatively low cost.  Over 90% of the fluid processed is water, which is a by-product that has to be disposed of. In order to keep the process cost effective, Mr. Danzik refined his process so that the water ended up being cleaned enough for safe economical discharge.

Here, Ridgeline saw an opportunity to address the growing need in the oil and gas industry to treat the tremendous amount of water that returns to the surface after hydraulic fracturing and the larger volumes of produce water that flow to surface.

Ridgeline worked with Danzik to develop the method that relies on electro-catalytic technology. Essentially what this means is that electricity and catalysts – a substance that effects a chemical reaction – are used to cause reactions that enable the bonds between water and contaminates to be separated.

Danzik’s innovation works in a slightly different way than most wastewater treatment methods, as it is used at the beginning of the treatment process. By using the method early, the contaminants are able to be separated from the water. Then the water is better prepared when it goes through a more traditional treatment process such as reverse osmosis, which, in layman’s terms, separates contaminants by passing the liquid through a sieve (membrane). The electro-catalytic step allows for such processes to more efficiently separate the water from, hydrocarbons, Totally Dissolved Solids (TDS) or other unwanted substances.

The company touts the low energy output required by this step as the water does not need to be excessively heated. The bonds are broken, “cracked” without the need of large amounts of energy.

Website: www.ridgelinecanada.com

Regards,

- The OGIB Research Team

DISCLOSURE:  Keith Schaefer owns Ridgeline stock in the Oil & Gas Investments Bulletin portfolio.

Publisher’s Note:  It bears repeating — the water services sector is just beginning to take shape. Ground floor. The rewards for investors will be plentiful, to be sure. One of the best, most profitable examples to date is a company that’s dominating its niche in the space… and it’s making investors a fortune in the process. To learn how you can join in on this money-making opportunity, simply follow this link to my new research.

New accounting rules in Canada are looser than before, making it harder for investors in oil and gas to understand their investments, and also more of a pain for Canadian companies to raise money in the United States.

That’s the conclusion I’ve come to after interviewing industry executives and national firm-accounting consultants in the oil patch.

“Find me a company in Canada that says we were able to raise more money at a better price with IFRS (International Financial Reporting Standards),” says Craig Nieboer, CFO at Canadian Energy Services (CEU-TSX).  “Find me an investor who can now say I understand this company’s financials better because of IFRS.”

“They don’t exist.”

This year, for public companies, Canada dropped its GAAP accounting system—Generally Accepted Accounting Principles—in favour of the IFRS—International Financial Reporting Standards.

During my interviews, I found the main difference between the two is that IFRS allows greater leeway for management and boards to use their own judgement in how to present and explain company financials.

In an era where the core financial sector of the western world is under huge scrutiny for lending and accounting practises, I found this odd.

“There are now more choices, so consistency between companies is impaired,” says Nieboer.  “For us, we have fewer lines in our statements so investors have to dig more in the notes and MD&A.”

“Has it improved better information to investors? At best no, and potentially it’s worse.”

Kevin Nielsen is a partner at Deloitte in Calgary, and works with a lot of energy companies.  I asked him to explain the switch to IFRS, and how it impacts both investors and management teams in the Canadian oil patch.

“IFRS is more “principles” based and therefore more judgement is required (by management in how to produce their financials),” he said in a phone interview. “Previously, GAAP was more rules based.  So as a result companies need to disclose in their financials more information on how their accounting policy choices are determined.

He said the new IFRS rules most benefit major international firms who operate in different countries and have different accounting practises.

For junior oil and gas companies in Calgary that have domestic assets, it obviously is not going to have the same benefit.

Stuart Symon, Chief Financial Officer at intermediate producer Angle Energy (NGL-TSX) in Calgary, says investors will have to do more digging to really understand a company with IFRS.

“You have to go to the notes in the financial statements to get the full story; read the disclosures. What’s happening behind the scenes? Is IFRS adding value to this equation? IFRS requires more disclosure that doesn’t necessarily provide incremental benefits for the reader.”

There are now more disclosures with IFRS. Management teams are trying to put the best information out there that’s the most relevant. But does the investor have time to read and understand it all?  Or does all that information drive investors back to the basics – the management team, drilling results and reserve report?

The Canadian accounting standard setters decided to move to IFRS as the majority of the world is doing so — even though Canada’s largest trading partner and largest source of foreign capital, the U.S., still uses GAAP, and there are no indications that they are moving to IFRS anytime soon.

Most changes that IFRS makes to oil and gas accounting happens below the cash flow line.  And being as most energy investors use cash flow as a primary valuation method, the IFRS changes should not have a major effect on corporate transactions, says Angle Energy’s Symon.

“We are not judged as much on earnings as we are on cash flow and recycle ratio. (Recycle ratio= field netback (profit) per barrel divided by finding cost per barrel–KS.)  So how much will this change how investors look at junior oil and gas companies? If you have an earnings emphasis, IFRS will change things, but oil and gas valuations do not tend to be as influenced by earnings.”

Here are some of the main changes that Nielsen, Symon and Nieboer say investors will notice in the junior oil and gas accounting under IFRS vs. GAAP:

1. More impairments, or writedowns—and more frequent impairments in IFRS.  Asset values are obviously tied to commodity prices in this sector, so as prices move, the industry will not only see more writedowns, but lots of reversals in impairments.  “A writedown used to be viewed as negative in the market as it was rare,” says Symon. “People are going to have to get more used to impairments and reversals giving rise to earnings volatility.” The intent is to carry assets on the financial statements at a more current or real time market valuation.
2. For service companies, one of downsides of IFRS is you don’t get true gross margin anymore, says Nieboer, as non cash items like stock based compensation and amortization are included as cost of goods sold.  “Gross margin is now artificially lower,” he says.
3. Many more costs must be expensed, not capitalized, such as transaction costs when doing a deal, and even dry holes must be expensed, whereas before they could be capitalized.  For the small junior producer, a couple misses can mean a very bad income statement.
4. All of the above points means there will be more volatility in earnings.  But few junior oil and gas companies have earnings.

No accounting system is a replacement for management integrity.  But with fewer lines in the financial statements being replaced by more detailed notes—facts being replaced with explanations—investors will now more than ever be on their own trying to determine what’s being said, and what is not.

by Cory Mitchell, CMT

The Horizon BetaPro NYMEX Natural Gas Bull+ ETF (TSX: HNU) has been one of, if not THE most profitable trades in natural gas for the last four years, yet my sense is retail investors have missed it completely.

Why? The reason is simple—you have to short it. Most retail investors don’t short, and fewer think about shorting an “Up” ETF.  I admit, it’s not a trade for novices.  But it’s available to everybody.

I’m going to outline just how lucrative this trade has been over the last four years, and how you can capitalize on this downtrend in natural gas. I’ll explain the two  “built-in” factors to this ETF that add to the profits of a short position—and lose you money if you’re long.  I’ll even tell you when, historically, the best time of the year is to initiate this trade—and it’s coming up VERY SOON.

“Shorting” means selling first and buying back later, as opposed to the more common convention of buying first and then selling.  The short seller profits by selling at a higher price and buying later at a lower price.  The difference in the price between where he sold and where he bought is the realized profit of the trade.  This is how money is made on downtrends like we are witnessing in HNU.

(If you just learned what “shorting” is by reading this, do not attempt this trade;-))

HNU started its steep downtrend in July, 2008 just a few months  after its January inception.  The ETF is down 99.86% from that high, far underperforming the underlying commodity it is supposed represent.  Now, this is very bad news if you’re long.

But if you’re short, this underperformance is a key; if you’re short it’s kind of like being The House in Vegas.

The ETF actually represents one of the most reliable trades in the sector—and it is not too late to get in.  And as I mentioned,  one of the ideal annual entry points over the last three years is coming up very soon!  If retail investors want to ride a trend this is it. The trend in natural gas is currently down, and even if the trend reverses, there are two built-in features within the fund are likely to stifle long-term upward price appreciation: “contango” and re-balancing.  I will explain both of these.

The Structure of Underperformance

HNU is a leverage ETF which attempts to “seek daily investment results equal to 200% the daily performance of the NYMEX Natural Gas futures contract for the next delivery month” according to Horizons website.

This is accomplished through purchasing natural gas futures contracts, and then at specified dates rolling the contracts which are nearing expiry into new futures contracts.  According to Horizons website “This mechanism also allows the investor to maintain an exposure to commodities over time.”

Yet those who have bought, or gone long the ETF since the start of 2011 have lost 64% of their capital, while the underlying commodity has lost 22.77%.  The ETF is leveraged, therefore the theoretical loss HNU should have experienced so far this year is negative 45.54%.  Investors have  lost about 17% more than anticipated this year alone (the fund charges a 1.15% management fee).  Since inception the picture is grimmer—but only if you’re long  It’s actually a beautiful thing if you’re short.

Adjusted for four reverse stock splits, the stock hit a high of $7,710.40 in 2008, and currently trades at $10.48 as of Friday, December 2.  It should be noted that the actual price paid at the high in 2008 was not $7,710.4 (it was $48.19).  This price reflects the equivalent value in retrospect based on the reverse stock splits that have occurred.

If an investor  picked the top and shorted 1000 shares at $48.19 ($48,190 invested) in 2008 the trade is showing a profit of $48,124.68!

Whereas if an investor bought 1000 shares at $48.19 in 2008, the first split would have left him 250 shares (1 for 4), the second split with 50 shares (1 for 5), the third split with 25shares (1 for 2) and the fourth split with 6.25 shares (1 for 4).  The original investment of $48,190 is therefore worth $65.5(6.25 times the current $10.48 share price) reflecting a 99.86% loss in capital (that is why the shorts have nearly doubled their money).  The prices on the chart are adjusted to reflect the reverse stock splits and the appropriate percentage decline of the ETF.

Figure 1. TSX: HNU –  January 16, 2008 to December 2, 2011 Logarithmic Weekly Chart with Reverse Stock Splits

Source: FreeStockCharts and split information from Yahoo Finance.

Horizons does point out that “These ETFs do not seek to meet their investment objectives over any period other than daily.”  This is clearly stated multiple times in the ETF prospectus, indicating the ETF does not track the commodity over the long-term, rather only on a daily basis.

CONTANGO

A major factor in the decline witnessed in HNU over the long-term—and something that stacks the deck in favour of being short–is due to a phenomenon known as “contango.”  Futures contracts, which HNU purchases, are an agreement to buy an asset at a fixed price at a forward or future date.  When the futures price is higher than the spot price, that is known as “contango“.  The natural gas market is usually in contango; futures prices are higher due to storage costs and uncertainty; so a premium is paid for that uncertainty.

But as that more expensive  futures contract approaches its  expiry date—the date the gas must be delivered–it will converge with the spot price—which by definition means it declines in price. Since HNU does not take physical delivery of the commodity it trades, it must continually “roll”, or sell futures contracts which are expiring and buy longer-term contracts—usually the next month.

By continually paying a higher price than the spot price each time the contract is rolled, there is an inevitable long-term systematic erosion of value within the fund, and a continual slide in the value of the ETF.

This is GREAT—if you’re short.  The House Rules are in your favour.  But it’s a profit killer if you’re “long”  though.

As for December 5, January 2012 Natural Gas is trading at $3.465.  February, 2012 Natural Gas is trading $3.492.  Not only does the fund lose money because of the downtrend (sells expiring contracts at a lower price) but it then pays a 2.7 cent (this will fluctuate) premium for the next futures contracts.  Compounded and leveraged each month, the losses become staggering, as shown by the ETFs decline.  Keep in mind the fund is leveraged-essentially doubling the premium and magnifying losses. . . Month after month, all else being equal, this occurs.

The contracts HNU is forced to sell will almost always be lower than the price which is paid for the new contracts they must purchase. This will offset any long-term gains the fund could theoretically make, even if natural gas rises over the long-term. The fund loses if natural gas drops, stays the same or even rises slightly. These regular losses and inefficiencies continually drive down the value of the ETF.  Again, if you’re short, this is adding profits to your wallet.

The second big structural factor in HNU that is in favour of the “shorts” is the issue of leverage and compounding losses.  HNU attempts to reflect 200% of the movement of natural gas on a daily basis.  Assume you invest $100 in the ETF, on the first day natural gas rises 5%.  This means your investment will be worth $110 (you make 10% because of leverage).  But assume the following day natural gas falls by 5%.  Your investment is worth $99 (you lose$11 or 10% of $110).  Many investors think they should just be back at $100, but compounding and leverage create a loss.

If you’re short, you just made $1 in two volatile days.  If you’re long, you just lost $1.

How to Make Money

Investors don’t usually think about short-selling but in this case, shorting the ETF has historically been the way to make money over the long term. Shorting selling is taking advantage of both sides of the market—up and down—movements which occur regardless of short-seller involvement.

“Market participants are permitted to sell Units of an ETF short and at any price…” according to the prospectus for the ETF.  Short selling is a legitimate way to trade the ETF and is noted in the fund’s legal documents.

Shorting ETFs is often more efficient than shorting an individual stock or commodity:

• The ETF is not prone to short-squeezes since the fund is rebalanced every day to reflect the value of its holdings-which seems systematically doomed to continue its decline.  The ETF moves intra-day as the underlying assets move, therefore all traders (long and short) are simply volume, as the price is determined by underlying assets, in this case natural gas contracts and how those contracts are managed.

NOTE: The underlying commodity may be prone to a short-squeeze where buyers push up the price and people with short positions are forced to cover their position (pushing the price even higher) or receive a margin call on their short position. Investors should be aware this can cause sudden, sharp short-term rises in the ETF.

• HNU can be shorted at any time.  This differs from a regular falling stock as the stock may not be shortable at all, or subject to the uptick rule.  An uptick rule means traders can only initiate short positions when the price is above the last trade price.  This is common on the TSX exchange, but this ETF is excused from the regulations.

In an ETF which has proven very inefficient for buyers over the long-term going short is the logical strategy.  (The industry jargon for buying is called “going long”.) Couple this with an overall downtrend in natural gas—even if natural gas begins an uptrend the rise in the ETF is likely to be muted—the trade sets up very well for investors who are willing to incorporate short selling as one of their tools.

The fund is leveraged which means on a daily basis there can be big percentage moves.  Short-selling blindly is not wise.

PART 2—On Saturday, I tell you historically WHEN is the best time to make this trade to maximize profits—and it’s coming soon.  And I’ll also explain what happens to this short trade if natural gas prices start to rise (Hint—it’s better than you think.)

Disclaimer: Cory Mitchell nor Keith Schaefer currently hold a position, short or long, in TSX:HNU.  This information is not to be construed as investment advice in any fashion. Always consult a licensed financial planner to help determine what investment strategy is best for you.

The investor trend towards yield could have a big impact on the US junior oil and gas market, a new report by brokerage firm Raymond James suggests.

Energy Analyst Kevin Smith says the stocks of Upstream Master Limited Partnerships, or MLPs, are worth almost double their regular corporate counterparts (called “C-corps” in industry jargon).  And that big valuation gap could start some Mergers and Acquisitions (M&A) activity in the junior US energy space.

“We are not saying that you should expect a rash of Upstream MLP acquisitions of C-corps tomorrow, but we are saying we think that it is coming over the next few years,” he writes.

MLPs trade like stocks on American stock exchanges.  They have a big tax advantage in that they don’t pay corporate tax; investors are treated as owners of the company, which means they get the corporate tax breaks too. (Isn’t that a switch?)  This lowers the income tax paid on the earnings.

Then the MLP pays out most of its excess cash flow to shareholders in the form of a distribution — which can end up creating a big cash yield.  (That’s why I think the U.S. will see a LARGE increase in MLPs over the coming few years as interest rates stay low.   Investors love seeing this money dropped into their account, and price the stocks based on the yield they give.)

And in this tough junior oil and gas market, yield stocks are holding up the best.  The reason is that MLP investors are looking at yield for its primary valuation method. Regular corporations, or “C-corps” as industry jargon goes, investors are looking at earnings and cash flow valuation methods — and those are likely going to decline this year and next due to the weakness in the natural gas pricing. And overall market volatility is reducing valuations on the junior oils. That’s what’s making Upstream MLPs valuations (stock prices) much more sticky vs. the “regular” C-corps.

They’re holding up so well in fact, that Smith says it’s only a matter of time before the MLPs use their much better valuation — stock price — as a currency to buy regular junior oil and gas companies.

“While no (upstream) MLP has bought a producing C-Corp yet, I think it will, I think it’s inevitable,” Smith told me in a phone interview from Houston.

Upstream MLPs have bought many producing oil and gas assets, but they have yet to swallow an entire company.

“At some point, $100 million (asset) deals won’t quench your thirst… as MLPs grow, they will need to do bigger and bigger deals,” Smith says.

There is a tax issue when MLPs buy C-Corps, but the valuation difference between the two groups now make up for most of that.

LINN Energy (LINE-NASD) is the poster child of the new upstream MLPs that are going public.  In five years it has grown from a market cap of just over $500 million to now $7 billion, and is a Top 20 oil producer in the US.

So, as an investor in junior oil and gas companies, where should I be looking at take-out candidates?

While the difference in valuation between MLPs and natural gas-weighted companies are the greatest, Smith points to the oil producers.

“I would bet (MLPs buy) oil-weighted C-Corps that are under-loved.  The most active market is the Permian Basin. We have seen quite a bit of activity in this area over the last 24 months.  And some California plays will get some looks, with low decline rates.”

In his October 31 report, Smith said that public C-corps are trading at a discount to what many private E&P property packages can be purchased for today (5-6x EBITDA for sub $500 million transactions).

This game that Smith is talking about completely changed the way junior oil and gas companies operated in Canada.  In Canada, MLPs are called “Income Trusts,” and while there might be some subtle differences, they are basically the same tax-advantaged public company that allows big chunks of their cash flow to pass through to unitholders.

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How Oil Fields the World Over Are Getting a “Second Life”

Extending the life cycle of an oil reservoir — by years — could mean the difference of tens of millions of dollars to an oil producer.

That’s exactly what one company’s new technology does… It improves oil production rates while slowing the rate of decline.

Oil producers using this powerful system are finding it a huge success, often times almost immediately.

Adoption, meanwhile, is steadily increasing inside the oil & gas sector. In fact, this company’s technology is now employed by major oil producers — or soon will be — on 4 different continents.

To get the full story – and how you could profit – click here.

—————————————————————————
First these trusts started buying intermediate producers, those producing over 10,000 barrels a day.  When they were gone, and the number of trusts kept increasing, they went after juniors producing only 1,000 barrels a day.

The number of junior companies soared as management teams now had an easy exit plan — build up production with a decent land base and get bought out fast by a trust.  They didn’t need to plan for the long term and, generally speaking, didn’t need to be as disciplined in how they spent their capital.

With all the shale plays being discovered in the US, could this be the beginning of the same type of mania that overtook Canada?

“We’re not quite to point where we were in Canada in 2005,” says Elliot Gue, editor of MLP Profits (www.mlpprofits.com), who specializes in US MLP investing.  “We are seeing a number of MLPs getting listed.  Some are small and hoping to get bought out.”

Gue says he is already seeing a lot of MLPs buying out private oil and gas companies.  “In the Permian Basin in Texas there are over 1,500 operators. Most only own a small amount of land. Those guys are selling out to MLPs.”

So there is definitely a trend here, similar to what Canada went through starting 15 years ago?

“We’re entering that growth phase now,” says Gue.

Smith says the new upstream MLPs could be a long trend: “With current interest rate trends, it doesn’t look like that valuation gap will close anytime soon.”

- Keith

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This past Friday I had a chance to dialogue with Nathan Weiss of Unit Economics, an independent institutional research firm based in Boston. Nathan explains – below – why that day may turn out to have historic significance for natural gas investors.

- Keith

To natural gas investors, 11/11/11 will, in hindsight, be remembered as a historic date.  Friday marked the first time since November of 2002 that the 12 month forward US natural gas price moved to $4.00/Mmbtu (1 Mmbtu=1 mmcf).

We think this spells the end of highly profitable hedging for a large majority of natural gas producers.  That should have a negative impact across the board for natural gas stocks in 2012. Twelve month forward natural gas prices can be seen on the following chart:

U.S. natural gas producers typically hedge more than 50% of their coming year’s production in advance, often telling investors that they are “trying to be conservative” and reduce risk.  They use the forward curve to improve earnings and cash flows, and by hedging E&Ps have added as much as 50% of their operating cash flows over the past five years–making gas E&Ps equal parts hedge funds and natural gas producers.

This means lower cash flows for natural gas producers from their hedge books.  It will make life very difficult for natural gas E&Ps as we move through 2012 and they work their way through the majority of their remaining hedge books put in place when 12 month forward gas prices were 20%+ above spot prices.  Now the forward curve is only 11% above spot prices—which are lower in themselves.  It’s like having one of your two legs get cut in half.

Here are the numbers:

Over the past five years, on average, the 12 month natural gas future contract has been priced 21.93% above the spot price.  Prior to 2005, the 12 month forward futures price was, on average, equal to the spot price, as the following chart, depicting the % contango between the 12 month natural gas futures price and the spot price going back to 1991, shows (the pink line is the five year average):

As you can see on the above chart, the current contango between the 12 month natural gas forward price and the spot price is 11.73% and falling.  That means lower cash flows from new hedging.

Investment Conclusions

Many natural gas producers have successfully used their hedge books over the last 3 years to greatly increase cash flows and help share price—by as much as 50%, thanks to a 20% contango on the forward price curve.  Now, not only is spot gas lower – at $4/mmbtu for the first time in 9 years–but the contango is lower too.

This should mean that 2012 will be the year when the cash flows of many natural gas producers take a big hit—and therefore their stock prices should too.

While this data may tempt you to run out and short a basket of E&Ps, there are a few complications that must be addressed.

The first is that with the current 27.2:1 ratio of spot oil to spot natural gas prices, even a relatively small amount of Natural Gas Liquids (“liquids” such as propane, butane or condensate/pentane) production can substantially change the economics of a “gas producer.”

For example, Chesapeake Energy (CHK) produces 83% of their BOEs from dry gas, yet generates only 52% of their revenue from dry gas at current spot prices—that’s a big liquids component.  Cabot Oil and Gas (COG) generates 95% of their BOEs from dry gas, but only 81% of their revenues at current spot pricing.  This substantially narrows the number of “gas” E&Ps.

In addition, some E&Ps (Sandridge in particular) have taken to creating Royalty Trust/MLP vehicles – carving out gassy assets and selling them to retail investors at absurd valuations, raising substantial amounts of cash.  This game will continue into 2012.

Lastly, some E&Ps are rapidly switching their production from gas to oil.  Chesapeake, for example, has decreased the percentage of their production that comes from dry gas from 90% in Q3 2010 to 83% in the most recent quarter.

The following table lists the major U.S. E&P’s, sorted by the percentage of their production (in BOEs) that currently comes from natural gas (from least to most).  The farther down companies are on this list, the more vulnerable their cash flow and stock prices are to lower gas prices.

It also shows their production mix a year ago (Q3 2010) to allow for comparison, as well as the percentage of revenues based on current production that would come from natural gas using $3.50 natural gas price realizations and $94 WTI crude realizations.

As always, feel free to call with any questions!

- Nathan Weiss

Unit Economics, founded in 2008, is a Boston-based independent research firm providing institutional investors with insightful research on small and mid-cap equity securities and market themes.  Senior Analyst and company founder, Nathan Weiss, was the author of The Weiss Report, a monthly newsletter focused on risk arbitrage and market neutral strategies from 1998 to 2000. From 2000 to 2006 Mr. Weiss was a generalist analyst and portfolio manager at Noble Partners, contributing significantly to their outstanding returns.  Mr. Weiss holds a Master of Science in Investment Management from Boston University and a BBA in Business Administration from the University of Iowa.

Unit Economics
A Division of Weiss, Harrington and Associates, LLC
44 School St., Suite 805
Boston, MA 02108
office: (617) 227-5871
mobile: (617) 763-4415

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I asked Cory Mitchell to explain two scenarios that could play out in the global energy markets, and what it means for energy investors. Here’s Part 1 of his story.

- Keith

The Macro Dilemma
by Cory Mitchell, CMT

Energy investors need to be aware there are two massive macro forces in our global markets and economies battling it out.  One is obvious (and positive!), and one is not—it’s negative.  But the new global credit crunch has brought this dilemma for energy investors into sharp focus:

1.   Stagnant or declining oil production, which should mean oil prices—and oil stocks—are going higher.

But as I’ll show you…

2.   If oil production declines, it will have a negative on global debt and GDP—declining oil production will in turn lead to a long-term decline in the global economy – and a declining economy should push the price of oil down.  The lack of continued growth in oil supply has been a constraint on global growth since 2004, says Canada’s Sprott Asset Management.

One scenario points to a higher oil price, and another to a lower price—yet they are two sides of the same coin.  And while it’s counter-intuitive, lower oil production can potentially lower oil prices by constraining demand. As these contrasting forces play out now and in to the future, oil markets are likely to remain volatile.

The volatility created by this global battle will present opportunities for energy investors as the macro forces play out.

Economic Relationships with Oil

Oil production (and consumption) drives GDP and debt.  While debt is often viewed negatively, it is what allows our economy to expand.  When a consumer goes to the bank and gets a loan, money is created.

This money is then spent and deposited into someone else’s bank account, allowing the bank to grant another loan and so on.  This is healthy for the economy as long as the process is not taken to extremes and leveraged too highly, like what occurred in the 2008 “credit crisis.”

US debt had been steadily rising but has now plateaued, as shown in Figure 1. The problem is, debt—and thus the economy—do not expand if oil production does not expand.

Figure 1. US Government and Non-Government Debt:

*Source: http://www.theoildrum.com/node/8268

Figure 2 shows the high correlation of oil production and GDP.  Oil production levelling off corresponds to the flattening in debt (above) and GDP that we are currently seeing.  Oil production levelled off in 2005 and GDP is failing to get above 2008 levels after a significant decline.  The plateaus in oil production, debt and GDP may be short-term, or may indicate a long-term lack of growth or decline in global economies.

It’s interesting to note that oil production and demand has increased steadily by 10 million barrels of oil per day per decade since 1970—just as the world experienced the largest debt increase in global economic history.

Figure 2 World Oil Production and GDP (Crude Production in blue and scale on the right, GDP in red and scale on the left):

*Source: Economagic

Figure 3 shows the high correlation of oil consumption to GDP.  The relationship of oil production to these major economic factors—debt and GDP—are unavoidable.  As goes oil production so goes the global economy.  The major issue presented is that oil production has levelled off.  If oil production cannot increase the world has reached “peak oil” and by extension, peak debt and peak GDP.

This means investors need to look for places which still exhibit growth prospects and may even benefit from peak oil over the next several years to decades.

Figure 3. Oil Consumption vs GDP:

*Source: Gail Tverberg,  The Link Between Peak Oil and Peak Debt

Issues the Relationship Presents

“Peak oil” occurs when global productions hits maximum output and can no longer continue to increase, leading to a long-term decline in supply.  Oil is what allows economies to operate, and without it to fuel many projects — well, companies, consumers and banks would have no need for debt.  Debt would dramatically drop, forcing down GDP in the process.

Therefore, peak oil and peak debt will create peak GDP.

When peak oil and peak debt (and by extension peak GDP) will exactly occur is unknown, but global production has levelled off and the idea that we are rapidly approaching a global peak oil production is becoming more prominent in the media.  Canada, however, is continuing to see its oil production rise—which is providing a very interesting opportunity for energy investors around the globe.

With debt and oil production levelling off, I believe that at some point the world will hit a “growth ceiling,” until some new technological advance drives us forward once again.  This has happened throughout history, when there have been moments of radical growth following a new technology or an increase in productivity.  Then growth levels off or declines until the next big idea comes along.

That big idea may or not be here yet — shale gas, hydrogen and electricity are some the alternatives currently being explored; though the transition away from oil will take at least 30-50 years according to Vaclav Smil in the book, Energy Transitions: History, Requirements and Prospects.  That’s not hard to fathom, given the vast infrastructure aligned with our dependence on oil.  At this time, creating or extracting an alternative fuel and transporting it stills relies on oil.

In conclusion, I see the combination of (at least short term) peak oil and peak debt, which should cause lower demand and lower oil prices, continuing to do battle against the idea that lower oil production should obviously mean higher oil price.

To me, this means the oil sector will continue to be a hot bed of macro volatility and investor opportunity.  And in my next article, I’ll explain how energy investors can best profit from the volatility created by these two forces.

- Cory Mitchell, CMT

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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

- Keith