The Biggest Winner and Loser in the Last Oil Cycle

By
Keith Schaefer
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Oil went from $8-$147 per barrel between 1998-2008.  Then it crashed to $32.  Then it rocketed to $105 for five years.  Then it crashed to $27.

Notice a pattern at all?

Ever wonder why management of senior oil companies don’t notice this same pattern?  How can that be so when the long history of this business is nothing but booms and busts?

In a moment I’m going to compare for you two companies of a similar size.  One is another typical victim of this crash.  The other is going to come out the other side stronger because of it.

Why more companies weren’t in a position to do the latter….I do not fully understand.

The fact that oil crashed shouldn’t have been a surprise to anyone.  We have 150 plus years of oil production history that tells us that this is a highly cyclical business.

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Source: Goldman Sachs

The fact that we were five plus years into a bullish oil run should have had every energy executive worth his salt preparing for the next instance of the bottom falling out.

I’m no rocket scientist, but even my teenagers think I have a bit of common sense.

In July 2014 I told my subscribers that with oil over $100 per barrel I didn’t see a lot of upside under many scenarios.  With oil at $100 per barrel I really wasn’t thinking outside the box there.

Also at that time I told my subscribers that with oil at $100 per barrel I certainly could envision a lot of downside.

So I greatly reduced my oil exposure and found other ways to make money from energy.

My decision was based simply on common sense.  That simple common sense allowed my Oil and Gas Investments Bulletin portfolio continue climbing through 2014, 2015 and this year despite the complete carnage all around me.

If a simple thinker like myself could figure out that the time to build an ark is before it rains…..why couldn’t the majority of the people running oil producers?

For investors, the very cyclical nature of this industry isn’t something to fear–it’s something to embrace.

Rather than be a victim of the cyclicality I don’t understand why more companies don’t do what I do which is try to exploit it.

How It Should Be Done (Suncor), and How It Shouldn’t (Marathon)

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Source: Yahoo Finance

A picture tells a thousand words and the stock chart above definitely does too.

Since the middle of 2015 when it became clear that the oil crash wasn’t going to be a short one Suncor’s (TSX/NYSE:SU) share price has held strong, while Marathon Oil’s (NYSE:MRO) has taken a beating.

Both companies are very large independent producers, virtually mini-majors.

Suncor produces 695,000 boe/day while Marathon produces 430,000 boe/day.

Suncor has distinguished itself in the eyes of investors over the past year while Marathon has been forced into an ultra-defensive position where it is just trying to survive.

Dividend Policy

Marathon hasn’t completely eliminated its dividend but it isn’t far off.  From paying $0.21 per quarter as a dividend leading up to the oil price crash Marathon has dropped its dividend to only $0.05 per quarter.

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At this point Marathon is paying a dividend more for the sake of saying that it is paying a dividend than because it wants to pay a dividend.  Marathon shareholders have had the double whammy of both the share price and dividend collapsing.

There have been no dividend cuts from Suncor despite oil prices at one point losing almost 75% from the 2014 peak.  In fact these cheeky monkeys at Suncor actually increased their dividend by a penny per quarter in September 2015.

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Doing that while oil has fallen as far as it has is a tremendous accomplishment.

Acquisition and Dispositions

We are now 18 months plus into this oil crash.  Cash flows are crimped, balance sheets strained and the bankers no longer willing to lend.

To say that this is a buyer’s market for oil and gas properties is an understatement of epic proportions.

You can likely imagine which side of buying and selling these two companies are on.

Marathon’s balance sheet is in rough shape.   Over the past year the company has sold $1.3 billion of assets into this buyer’s market.

In the largest transaction Marathon sold all of its Wyoming assets for $870 million. The properties consisted only of very low waterflood developments in the Big Horn and Wind River basins which averaged 16,500 barrels per day in first quarter 2016.  That is only $52,727 per flowing barrel which is likely less than half what those assets would have gone for in 2014.

Marathon is selling at the worst possible time.  The company is a victim of low oil prices.  It is too bad they don’t have the $1.5 billion in cash that they spent buying back shares at $35 when oil prices are higher.

Suncor on the other hand is not a victim.  The management group of Suncor has positioned the company to take advantage this opportunity.

And Suncor has.

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Over the past several months Suncor has been able to turn its 12% interest in Syncrude into a majority 53.74% interest by acquiring all of Syncrude pure-play Canadian Oil Sands as well as Murphy Oil’s small piece of Syncrude.

On top of that Suncor has tucked in another 10% interest in its Fort Hills oil sands project.

Comparing these Syncrude transactions by Suncor looks like a major steal compared to what Sinopec (NYSE:SHI) paid for Conoco Phillips (NYSE:COP) Syncrude interest in 2010.

Sinopec’s price was $4.65 billion for a 9.03% interest in Syncrude.   Suncor’s price for 41.74% of Syncrude was only $7.8 billion.  (The consideration being $4.3 billion in equity plus $2.6 billion of assumed debt for Canadian Oil Sands and $937 million for Murphy Oil’s stake.)

If Suncor paid the same price per percentage of Syncrude as Sinopec did the price would have been $21.5 billion.  Suncor paid one-third the price that Sinopec did.

You might think that Suncor being in a financial position that allows it to be an acquirer is luck.   I doubt it considering that the last time Suncor pounced on a major asset was when oil prices last crashed.  In 2009 Suncor made a major acquisition acquiring Petro-Canada.

Equity Issuance

When commodity prices crash, commodity producer cash flows are going to do the same.  It makes a lot of sense to adjust dividend policy accordingly.

As a shareholder I can handle that.

But it gets worse when following Marathon Oil.

In 2013 and 2014 Marathon’s stock price spent most of the time above $35 and during this time the company repurchased $1.5 billion worth of shares.  In total Marathon repurchased roughly 43 million shares.

That is $1.5 billion dollars spent at share prices that are three times the current level.

In 2015 Marathon shut down its share repurchase plan entirely.  Then came the brutal kick in the stomach for shareholders.

On February 29, 2016 Marathon announced that it would be issuing 145 million shares at a price of $7.65.

Let me recap those numbers…

  • In 2013/2014 Marathon spent $1.5 billion to repurchase 43 million shares at $35
  • In 2016 Marathon issued 145 million shares at $7.65 to raise $1.1 billion

The net impact of this is that Marathon is out of pocket $400 million and has increased its share count by 102 million (on a 770 million outstanding share base).

That’ s just brutal.

Suncor meanwhile has reduced its share repurchasing since oil dropped to match its reduced cash flows. It hasn’t had any sort of a share issuance to raise cash so Suncor shareholders haven’t experienced the ugly dilution that Marathon shareholders have seen.

Build the Ark Before It Rains

You have to wonder what so many of the management teams in this industry were thinking when oil was at $100 per barrel.

Yes, everything is easy with the benefit of hindsight but the fact that oil prices would crash again was never a matter of if.  It was just a matter of when.

Instead of hitting the accelerator on spending when oil prices were high companies should have been making their balance sheets bulletproof.  Instead so many of them go to work on their balance sheets after the crash has happened when selling assets and issuing equity is painfully dilutive.

EDITORS NOTE–There’s one junior producer out there who has made an amazing deal at the bottom of the market–access to most of the ground surrounding an 850 million barrel field–near-virgin territory, with no work done on this prolific ground for 50 years…I think it will The Play of The Year…CLICK HERE for the details…

The Big Winner at the OPEC Meeting

By
Keith Schaefer
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The media said there was no winner at the June OPEC meeting held early this past week.

But there was—a big winner in fact.

OPEC producers didn’t win because they didn’t get a production-cap deal that would instantly give them a higher oil price.

Even the Saudis are now issuing multi-billion dollar bonds to keep their economy afloat.

Oil consumers didn’t win because the price of oil didn’t drop on this news.

But the low-cost western producer that not only makes great money at $45-$50 oil, but makes it so fast that it can still grow in leaps and bounds—they’re the winner.

I’ve been buying the stock for months, and I’m still buying it—because it’s making me money.

$45-$50/barrel is the sweet spot for my #1 Oil Stock—because it makes money like nobody else at this price.

Get the name and symbol BEFORE its next quarterly report comes out—CLICK HERE

OPEC lost, but this stock keeps winning.

Keith Schaefer

China is Importing This (Surprising) Commodity at Record Levels

By
Keith Schaefer
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Who said Chinese commodity demand was dead?

Through the first three months of 2016 China imported 75.2 million gallons of ethanol from the United States.  That is more ethanol than the 70.5 million gallons China imported from the US for all of 2015!  Ethanol is used around the world as a gasoline additive to increase octane levels cheaply.

Here’s the story–and  it could be a Big One–along with the trade to go with it.

Prior to 2015 China was basically importing no American ethanol–3.3 million gallons in 2014.

Total US ethanol exports were 95.3 million gallons for the month of March, up 42% from February and the highest monthly volume in more than four years.

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For the month the biggest importers of that US ethanol were:

  • China 37 million gallons
  • Brazil 20.7 million gallons
  • Canada 16.2 million gallons

It is hard to get clarity as to whether the increase in Chinese demand over the past two years is a short-term surge or part of a longer term trend.

China is the world’s third largest producer of ethanol after the United States and Brazil.  The trouble that local producers have is that they rely on expensive domestic corn as their primary feedstock.

That can make U.S. and Brazilian ethanol a cheaper alternative if the cost of corn in China gets too high.

The Chinese Government over the past few months has bought up most of the domestic corn crop at high prices to support farmers.  The Government then resells it locally at higher prices than are available globally.

That has made it hard for Chinese ethanol producers to turn a profit.

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Fuel ethanol accounts for roughly one-third of all ethanol produced in China and more than half of the country’s consumption of industrial-grade ethanol.

Given that Chinese per-capita vehicle ownership is just a fraction of what we have here in North America ethanol demand for fuel could eventually overwhelm domestic supply of ethanol.  The surge in popularity of SUVs amongst Chinese vehicle buyers is also a demand positive.

This is good long term news for American ethanol producers.

Another long term plus could be the environmental movement which is picking up momentum in China.  The Government has pledged to reduce carbon emissions and there are ethanol blend mandates in place in six Chinese provinces (Heilongjiang, Jilin, Liaoning, Anhui, Henan and Guangxi).

Those blend rates of 8-12% have room to increase given that Brazil has ethanol blend mandates of 27%.

So while China is doing good things for American ethanol producers in 2016, it could do even better things going forward.  There are no guarantees though, especially given how committed the Chinese Government is to the electric car as being the solution.

The large Chinese exports have caused a (very positive) domino effect in the US ethanol market.  Consider this:
1) As a result, inventories are dropping and profit margins are now good and seasonally get stronger through the end of Q3 from here
2) RIN prices are strong.

Here’s what ethanol inventories are doing–the orange line in the chart below shows ethanol inventories coming down from all time highs into the 5 year band…still not great but showing the right direction: down.

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Now with RINs….ethanol that gets exported does not get a RIN attached to it.  What’s a RIN you ask? Only one of the most arcane and befuddling economic inventions known to man.  The US government mandates that every single gallon of ethanol used in the US has a Renewable Identification Number attached to it, and the refiners have to keep track of them to prove they are using 10% ethanol–which they are required to do by law.  (I don’t make or judge the rules, I just try to profit from them…)

Monthly gross generation through Q1 2016 has averaged 1.224 billion RINs, suggesting total generation for the year will reach just over 14.7 billion RINs. This exceeds the 14.5 billion gallon portion of the overall RFS mandate (Renewa le Fuel Standard) which can be met using ethanol or ‘D6’ RINs.

However, ethanol exports through the first quarter have averaged nearly 50 million gallons per month, on pace to reach nearly 600 million gallons for the year.  Accounting for projected exports (and non-compliance RIN retirements) suggests net generation of 14.1 billion D6 RINs in 2016, or 400 million RINs shy of the 2016 mandate.  RIN prices are up about 10%, or 7 cents a gallon, in the last 6 weeks. (This is bearish for independent refiners, BTW.)

This is further positive news for an ethanol market that is looking increasingly healthy every day – the research I’ve seen suggests that $52 WTI is necessary to support $.25 ethanol production margins, but note that margins are currently $.32 per gallon across the Midwest – a very positive development for US listed pure play ethanol stocks like REX-NYSE, PEIX-NASD and GPRE-NASD! 

The way to invest in this trade is to (obviously) buy the pure play ethanol producers.

Now, I’m going to paint a somewhat positive picture here, but readers should remember–this trade will go where oil goes.  If oil drops $5/b from here, the trade I’m about to tell you will go lower.  AND…as I’ll explain the Street would have to give the stock a higher multiple than 5…on my optimistic economics…to go a lot higher.  Hence I’ve only bought 5000 shares for now.

Ethanol producers are refiners; oil refiners have a crack spread (the price difference between the crude oil and the gasoline it produces; expressed in dollars per gallon) and ethanol producers have a crush spread (the difference between corn costs and ethanol sales).  The crush spread is the profit per gallon.

The two charts immediately below show, respectively, the Midwest crush spread and the West Coast crush spread:

Midwest Crush spread below

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West Coast crush spread below:

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As  you can see, Midwest margins have improved considerably.  And between a juicy increase in gasoline consumption and an even better jump in ethanol exports, I think these margins are here to stay for a couple quarters.

Here’s a chart of the seasonality of ethanol profitability:

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(The impact on GPRE’s earnings will still be positive, but less certain due to their reliance on ethanol futures rather than spot prices.)

Of those three ethanol stocks, Pacific Ethanol is my favourite.  (Quick background for new readers–PEIX was The Biggest OGIB Win Ever, in 2014, as I bought it at $3 and nine months later sold the last of it at $23.  The original report on PEIX and competitor Green Plains (GPRE-NASD) are in the subscriber Members Centre and worth reading ;-).)

PEIX was originally a west coast producer, but after it bought Aventine last year it now has 45% of 515 million gallons of its production capacity in the Midwest.

PEIX is a highly levered company, in a couple senses of the word.  There is only 43.2 million shares out for 515 million gallons of annual production.  Low share count=leverage. A $0.20 increase in ethanol production margins from Q1 to Q2–which has now happened–on 120 million (likely) gallons of production would make for a Q2 EBITDA of ~$24 million – a meaningful amount for a company with a $410 million Enterprise Value (on the day I bought the stock two weeks ago at $4.95).

Consensus EBITDA estimates for the year is $58.29 million. If the oil price stays steady here, that will go up for sure–there is a chance they could do close to that in Q2 and Q3 combined.  Be aware that a 5x EBITDA on $80 million EBITDA puts the stock at $5.  The Street would have to give the stock a higher multiple for this trade to give me the 50% I like to see in all my trades.

Leverage can also be debt.  At the end of Q1, PEIX only had $19 million cash and had $210 million debt, after paying down $17 million in debt to make its western plants debt free.  They are trying to re-finance that debt, and analysts estimate they could shave 300 bps on their interest.  One analyst noted they could sell one of their Midwest plants and be debt free.  Just over $140 million of that $210 million is term debt due the end of September 2017, though it is due at the Aventine plant level, not the corporate level.

One of the issues for me is that management hasn’t given much clarity around the midwest Aventine acquisition assets; they remain a bit of a black box and are a small wild card in quarterly reports.  They had no money spent on them for 3-4 years before PEIX bought them.

Now, IF PEIX can generate $50-$60 million in EBITDA they can use to pay down debt in the next two quarters, I can see the Street re-rating the stock higher. Also, I would think the Aventine shareholders who wanted to leave PEIX have now had the chance to do so; the merger completed July 1 2015 and all the stock has been free trading for a long time.

Add an activist shareholder (Candlewood) with a 25.8% stake who has said they want asset sales or some kind of restructuring to unlock shareholder value–and maybe the Market gets excited.

I hope I have laid out the positives and negatives of this trade.  In my corner I’ve got strong gasoline demand domestically and big China export demand.  Seasonality should favour me as well.  In the other corner is lower oil prices, less discipline by ethanol producers and new licenses for more ethanol plants in the US.

One other positive is the stock chart–it has just broken out.

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I got very lucky with the timing of the trade–the stock jumped $1/share the next day.  But if China keeps up its strong imports of US ethanol–which could have a big impact on air quality in the cities that use it–ethanol could become a Big Trade again.

EDITORS NOTE—The oil price appears ready for take-off.  I just told subscribers what the #1 Alpha Trade is for oil right now.  Get that symbol, along with The Lowest Cost Producer in the West–The Company that BEAT OPEC–to be positioned to profit BIG.  CLICK HERE

Keith Schaefer

This Wipes Out Any Spare Capacity OPEC Has

By
Keith Schaefer
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The Offshore Oil Business Is Crippled And It May Never Recover

How badly do oil producers want to transition out of the deepwater and focus on shale? And guess what that means for the global oil price?

Exxon Mobil (NYSE:XOM) just paid Seadrill (NYSE:SDRL) $125 million in cash to get out of its commitment to use the West Capella drillship.

exxonbuyout

Source: Seadrill
Don’t you wish someone would just pay you $125 million to pack up your things and just go home?

The contract that Exxon had on the Seadrill had an expiry date of April 2017.  Exxon couldn’t wait that long and instead elected to pay the equivalent of $370,000 per day to just get out of the deal.

Had Exxon used the West Capella it would have been paying $627,500 per day.

This is not a decision that is unique to Exxon.  The theme of shifting away from offshore projects is a consistent way across oil and gas producers.

Conoco Phillips – Last year the company said it is done with deepwater exploration forever.

Marathon Oil – Announced that all of its budget in 2016 will be directed to its onshore resource plays with only $30 million that was previously committed to going to offshore work.

Chevron – Is pivoting in a major way away from big ticket offshore projects and is hoping to ramp shale output up to 25% of the company’s production by the middle of the next decade.

This list goes on and on.   And this, dear reader, will almost single-handedly move the oil price higher in the coming two years.

Last August the U.S. federal government held an auction for offshore oil fields in the Gulf of Mexico.  Just five companies submitted bids and only 33 leases were sold.  This was the worst showing in three decades for the Western Gulf of Mexico.

Offshore Oil Production By The Numbers

Offshore production accounts for 30% of total global oil production. The percentage of global production has remained the same since the early 2000s but the absolute amount of production has grown.

offshore-numbers

Today nearly 22 million barrels of oil per day is produced offshore; the figure in the chart above includes all liquids.

Offshore production has lower decline rates than shale does, but considerably higher decline rates than onshore vertical developments.

It is hard to pinpoint these decline rates exactly since each field is unique unto itself.  What the industry generally believes is that offshore production declines at twice the rateof conventional onshore.

That would put the offshore decline rate somewhere between 15-20% per year.  These higher decline rates mean that the sudden halt to offshore development will result in BIG offshore production declines.

Off a 22 million barrel per day production base—15-20%= 3.3-4.4 million barrels a day—gone.  That is substantially more than the spare capacity of OPEC right now.  That means that in just one year, the world oil supply could be put into deep undersupply (pardon the pun) as offshore exploration and development stagnate.

Short Lead Time, No Exploration Risk

Shale/tight oil has beat offshore production in every way. Onshore costs are down dramatically. The time it takes to drill onshore wells is down.  Onshore flow rates have improved.

offshore-breakeven

But is isn’t just about breakeven-costs.  There are other considerations.

Going offshore involves taking exploration risk.  With shale, companies know they’ll get a producing well every time they drill.  You can imagine how many companies can afford to throw money down dry holes these days.

Even if an offshore exploration well is successful there are drawbacks.

Once a discovery is made offshore companies need to sink huge sums of money (often billions) over an extended time period (years) before any production can happen.  That leaves companies without any revenue from the money being spent for long stretches and also exposes them to commodity price swings.

Just imagine giving the thumbs up to a billion dollar offshore project that needs $70 per barrel oil and then having to watch oil crash just as production comes on stream.

Shale oil wells can be drilled in weeks meaning that there is very little time between investment and cash flow.   A shale well also costs under $10 million and can’t ruin a company like a billion dollar offshore project.

The location of shale within the continental United States is also far superior than being in the middle of the ocean.  Pipelines are already in place onshore, employees can go home to their families every night and the worst case accident scenario is much lessened.

Shale is simply a better option than deepwater development.  It is lower risk and has become higher return.

What Would It Take To Get
The Industry Interested In The Deepwater Again

The majority of the oil and gas sector is in serious financial difficulty.  It will take a long stretch of sustained high oil prices before anyone gets bullish on deepwater exploration again.

Existing discoveries will be developed.  Investing money in those situations provides a guaranteed return on investment through cash flow.  Wildcat deepwater exploration is not a business that is coming back for a long time, if ever.

Saudi Arabia’s decision to open the taps has changed this business for everyone.  The idea that sustained high oil prices were the norm for the future is gone.  Volatility is back and it isn’t going away.

There is no safety valve for oil prices.  It is everyone for themselves from this point forward.

Shale oil offers a predictable, manufacturing-like business model around which companies can plan.  And it can be stopped and started on a dime depending on oil prices.

Ten years ago shale oil wasn’t even on the radar.  Now it is has displaced the deepwater which was once thought to be our only savior from peak oil.

Now….about those electric cars.

Keith Schaefer

The Most Profitable Word in Energy is….

By
Keith Schaefer
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What is “optionality”?

In investing, it’s having a lot of upside with very little downside.  I would also call that an asymmetrical trade.

At $45-$50 per barrel oil, most producers no optionality.  They can’t grow—or if they can, it’s only by a small amount, like 5-10%.

But I found The Company—with enormous optionality at this oil price.  No other producer that I can find anywhere in the
world (that’s listed in North America…) can grow production like this one at $45-$50 oil.

There’s two reasons for that:

1)    They hit boomer wells—Big Ones; with high flow rates—hundreds of barrels a day
2)    The decline rates on their current wells is low

The downside protection is a balance sheet with no debt and a lot of very profitable production.

The optionality—the Big Growth—is drilling some virgin ground right beside an oil field that has produced 850 million barrels so far.

And it’s happening soon.  Get the name and symbol of this little gem RIGHT HERE.

The Two Most Important Questions Right Now

By
Keith Schaefer
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Canadian natural gas prices on the spot market hit an intraday low of $0.05/mcf earlier this month—that’s FIVE CENTS per thousand cubic feet.  That was a result of the massive forest fires around the oilsands hub city of Fort MacMurray, which has taken 1 MM bopd of heavy oil offline, and reduced natgas demand by about 1 billion cubic feet per day (1 bcf/d).

Obviously, nobody makes money at those prices.   But it sure beats the negative pricing—of over $1/mcf—that some spot sellers have had to endure a few days this year in Canada.  That’s right—producers paid to produce their gas—and not just a little bit; A LOT—over $1/mcf!

The well-hedged Canadian natgas producers however, are laughing all the way to the bank. Seven Generations (VII-TSX; SVRGF-PINK) has a robust 55% of current natural gas production hedged for the balance of 2016 at an outstanding C$4.00/Mcf, while the much smaller Delphi Energy (DEE-TSX; DPGYF-PINK) has hedged approximately 74% of their natural gas for the rest of 2016 at an even better C$4.20/Mcf.

I can’t think of another group of energy producers as Canadian natgas producers who see such different hedged vs. non-hedged pricing.

As an investor in Canadian natgas/condensate stocks, the obvious #1 question to ask management teams is now—how much are you hedged this year and next?

It’s hard to argue that they shouldn’t be hedging the maximum allowed—which is usually about 50% of production.

If a producer hedges more than that, they leave themselves open to the potential of pipeline outages or perhaps even forest fires creating a situation where hedging becomes speculating if they can’t produce or sell as much volume as they have hedged.

There are several producers who have 60-70% of production hedged, but generally they have
a) guaranteed pipeline capacity and
b) multiple delivery options
c) as well as a diverse production base
That makes the risk of hedging over 50% is somewhat limited.  However, the more a producer has hedged, the less upside they have IF commodity prices do rally significantly.

Producers selling into the Canadian spot market have had every Bad Luck Brick thrown at them in the last two years.

1) Super Low Cost Natgas from the Marcellus in Pennsylvania is stealing markets in:
a) US Midwest
b) US Northeast
c) Ontario & Quebec (Encana now says they can compete due to high condensate in their wells)

2) Increasing production in western Canada for the first time in several years as the industry figures out how to best produce the prolific Montney and underlying Duvernay plays on the AB/BC border

3) Thanks to the warm winter due to the weather phenomena known as El Nino, Canada is already at roughly 70% of natural gas storage capacity and the traditional injection season has barely started! Total storage in Canada is 66% higher than 2015 (as of April 30).

The story south of the border is not much better with current storage levels of 2,681 BCF being over 800 BCF above both last year and the 5 year average.

4) Massive wildfires around the oilsands hub of Fort MacMurray, reducing demand by 1 bcf/d.

Yes, all the fires in the oilsands has had a HUGE impact on natural gas—whether it be the utilization of gas to generate power for the upgrading process or to generate steam for injection into SAGD wells, the current estimate of lost demand for natural gas from this alone is ~1 Bcf/d—about 25-33% of production!

This has in turn resulted in the AECO (the name of the Canadian benchmark natural gas price)-Henry Hub differential widening to US$1.10/MMBtu last week.

This compares to the 2015 average differential of US$0.50/MMBtu  (In winter months it can be as low as US$0.30/MMBtu).With the Henry Hub June natural gas contract trading right around the US$2.00/MMBtu mark, the math isn’t very compelling for an unhedged producer in the WCSB.

Now, the 2nd question you want to ask of Canadian natural gas producers is—through which pipeline do you sell your gas? Because again, the price differences between them are….remarkable.

The Alliance pipeline gets the best pricing for producers.  This pipeline delivers production to the Chicago area.  The Chicago price for dry gas has a fairly high correlation to Henry Hub pricing, and remember that has been as high as $1.10/mcf more than Canadian gas—close to double.  DOUBLE.

So specifically ask management or search in the financials—how much of your gas do you sell via the Alliance pipeline.

There are two other export pipelines.  TransCanada’s NGTL pipeline gathers more than twice the natural gas in Western Canada than Alliance or the third pipeline system—Spectra—combined.  Accordingly NGTL becomes the de facto benchmark for pricing.

The Spectra system primarily gathers gas production in B.C., and although it can deliver into Alberta to access the other two export options, its pricing is driven mostly by demand from the B.C. Lower Mainland, Washington State and beyond (albeit via connecting pipelines past the Canadian border).

All three locations will have regional supply/demand implications that impact the respective prices, but generally follow seasonal pricing closely.

However, if a producer hasn’t committed to “Firm Service” capacity (essentially a take-or-pay commitment on the pipeline), then field pricing can get really crazy if there are regional issues or outages on a pipeline or at a particular gas plant when production exceeds take away capacity.

This mostly happens just on the NGTL pipeline, because both Spectra and Alliance have virtually all of their capacity committed to Firm Service agreements.

With all this in mind, if you are a Western Canadian natural gas producer with no Firm Service and no hedges in place, the world is a pretty ugly place right now.

Birchcliff Energy (BIR-TSX; BIREF-PINK) and Paramount Resources (POU-TSX; PRMRF-PINK) both have significant Firm Service contracts on NGTL, but it’s really only Alliance capacity that serves as a quasi price hedge and both of these names have none of their natural gas production hedged at present.

Trilogy Energy (TET-TSX; TETZF-PINK) and Pine Cliff Energy (PNE-TSX; PIFYF-PINK) are another pair of producers who are completely unhedged on the natural gas side and have the other exposure of no Firm Service agreements, Trilogy having not renewed their Alliance Pipeline capacity effective Dec, 2015.

There isn’t a very compelling picture for natural gas prices over the next few months. Sure the bulls will highlight that US production has rolled over and that demand continues to grow but storage continues to hit record seasonal highs.

If oilsands production continues to be impacted by the uncertainty of the current fire situation, storage could fill at even faster rates putting even more pressure on the spot AECO price.

But this leaves un-hedged natural gas weighted producers exposed to some serious price risk.

Canadian producers such as Crew Energy (CR-TSX; CWEGF-PINK), Delphi Energy, Leucrotta Exploration (LXE-TSX; LCTRF-PINK), NuVista Energy (NVA-TSX; NUVSF), Seven Generation Energy and Tourmaline Oil Corp (TOU-TSX; TRMLF-PINK) have Firm Service on the Alliance Pipeline.  Of these names all but Leucrotta have hedges in place for 2016 and 2017.

Companies like Bellatrix Exploration (BXE-TSX/NYSE), Painted Pony Petroleum (PPY-TSX; PDPYF-PINK) and Peyto Exploration (PEY-TSX; PEYUF-PINK) have solid hedges in place but definitely face greater price risk on their non-hedged production.  While names like Trilogy, Pine Cliff, Birchcliff and Paramount Resources are fighting an uphill battle to achieve positive cash flow in the near to medium term.

So as an investor it is prudent to look at

1) strongly hedged producers

2) producers with Firm Service on Alliance or to a lesser extent Spectra, or a robust hedging program or preferably BOTH, to best survive the lean times ahead.  These producers are best situated to escape the doldrums of the domestic market and it’s seemingly never ending depressed pricing.

The chart below has a rough guideline (all the data I could find quickly…) of hedges by leading Canadian natural gas producers:
1

P.S. My #1 Stock Pick for 2016 just had its Biggest Catalyst of the Year—and I expect it to be re-rated—in a very good way.  I just bought another $80,000 worth of stock.  I’m looking for a Big Gain—quickly—for my portfolio.  Get the Name and Symbol of this Stock–HERE

The New FrontRunner in the Global Lithium Race

By
Keith Schaefer
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0

Lithium is the hottest commodity in global energy, and there’s a race on to develop the next greenfield lithium mine (greenfield=from scratch).

Lithium X (LIX-TSXv; LIXXF-OTCBB)) took a big step to being The Next Big Lithium Producer with a deal last week to get a pilot plant operating at their Sal de Los Angeles property in Argentina.

The plant is expected to cost only US$9.3 million to build. The new partner, a technical consortium known as SESA, will earn its 50% stake by contributing US$6 million.

Lithium X will contribute the other $3.3 million to earn 30%; it will earn its other 20% by contributing brine to the facility from Sal de los Angeles.

Initially the plant will be built to produce 2,500 tonnes of lithium carbonate equivalent (LCE) annually. Once it is operating smoothly the partners will expand it to 5,000 tonnes LCE annual capacity.

It will provide the company with cash flow, and prepare the Market—and Lithium X–for full scale production, says Lithium X Vice President Will Randall.

“The cash flow from (the pilot plant) operations will go back to build this out to 5000 tons per year,” he said in an interview late last week.

“In conjunction with the pilot plant build, we’re also going to update the resource bring into a Measured and Indicated category.  That will help LIX as we do a feasibility study for a full 15,000 ton per year operation.”

Randall says the real time data and costs from the pilot build and operation will give a bankable feasibility study much higher quality numbers than normal.

“If, at the end of a year of processing, we have a facility that’s working well, and a robust feasibility, then raising the capital to build the full plant should be much easier.”  He added that pilot plant production also makes offtake (sales) agreements much easier to conclude.

The pilot plant itself will also be easier to build: the Sal de los Angeles partners will not actually product lithium carbonate. Instead, they plan to extract lithium from the brine and produce a concentrate grading 5-30% lithium – and then sell the concentrate.

Randall said the plan makes economic sense, as there is both a local market in Argentina for lithium concentrate and demand overseas in China.

“That’s what led me to the idea; I saw all these tankers going out with brine.  They basically line a container inside and fill it with concentrate.”

Randall says you still get most of the value for lithium—which has been quoted as high as US$20,000/tonne in China–without incurring the big costs to make lithium carbonate.

Eliminating those final steps lowers the technical and execution risk, he says. Carbonate plants are tough to build, especially at 4000 metres elevation, where there is a scarcity of energy and workers.

The world has lots of lithium, but like any metal, getting it into production can be difficult for political, economic or environmental reasons.

That’s why the first few new mines should enjoy the best margins. Even forecasts that use conservative assumptions around electric cars and exclude power storage completely still see lithium demand tripling within a decade.

Sal de los Angeles is one of few lithium assets in the world where conventional methods work to recover the lithium from the brine. The project is in the mining friendly Salta province, which is also lithium brine central: there are operating and feasibility-level lithium projects all around.

In fact, the team that built the most recent such mine finished up about a year ago…and just signed on to build the pilot plant for LIX.

As background, Lithium X is earning an 80% stake in Sal de los Angeles from Aberdeen International, which bought the property from Rodinia Minerals in 2015. Rodinia discovered the deposit and produced a Preliminary Economic AssessEA, under the leadership Will Randall…who is now VP Exploration for LIX.

So he knows it is one of few lithium brines in the world that can be brought into production quickly and easily, because the resource responds to conventional processing methods and because the project is located near infrastructure.

With this agreement not only has Lithium X found a partner to fund most of the build, it has found a partner with deep expertise to design, build, and operate the plant.   And SESA is responsible for any cost overruns .

SESA principals have been involved in the design, construction or operation of Orocobre, Sentient and FMC’s lithium production facilities in Argentina.

Randall says SESA wanted to use their knowledge and expertise to get involved with a lithium project on the ground floor.

The deal only covers 1% of the land mass and 3% of the resource, which means Lithium X remains free to develop the rest of Sal de los Angeles however it wants. And develop it LIX will – the real goal is to build a 15,000-tonne-year-year LCE operation in addition to the 2,500-5,000 tpa LCE pilot plant.

There are few assets in the world that people really need; but new lithium mines are one of them.  That’s why these junior lithium stocks are running so hard.

In almost every other case it takes years to move from idea to production, often decades. To do it in half a year is perhaps unprecedented.

The race is on, and Lithium X is ahead.

_____________________________________________

EDITORS NOTE–I profiled Lithium X at 46 cents in January 2016–and it’s on the way to production.  Another junior energy-related company I profiled last year has also made it to production.  Select Sands (SNS-TSXV) was able to secure and develop a greenfield frac sand deposit in Oklahoma.  I can’t tell you how hard it is to get a mining asset into production–even if it’s for energy!  But CEO Rasool Mohammad has done a commendable job in doing so–without raising hardly any money!  Interesting that the initial contract for the sand was for industrial minerals–with one of the largest industrial glass makers in the world–and not for fracking.  Well done Select Sands and CEO Mohammad!

Keith Schaefer

 

Be A SuperStar Energy Investor in 5 Minutes

By
Keith Schaefer
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0

It has been two years since I was earnestly combing through junior oil producers to find the best investment. But now that oil prices have moved up from $26-$46/barrel since mid-February, there are—believe it or not—a (very) few junior producers who can grow production within cash flow at these prices.

I’ve spent the last two years mostly investing in refineries and SmartGrid stocks—all “downstream” investments. Now could be the time to study the “upstream” producers again.

In this 5 min video, I tell you my top research points. What am I looking for in corporate powerpoints and company financials? And what are the key questions I want to ask management?

There’s no sales pitch here, it’s just a short educational video that prepares you to start investing in junior producers again—without being bamboozled by statistics.

– Keith

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