You Don’t Have To Be Insane to Invest in American Energy…But It Helps

By
Keith Schaefer
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By Bill Powers

“Insanity: doing the same thing over and over again and expecting different results.” – Albert Einstein

Therefore, energy investors in North America are insane.

Cheap money (low interest rates) and high oil prices encouraged the drilling of many marginal plays from 2010-2014–causing a huge amount of energy bankruptcies after the oil price crash of 2014.

And what did investors learn?  Well if you look at  what has happened to former highly flyers–Ultra Petroleum (UPL-NYSE) and Halcon Petroleum (HK-NYSE)–not much.  Even after bankruptcy, neither investors nor management has learned much.

Now, Ultra is a natgas producer, but the principle of a mid-tier US producer going bankrupt and then re-emerging as the same entity on the other side with the same management producing from the same assets at the same prices as before…well I’m not sure that anyone really guessed that back in 2014.

Ultra went from $1-$100—and straight back to $1,  (old UPL shareholders retained equity in new company) as management mis-timed M&A activity and went for growth at all costs.  Their riches-to-rags story is doubly hard to believe when one considers their core Pinedale assets are some of the lowest cost in North America.

They had $3.92 billion in debt against assets of $1.28 billion going into bankruptcy.  But they were able to raise $2.98 billion in new debt.  I’m not sure the Saudis anticipated the Market would quickly re-fund the same energy teams to run the same assets—to the tune of billions of dollars—and keep producing hydrocarbons almost without a hitch.

(And the fact that management is about to receive $300 million in new stock—free of charge—with Watford alone getting some $35 million for nearly wiping out every shareholder in the company…let’s just not go there.)

Ultra Petroleum filed for bankruptcy protection in the first quarter of 2016—still producing 732 million cubic feet per day of gas.  By Q4 2016, despite its reduced activity levels, was still producing 711 million cubic feet of gas per day.  (Source: http://www.ultrapetroleum.com/phoenix.zhtml?c=62256&p=irol-newsArticle&ID=2248155 )   Q1 2017 numbers are not expected until early May.

Ultra  recently emerged from bankruptcy with a debt load of $2.13 billion, a very generous executive compensation plan (CEO Mike Watford  was paid $3 million in 2015 just prior to bankruptcy) and a drilling program that will grow its marginally profitable gas production and likely require additional borrowings. Sounds like more of the same!

Though management is only spending $500 million this year on estimated cash flows of $650-$700 million.

Now look at oil-focused Halcon Resources (NYSE:HK).  CEO Floyd Wilson became an American icon for developing the Eagle Ford gas-condensate play in SE Texas, and selling his company, Petrohawk, to BP at the top.

But shareholders of HK have felt nothing but pain—in the last five years, shareholders have lost 99.997% of their value.  The company has gone through a bankruptcy process after ringing up nearly $3 billion in debt by the end of 2015.

a

They bought assets in every major US play—the Bakken, Utica, Eagle Ford and Tuscaloosa Marine shales among others.    They did not get into the Permian—the one US play that can survive $45 oil–until after going bankrupt.

Despite HK’s reduced activity levels leading up the company’s seeking court protection in September 2016, production for full year 2016 averaged more than 37,000 barrels of equivalent per day, down approximately 10% from 2015 levels.   (Source: https://www.sec.gov/Archives/edgar/data/1282648/000104746917001083/a2230839z10-k.htm   Page 21)

And again, in 2016, as they came out of bankruptcy, Wilson received $4 million in salary and bonus as well as nearly $20 million in new stock in the recently reorganized company.

And they’re still buying assets—the latest being a $727 million acquisition for 21,495 acres producing 2,801 boe per day of production in the red-hot Delaware Basin on western flank of the Permian.  Now to be fair, at just under $34,000/acre, that’s actually cheap if they get results like Resolute Energy.

And management is expected to just spend cash flow this year at $315 million, based on 37,000 boepd.  However the share price continues to languish near its lows.

One could argue that these bankruptcy/re-organizations were happening as costs were dropping like a stone through lower service costs, and better fracking methods (longer laterals/more sand/finer sand)…so on a real time basis, the funders could see their pro-forma cash flows improving literally  month by month.

But The Big Picture remains the same: the same management–who suffered no financial pain while ruining thousands of shareholders–now running the same assets that drove them to bankruptcy, with continued high debt loads.

Einstein was right. We are insane.

The Oil Market is Under-Supplied by Two Million Barrels a Day

By
Keith Schaefer
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0

Here’s a bar bet you energy investors can use:  Hey, how much if any is the world under-supplied oil right now?

The answer, says one highly respected voice, would surprise you: They say the global oil market is currently undersupplied by 2 million barrels per day.  That’s a very bullish statement, and a bit out of consensus right now.

Core Labs – Access To Better Data Than Most

The problem with making oil price predictions is—getting reliable supply and demand data is next to impossible.

There are concerns about some of the data from the IEA in Paris, the EIA in Washington, and OPEC.

On the supply side of things there are few people who should have better data than Core Labs (CLB-NYSE).  Core Labs are the global leaders in understanding reservoir performance.  With offices in 50 different countries Core Lab has a client list that includes oil and gas majors, national and independent oil companies.

On a daily basis the company gets real time production data from producing basins across the globe.  They can actually see what production is doing in real-time.

Much of this data comes from Core’s “Joint Industry” project which involves global E&P producers agreeing to provide data on their reservoir performance with Core.

The appeal to the producers that contribute the data is that having Core Labs study accumulated data across the industry allows Core to come up with better reservoir solutions for everyone.

In addition to having access to data most others don’t, CLB’s past predictions provide some further reason to believe what they are saying.  In the company’s second quarter 2015 conference call Core indicated that it expected 2016 U.S. production fall by at least half a million barrels per day.

According to EIA data, U.S. production did exactly that.

In their just completed conference call, Core Labs revealed that they in fact do believe that the global oil market is indeed undersupplied by 2 million barrels per day.

Here is exactly what they said:

“From July to December of 2016, worldwide crude inventories fell by an average of approximately 770,000 barrels of oil per day. In addition, considering the January 2017 OPEC cuts of approximately 1.3 million barrels of oil per day, plus cuts from cooperating non-OPEC producers, including Russia, the world market could be under-supplied by more than 2 million barrels of oil per day.

The continued under-supply of crude oil should lead to extended worldwide inventory declines and a continuing rally in energy prices throughout 2017.”

If accurate this is obviously important for investors.

There are two parts to it.

The first is that the global oil market was undersupplied by 770,000 barrels per day in the second half of 2016 prior to the OPEC cuts.  That would be 138 million barrels of oil over those 6 months of the year.

That should show up in global oil inventories.  That is historical so we should be able to check it.

We can verify 100 million barrels of decline in OECD commercial oil inventories from July through December 2016 in OPEC’s February OMR (Oil Monthly Report):

a

OPEC February OMR

That is most of the decline that Core Labs refers to and it isn’t that hard to imagine a 38 million barrel decline in non-OECD inventories (think Saudi, Iran, China) over that time as well.

Verifying that is virtually impossible to do, but there is at least one article that suggests that Iranian floating storage that started 2016 at 40 million barrels is now drained.

The second and larger part is the 1.3 million barrel per day OPEC cut that was instituted in January.

To date the International Energy Agency reports that OPEC has achieved a 98 percent rate of compliance with those planned cuts.

b

Source: IEA OMR

Not every country has done exactly what it promised, but the Saudis have done more than their part to bring the group compliance pretty much in line.

Considering all of this, there does seem to be reason to believe that Core Labs statement of 2 million barrels of undersupply claim has some merit.

If This 2 Million Barrel Undersupply Is True – What Does It Mean?

If the global market for oil is now undersupplied by 2 million barrels per day it means that global inventories would come down by 730 million barrels over the course of 2017.

That isn’t bullish for oil.  That is uber-bullish for oil.

That would wipe out a full quarter of global oil storage.  Investors should also remember there is very little spare capacity in world production right now.  One could argue the existing high inventories IS the spare capacity cushion the world has between here and $100 oil again.

But will that undersupply last for the entire year?  Let’s think about the various moving parts.

First, there is global oil demand.  Core Labs believes that global oil demand growth will be at least 1 million barrels per day over the course of 2017; likely a little higher.  And that is consistent with most years.

By itself this demand growth would mean that our daily undersupply would increase to 3 million barrels per day by the end of the year.

Second, we have the Permian and U.S. shale production.  U.S. production declined by 550,000 barrels per day in 2016 but this year it is going to grow, no doubt about it.

But by how much?

Core Labs suggests that the U.S. could grow by 500,000 barrels per day in 2017.  I’ve seen estimates as high as 1 million barrels per day, but it will depend on the price of oil.

It likely won’t cover the increase in global demand.

Third, production in the rest of the world.

Core Labs believes the global production decline curve to be 3.3 percent.  Apply that to the 45 million or so barrels of production that is outside of OPEC/Russia and the U.S. and we could see 1.5 million barrels per day of declines.

Are there enough big projects coming on stream to offset that?

The IEA is predicting total non-OPEC production (including Russia and the U.S.) as increasing from 57.7 million barrels per day in 2016 to 58.1 million barrels per day this year.

c

All of that is in the U.S., so the IEA expects the rest of the world to tread water this year.

Fourth, what will OPEC do?

Compliance with the production cuts to date have been good.  Will that continue if the cuts are extended?

Rather than speculate let’s look at what they need to do.

Based on what I have detailed above the year end 2017 supply picture would be:

Core Labs Current Daily Undersupply – 2 million boe/d

Plus: 2017 Global Demand Growth – 1 million boe/d

Less: Permian/U.S. Production Growth – 500k to 1 million boe/d

Plus: Declining Non-U.S. Production – ???

Add these all together and I get at least a 2 million barrel per day shortfall by the end of the year.  Perhaps considerably more if global production declines.

That would mean that OPEC could bring its full 1.3 million barrel per day cut back on line and the world would still be consuming 700,000 barrels more than is supplied per day.

To Summarize – A Coming Oil Rally?

If Core Labs is correct, then if OPEC holds its current production level for the first 6 months of this year at least 360 million barrels of oil that is currently in storage should disappear.

That would get inventory levels to where we were near the start of 2014 before the glut started building.  We also need to consider that with global oil demand 4 million barrels per day higher today than it was in 2014 we will consume an extra 1.46 billion barrels of oil over the course of 2017.

A start of 2014 inventory level would be much tighter on current demand levels.

That should be enough to light more than a little fire under the price of oil by the middle of the year……if it is all true.

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The Most Boring Commodity Has The Most Upside

By
Keith Schaefer
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0

Sometimes finding the next big opportunity requires nothing more than common sense.

By 2018 frac sand demand in the United States will have tripled from 2016.

Common sense is all you need to know that this will be very good for frac sand stocks.

That is simple economics.

a

It really is very simple.

As demand for frac sand doubles—volumes and cash flows for frac sand companies will also double.

And that’s just if frac sand prices stay flat.  What if frac sand prices double—I mean, that is the law of supply and demand.  Prices go up if demand overwhelms supply.

While there are new frac sand mines coming online next year, they don’t come close to meeting demand.

If volumes AND prices double—the cash flow for frac sand suppliers should jump 4x.

We all know that cash flow drives stock prices in the energy sector.  So if cash flow goes up 400%, shouldn’t the stocks of these companies see A Big Run?

I have no doubt that any of the frac sand stocks are “buys” right now.

But I don’t get paid to find ‘any’ stock—my job is to find The One With The MOST Upside.

I want to find the least known, fastest growing producer with great management that is ideally located very close to the Permian Basin in west Texas.

That’s because…

Frac Sand Demand In The Permian Is Growing Much Faster

Across the entire United States frac sand demand is expected to double by 2018.

The rates of growth across different regions are very different.

In the Bakken and Eagle Ford production and drilling have been falling.

b

Common sense tells us that frac sand demand will be slower in those plays.

That means that frac sand demand must be growing much faster somewhere else.

It is, and that somewhere is the Permian Basin.

The chart above from Pioneer Resources (PXD-NYSE) sows that Permian production has kept chugging higher despite the collapse in oil prices.

Common sense tells us that frac sand demand in the Permian will be much greater than the rest of the US.

The Obvious Investment – Get Long Permian Frac Sand Providers

The rate of frac sand demand growth in the Permian is going to be incredible over the next three years.

What we need to own in order to profit from this is very obvious.

A frac sand provider that focuses purely on the Permian.

Simple enough right?

I’ve found The One.  Since it is unknown the stock is ludicrously cheap for the Permian focused growth that the company has in front of it.

In fact, there was just a buyout last month that value this company at 2-3 times its current market cap.

Common sense is all I need to know that this little company is an incredible opportunity and that is why I personally own a ton of stock.

Before the institutions catch onto it as the way to directly play Permian frac sand demand I’d like to share this idea with you…click HEREto get my full report, RISK-FREE.

 

The Most UN-Sustainable Dividends in the Market

By
Keith Schaefer
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0

What’s the most un-sustainable part of the global energy complex?

Maybe you would say co-ordinated OPEC production cuts.

Or perhaps you would bring up high growth rates of shale producers.

If you talked about the lack of free cash flow among shale producers you would be getting warm…

But for me, when I went looking through the final 2016 financial statements of the supermajors, their dividends seemed the most un-sustainable part of the industry.  That should make shareholders very nervous.

What these year end financials show is that these companies have spent the last two years continually digging a balance sheet hole.

With the commitment that they have to their dividends it doesn’t look like they will be putting their shovels down any time soon.

Law of holes – The first law of holes is an adage which states that “if you find yourself in a hole, stop digging”. Meaning that if in an untenable position, it is best to stop carrying on and exacerbating the situation

 
Behind The Numbers – Those Dividends Are A Heavy Burden

The largest oil companies and their dividend yields are as follows:

Exxon (XOM: NYSE) – 3.60%

Chevron (CVX: NYSE) – 4.11%

BP (BP: NYSE) – 7.12%

Total SA (TOT: NYSE) – 5.24%

Royal Dutch Shell (RDS-B: NYSE) – 6.97%

These companies have long taken great pride in being able to maintain their dividends through even the worst of oil crashes.

Exxon for example has 34 years of consecutive dividend increases.  Chevron has increased its dividend for 29 consecutive years.

That is very impressive to be sure.

However, when I drill into the 2016 financial statements of these companies I don’t find myself wondering if they should continue to increase dividends.

I find myself wondering if they should continue paying dividends.

In the table below I’ve laid out the 2016 cash inflows and outflows for each of these companies.

(In Billions) XOM CVX TOT BP RDS-B Total
Cash Inflow From Operations $22.1 $12.8 $16.5 $10.7 $20.6 $82.7
Cash Outflow For Capital Spending ($16.2) ($18.1) ($18.1) ($16.7) ($22.1) ($91.2)
Cash Outflow For Dividends ($12.5) ($8.1) ($2.6) ($4.6) ($9.7) ($37.5)
Net Cash Outflow ($6.6) ($13.4) ($4.2) ($10.6) ($11.2) ($46.0)

I have not given any credit for cash from asset sales since that isn’t a sustainable source of cash and I haven’t deducted any cash for asset purchases either (like the Shell purchase of BG Group).

I’ve tried to present a true picture of what these companies look like on an ongoing, sustained basis.

When I was putting this together I kind of knew what to expect, but I still find the numbers very sobering.

As a group, these companies outspent the cash that they generated by $46 billion.  Even if the group paid zero dollars in dividends it would not have lived within cash flow.

And this $46 billion outspend has not generated big production increases.  In fact generating production and reserve growth has been a constant struggle for the supermajors.

Admittedly oil and gas prices were low in 2016.

Now, remember my comment earlier about being warm if you were thinking about the lack of free cash flow among shale producers as being un-sustainable?

Behind The Numbers – Consuming Cash, But No Worse Than The Supermajors

The combined supermajor numbers weren’t exactly unexpected, but they are still an eye-opener.

What would a similar group of large independent shale producers look like?

To find out I decided to drill into the 2016 10-ks of the following four:

Continental Resources (CLR: NYSE) – (Bakken and SCOOP/STACK)

EOG Resources (EOG: NYSE) – (Bakken, Permian and Eagle Ford)

Pioneer Resources (PXD: NYSE) – (Permian)

Diamondback Energy (FANG: NYSE) – (Permian)

Again I’ve excluded cash spent on acquisitions and cash received for asset sales.  The only one of these companies that pays a dividend of any significance is EOG so I left the dividend numbers off the table.

Here is what I found:

(In Millions) PXD CLR FANG EOG Total
Cash Inflow From Operations $1,498.0 $1,125.0 $332.0 $2,359.0 $5,314.0
Cash Outflow For Capital Spending ($1,857.0) ($1,154.0) ($362.0) ($2,490.0) ($5,863.0)
Net Cash Outflow ($359.0) ($29.0) ($30.0) ($131.0) ($549.0)

As a group I was surprised by how little they actually outspent cash flow.  This is certainly not what we would have seen from these companies in 2014 or 2015.

The oil price crash has forced this industry group to spend more responsibly.

While these companies aren’t close to generating free cash flow, I find it interesting that they are doing a better job of living within cash flow than the supermajors are.

The sustainability of shale production has always been questioned (and rightfully so).  When I look at all of this data though, the most unsustainable thing that I see are the dividends that the supermajors are paying.

Would You Run Your Own Business Like This?

If the supermajors are outspending cash inflows by $46 billion to pay their dividends the funding of that cash has to come from somewhere.

The vast majority is from increased balance sheet leverage either through a reduction of cash on hand or increased debt.

That begs the question of whether those dividends are really in the best interests of the shareholders to whom they are being paid.  If that cash had been invested in new projects at least cash generating ability would have grown and balance sheet deterioration lessened.

Since the oil crash the industry has canceled $1 trillion of projects and hundreds of thousands of workers fired.  While the supermajors have taken a knife to every imaginable expense their dividends have been spared.

At some point one of these companies is going to make an unpopular but sensible decision and do what the shale producers did: start living within cash flow.

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I Do NOT Want to Own This Stock For One Year

By
Keith Schaefer
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0

Investors don’t need to hire Sherlock Holmes to help them see what it did to the balance sheet of Cenovus (CVE-NYSE/TSX) after spending $17.7 billion to buy most of Conoco-Phillips (COP-NYSE) Canadian assets this week.

It’s a whopper of a deal.

In total what is being acquired adds 298,000 BOE/day of production for Cenovus.

178,000 BOE/day of that relates to Foster Creek and Christina Lake (FCCL) oil sands production (CVE already owns the other 50% of those assets) and the other 120,000 gas weighted BOE/day is from the Deep Basin.  There is also 1.4 bcf/d of natgas infrastructure.

The production addition almost exactly doubles Cenovus production to 588,000 BOE/day.

a

Source: Cenovus Presentation

Here is how Cenovus will cover the $17.7 billion price tag:

  • $3.6 billion of Cenovus shares issued to ConocoPhillips
  • $3.0 billion bought deal financing
  • $11.1 billion through debt and eventually asset sales

It is that last number that has raised more than a few eyebrows.

At the end of 2016 Cenovus was carrying $2.5 billion of net debt—about 0.9 times debt-to-cash-flow (D:CF) on 2017 strip pricing.  That put Cenovus at the head of its peer group in terms of balance sheet quality.

With the balance sheet being required fund $11.1 of this ConocoPhillips transaction the net debt figure for Cenovus is going to jump to $13.6 billion.

The transaction has doubled production, but increased debt levels fivefold, and tripled D:CF. Those are not a wash.

From the analyst reports that I have read debt to cash flow levels post transaction jump to more than 3 times from 0.9 times before.

That takes Cenovus from the best in class in terms of balance sheet quality to near the worst of the bunch.  It also puts the company in a position where it is much less able to withstand the uncertainties of this business.

That is a lot of added risk.   What then is the reward?

According to Cenovus itself the cash flow from the $17.7 billion of acquired assets is running at $1.8 billion per year.  That would mean that Cenovus just paid $17.7 billion / $1.8 billion = 9.8 times cash flow for those assets.

On a flowing barrel basis the purchase metric is $59,000 per flowing barrel.

Neither of those metrics seem like a bargain given what we know about transaction prices in this industry.  I’d say that it seems like about a fair price.

At best.

b

My opinion (and I doubt I’m alone) is that if you are going to do this kind of damage to your balance sheet then you had better be paying a price that is an absolute steal.

I think that on the surface that is clearly not the case here.

When I dig a little deeper I’m even more skeptical.

Earlier this month Canadian Natural Resources (CNQ:TSX/NYSE) paid $58,402 per flowing boe (barrel of oil equivalent; this is how the industry transforms natural gas economics into oil-speak at a ratio of 6:1) for Shell (RDS.A-NYSE)’s oil sands assets.

I don’t like what that implies about what Cenovus just paid for Conoco’s Deep Basin assets.

Follow my logic:

Total Cenovus purchase price – $17.7 billion

Allocate to oil sands based on CNQ deal – 178,000 boe x $58,402 = $10.4 billion

Remainder then allocated to Deep Basin assets – $17.7 billion – $10.4 billion = $7.3 billion.

c

Source: Cenovus Presentation

If I assume that the FCCL assets that Cenovus bought are worth the same on a flowing barrel basis as what CNQ bought (which is a stretch) it means that Cenovus is paying $7.3 billion for 120,000 boe/day ($60,833 per flowing barrel) of Deep Basin assets.

These Deep Basin assets have only a 26 percent liquids weighting—it’s mostly dry gas, and that is a very steep price for gas weighted assets.

And it may be worse than that.

I’ve used the multiple paid by CNQ to value the oil sands assets that Cenovus just acquired but that is likely too optimistic.  The CNQ-acquired production is already upgraded and therefore sells for a higher price than the production Cenovus bought.

My contacts in the oilpatch say the difference between the two deals is this: CNQ captain Murray Edwards waits for deals. Shell came to him.  Cenovus had been talking to COP for well over a year, and offered to buy the Deep Basin assets to sweeten the deal and get it done.

And what about that Western Canadian natural gas glut?  Tell me that these Deep Basin assets aren’t going to be faced some very weak natural gas prices in the years to come.

That is another risk on top of the balance sheet risk assumed.

The deal also makes Cenovus less integrated with more direct exposure to heavy oil pricing differentials.  With heavy oil production appearing set to overwhelm existing pipeline capacity in 2017 that is another potential negative to this deal.

d

When you leverage up your balance sheet you aren’t looking to also increase the volatility of your cash generating ability.

Another negative is that a clause in the deal involves contingency payments to Conoco Phillips if oil prices do rise.  These contingencies will cause Cenovus to lose 15 to 20 percent of any rise in the price of oil.

With the risks that Cenovus is adding I sure hate to see the company not all of that upside as potential reward.

And speaking of taking away upside from CVE shareholders—COP was emphatic in saying they are selling ALL their 200 million + CVE shares once the six month hold period expires—“in an orderly fashion”.  Between the TSX and NYSE, the company trades about 3.5 million shares a day.  If they can sell 1 million shares a day—which would impact markets—that’s almost a year of selling.  In a flat oil environment—under $55/b—this stock will stay under pressure until The Street can take out that block.

You Don’t Drop $17 Billion Without Giving It Some Thought

It is easy for me to armchair quarterback this transaction.

I really like top quality balance sheets in commodity producers, so I’m pre-disposed to being negative here.  And The Street values the optionality of a strong balance sheet.  High debt companies always trade at a lower valuation.

So what then is the other side of this?

Why did the Cenovus Board and management team decide to dramatically worsen the company’s financial strength to double the size of the company?

I see a few positives.

First, the plan is to sell assets this year to get the debt down.  The company is already marketing both its Pelican Lake and Suffield properties.  Selling those will help bring debt levels down closer to 2 times EBITDA. That’s still more than twice where it was pre-transaction but better.

Of course, now everybody else KNOWS that Cenovus wants to sell, so CVE’s negotiating position has been weakened.

Second, I do appreciate the fact that the Deep Basin assets that are being acquired are short-cycle in nature.  The existing opportunities that Cenovus has—oilsands—require a long lead time which is not so appealing in this post-crash volatile oil price world.

This gives the company more option to see investments made turn into cash flow much faster.

Third, these Deep Basin assets provide a huge free option on continued technological advancements from the oil industry.

Cenovus is acquiring 3 million acres of land and who knows what that could turn into in the years to come as different formations are exploited.

Fourth, CVE is the partner on the oilsands assets COP is selling—so there is obvious synergies.

Fifth—historically, American companies have to come to Canada at the top of the market and left at the bottom.  Ask Mike Rose of Tourmaline.

Sixth–heavy oil and natgas pricing have been stronger this winter than I would have expected.  It is possible to say markets for both those products in the US are structurally tighter this year than last (at least, right this second).

The bottom line is now, however, that Cenovus is much more vulnerable to a sustained downturn in the price of oil.  It becomes a much more levered play…and I’m not convinced institutional investors want to own that much risk in their Big Positions in oil.

Good balance sheets allow companies to have more control over their long-term success or failure no matter what commodity prices do.  Leveraged balance sheets take away a lot of that control.  CVE has a lot less control now.

Cenovus has made its bet.  Now it is up to those commodity prices to see how it turns out.

The Bullish Silver Lining In The Oil Price Collapse

By
Keith Schaefer
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0

Psychological fears of an oil glut are have caused oil prices to drop from $55-$48.  But there is some fundamental  economic factors that suggest this price drop will be short lived.

So far in 2017, U.S. crude oil inventories have increased 49.38 million barrels to 528.39 million barrels as the following chart displays:

a

While the recent builds appear negative, over the past five years U.S. crude inventories have increased 26.23 million barrels, on average, during the same nine week period over the past five years.

But over the past few weeks, unplanned and accelerated refinery maintenance (meaning they go offline) has created a one-two punch – resulting in lower refinery throughput while crude oil imports have continued at a (higher) rate that would really be meant for higher refinery utilization than we’ve seen this year.  That’s because imports are generally scheduled weeks to months in advance.

On average, 48.1% of crude used by U.S. refineries is imported.  Since early 2017, U.S. crude imports have averaged 50.97% of refinery throughput – up from 47.62% in Q4 and 48.78% YoY.  Had U.S. crude imports remained at 48.1% of refinery throughput, U.S. crude inventories would have increased by just 14.88 million barrels so far in 2017 – well below the five year average build of 26.23 mln barrels.

The ‘excess’ U.S. crude imports (versus refinery utilization) were most likely accidental and there is one very encouraging sign that reduced imports will correct the imbalance shortly: benchmark VLCC charter rates for Arabian Gulf to Gulf of Mexico voyages have plunged from $27,000/day at the end of 2016 to just $920/day today – as the following chart displays:

b

That screams—lack of demand.  And the Market is very fixated on the weekly waterborne import number the EIA puts out every Wednesday morning at 1030 am EST.

The conclusion is that imports were temporarily (and accidentally) elevated and could decline meaningfully over the next two months (ultimately averaging roughly 48% of refinery throughput in 1H17), and crude oil prices will bounce back meaningfully with lower US imports.

Huge Imbalance in Crude Oil Positions: McClellan Oscillator

By
Keith Schaefer
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Editors Note: I’ve been following Tom McClellan for years. He has an uncanny ability to find intriguing economic relationships–ones you would never expect–through charting.  His recent article on oil was so direct, so simple I asked him to share it with you today.  I’ve been a subscriber for a couple years now, and you can find a link to Tom’s service at the bottom of this article.

Chart In Focus: by Tom McClellan
Huge Imbalance in Crude Oil Positions

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March 10, 2017
There is a giant wall of short positions held by the smart-money “commercial” traders in crude oil futures, and it is going to lead oil prices to come crashing down.

Each week, the CFTC reports on the numbers of long and short positions held by futures traders.  They are broken down into 3 separate groups:

Commercials – Those engaged in the business related to that commodity.  They are the big money, and thus presumably the smart money.  Think Cargill for grains, or Goldman Sachs for financial futures.

Non-Commercials – Large speculators.  Think hedge funds.

Non-Reportables – Those whose positions are too small in number for the CFTC to bother tabulating them individually.
This week shows the commercial traders net short position, expressed in numbers of contracts.  They just reached an all-time (since 1986) record for the number of contracts that they are net short, i.e. short positions minus longs.  Every futures contract is simultaneously a long and a short position, with the two sides of that contract held by different parties.  The short side is the one that has to deliver the product, and the long side wants to take delivery, or at least that’s the design.  Speculators also play in the futures markets, never intending to take or make delivery.

In the crude oil market, the commercial traders are often the producers, using futures markets for their original intended purpose, which is to be able to lock in prices now for sales of future production.  So the direct message of seeing the commercial traders reach an all-time net short position is that the smart producers think that recent prices have been a great deal to lock in for their future production.  If oil prices were going to rise, then locking in now would not be a great deal.  But if oil prices are about to fall, then smart traders would want to lock in prices before that happens.  This seems to explain what we have just seen.  And understand that the speculators, large and small, have taken the opposite site of that big imbalance in positions.

The last time that the commercial traders came even close to this big of a net short position was back in June 2014, just before crude oil prices were cut in half.  I cannot forecast the magnitude of the coming move down, but the message here is that it should be substantial.
The notion of a down move for oil prices is confirmed by the spread between near and far month futures prices, known as “contango”.

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That spread recently narrowed to its smallest point in over 2 years, a sign that near month crude oil prices were topping.  When there is a big contango, then a trader could buy cheap oil in the spot market, rent a place to store it, and sell a more expensive futures contract.  Then all he has to do is wait a few months to deliver at that higher price.  As long as the spread is big enough to cover the cost of storage, then there is a lot of money to be made.

But when contango gets really small, up close to zero, then the cost of storage eats up all of the profit margin from that game, and traders look to dump that supply on the market and stop paying rent.  This is the sort of condition we are entering now, with a glut of oil coming onto the spot market.

The point is that prices for crude oil are likely to fall for a while, and we will probably know that they are done falling only when we see the commercial traders covering their shorts in a big way.

Get more information about Tom McClellan’s subscription publications at https://www.mcoscillator.com/subscriptions/signup.php .  You can also sign up on his Home page for a free weekly Chart In Focus series of articles like this one.”

Tom McClellan
Editor, The McClellan Market Report
tom@mcoscillator.com
Now On Twitter: @McClellanOsc
(253) 581-4889
Timer Digest’s #2 Stock Market Timer for 2016
and #1 Gold Timer for 2015

This Country Is Caught In A Catch-22 with Energy

By
Keith Schaefer
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Falcon Oil and Gas is in a “Catch-22” situation in Australia.  In fact, you could argue that natural gas consumers down the entire east side of the country is in the same “Catch-22”.

A “Catch-22”—the name of the famous 1961 book by Joseph Heller—is “a dilemma or difficult circumstance from which there is no escape because of mutually conflicting or dependent conditions.

You see, natgas prices in heavily populated eastern Australia have soared—up to $25-$30/GJ, or 6x North American pricing–as LNG exports have created international competition for demand.  In fact, just yesterday, the Australian Energy Market Operator said they forecast there will not be enough natgas to meet summer demand at any price as early as next summer, through to 2025 (http://www.theaustralian.com.au/business/mining-energy/aemo-warns-of-blackouts-as-gas-runs-out/news-story/06c61083332d293f2a6ecd462dcba94a).

Falcon (FO-TSXv) and Aussie partner Origin Energy (ORG-ASX) have found a COLOSSAL natural gas shale deposit in Australia’s Northern Territory that could supply the east coast with much needed gas.

But the government of Australia’s Northern Territory—which has a population density less than Siberia—has imposed a moratorium on fracking.

That’s a Catch-22—shale gas is the solution to the problem but it’s also THE problem—at least according to the Northern Territory.

THE BACKDROP

Natgas pricing in Southern Australian has become volatile—due to LNG exports (is there a lesson here for North America?).

In July of 2016 natural gas prices in Southern Australia spiked as LNG exports in Queensland almost tripled total gas demand on the East Coast of the country.

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 Source: reneweconomy.com.au

Southern Aussie gas prices reached daily average prices of more than A$25/GJ which is 600% higher than the price of gas in the United States when converted to greenbacks.

It was also multiples of what Australians are used to paying.  And then just yesterday

Historically, natural gas prices on Australia’s East Coast had been based on long term contracts with stable A$3-4/GJ prices.  The introduction of LNG exports has resulted in a closer link of Australian natural gas prices to higher international pricing.

You can see in the chart above how prices had been well above the A$3-4/GJ price even before the July 2016 spike.

LNG demand may be the main driver behind this price spike but it isn’t the only one.  Low oil prices have reduced the amount of cash flow Australian producers have available to invest in developing new supply.

Coal fired power plants have been closing—which is causing demand for natural for power in Australia to increase (again, just like the US).   New sources of supply in Australia have higher costs than legacy Gippsland and Cooper Basin production.

None of these factors are temporary problems.  These issues causing crazy high natgas prices are here to stay; it’s a new paradigm.

THE BEETALOO BASIN

Falcon and Origin have made an onshore discovery so big that I’m quite frankly having a hard time wrapping my head around it.  This Beetaloo Basin play is perfect in the sense that it’s huge, and it’s in the middle of nowhere—the Aussie Outback.

They’ve been working on it for years, and recently, Origin Energy released a Discovery Report on behalf of their combined Beetaloo Joint Venture (BJV).

The Discovery Report indicated that the acreage covered by the BJV contains 496 TCF of Original Gas in Place.

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Falcon’s interest in the BJV is 30%, so 146 TCF of the gas in place belongs to the tiny explorer with a market capitalization of just over $200 million.

Those huge numbers are the raw gas in the ground.  Obviously not all of it can be considered recoverable.

How much of it can be?

It is early days, but Origin believes that roughly 16% of the Beetaloo gas can be considered technically recoverable.  That would mean 85 TCF in total is recoverable for the BJV and 25 TCF for Falcon specifically.

Those are still crazy, crazy big numbers especially for a company with such a small market capitalization.  The size of this resource helps explain why Origin was willing to carry Falcon for $200 million worth of drilling.  That’s right—market cap=$200 million, and their carry on this one play alone is $200 million.

The acreage has had three vertical wells and one horizontal well drilled over the span of a couple of years. One well was the subject of a hydraulic fracture stimulation and an extended 57 day production test.

The drilling results, the production test and thousands of kilometers of seismic data combined were the basis for the Origin prepared Discovery Report.

And the Discovery Report included only the “B” shale of the middle Velkerri formation.   Within the Middle Velkerri there is more potential through the “A” and “C” formations plus an entire other shale formation called the Kyalla shale.

The Discovery Report covers 16,000 square kilometers which is the equivalent to almost 4 million acres.  That is basically the size of the entire country of Wales.

Falcon and Origin’s massive Beetaloo discovery could be a huge new supply of natural gas that would keep a lid on Australian natural gas prices for decades to come. We know from experience here in North America how massive shale resources can provide an entirely new future for the pricing of the commodity.

The Catch-22 – A Northern Territory Fracking Moratorium

Origin and Falcon have unleashed a massive discovery that could provide Australia’s consumers and economy with a major competitive advantage for decades to come.

For shareholders of these two companies (especially tiny Falcon) the discovery has the potential to be nothing short of a winning lottery ticket.  And it’s not just that—millions of Aussie natgas consumers would benefit hugely as well, when you’re paying $25/GJ for energy.

Do you feel the “but” coming?

On September 14, 2016 the Government of the Northern Territory in Australia announced a moratorium on hydraulic fracturing.

So here is little Falcon Oil and Gas sitting on trillions of cubic feet of natural gas –- potentially worth billions—and now not knowing whether they will ever be allowed to frac another well?

Of course a moratorium is a pause, not a final conclusion.  Since the moratorium was announced an independent Panel has been established to evaluate the issue and report back to the Government.  An interim report is expected by mid-2017 and a final report by the end of the year.

What is the likely recommendation of the Panel going to be?  I wouldn’t ever pretend to be able to predict such a thing.

What I do know is that the Australian Northern Territory is one of the least populated places on the planet.  The population density here is 0.2 people per square kilometer.  For some perspective on how sparsely populated that is consider that Siberia has 3 people per square kilometer.

Any concerns over pollution of drinking water have to be lower here than almost anywhere.
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Source: Worldatlas.com

As you can imagine, Origin and Falcon will not be drilling any additional wells until the outcome of the moratorium is known.  For shareholders of Falcon that means there is nothing to do but sit and wait.

And Aussie gas consumers can sit and fume…and keep paying.

In Joseph Heller’s book, Catch-22 refers to “absurd bureaucratic constraints” on soldiers in World War II.  I think this situation fits that phrase.

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