Where to Find Undiscovered Gems in Oil Stocks Now

By
Keith Schaefer
-
0

A Blueprint For Small Cap Oil and Gas Investment Success – Part 1

You only make Big Money on mis-understood investments.

And now that the oil price has collapsed to the point where there is almost no meaningful cash flow, mis-understood investments are easier to find.

That’s because the Market has divided oil stocks into two groups—those that can thrive at $65 oil and those that can’t.

Some go bankrupt, like the operating subsidiary for junior Bakken producer American Eagle did on May 11, and some just survive as zombie stocks—the walking dead who make enough cash flow to stay alive but not to grow.

But there’s actually a few—and these would be the less followed, smaller companies—that actually have quite good economics in Canada, given

  1. The lower Canadian dollar
  2. 15-25% reduction in service costs
  3. Continued improvements in fracking technology that is lowering costs per barrel—sometimes as much as 20% just since last summer!

You just have to use the right process to find them; your research has to quickly weed out the zombies.

There is so much leverage for investors in the junior oil sector now as valuations have been crushed—if you find one of the few that has stellar economics and a good team at the helm…you can make a lot of money right now.

With the right process, you not only increase reward but reduce risk in your investments.  I’ll give you my process right here, and the stock that it has led me to:

Box #1 – Proven Management Team With Real Skin In The Game

Management is so important in oil and gas production.  A good team thrives in bull markets and does more than survive in bear markets. A good management team has the respect of analyst and investment banking community which opens deal flow and allows for low cost access to capital (i.e. higher stock prices).

Do the bios for top management and the Board of Directors show a past track record of successfully building companies?  And how many shares did each of them own?  You want management to be both skilled and motivated by having significant skin in the game.
If management doesn’t have a great track record AND own a significant number of shares toss the company back on the zombie pile and look for another.

If that box is ticked proceed to the next boxes.

Box #2 – Low to No Debt–A Pristine Balance Sheet

Once you have an “A” Team with skin-in-the-game—look at the balance sheet.

I’ve watched companies like Legacy Oil and Gas that has a Tier 1 management team just slowly add on too much debt…and fall out of favour.  The team at Lightstream took Petrobank to $60 and Petrominerales to over $30 and were market darlings.  But now that team has one of the lowest valuations on the Street—all because of debt.

In Canada, the Market is very clear: lower debt levels get higher valuations—even though debt is essentially free, and makes a lot of business sense.  High growth, high debt companies can be very tempting in a bull market.  But it was the more highly leveraged oil stocks that fell 70-90% in late 2014 as oil prices collapsed.

So now the field of possible investments narrows.  The overleveraged companies are weeded out.  This is good—it should narrow, at every step in the process.  If your company has less than 1.5x debt-to-cash-flow, then your investment idea is ready for the next step.

Box #3 – Low Finding And Development Costs

Ok—now you have a proven team with a good balance sheet that is ready to drill baby drill…..but as an investor you better be very sure that what they are drilling is a top quality asset.

A good management team and good balance sheet can both get ruined by hitching their wagon to the wrong property.  The team at Pinecrest Energy are a Tier 1 group, and were the toast of the town for their high netback Slave Point play.  Everyone expected it to be the Next BIG Winner, and the Market gave it a huge valuation.

But this young asset never met expectations with unexpectedly high decline rates, and the stock went from just under $4 to just over four pennies.

The issue here for investors—Slave Point was not a proven play—you want a proven play with Top Tier Finding Costs.

At $100 oil these resource plays can make some money for junior producers.  Today, they are really only a good fit for larger companies.
Few resource plays (read: tight oil, shale oil) can recycle cash very quickly for a producer through rapid payouts.  I’m looking 18 month payouts now and at higher prices it’s 12 months.

Small companies have a limited amount of cash and typically don’t have an underlying base of low-decline production.  That is why these fast paybacks are so crucial.

I think this low oil price will bring back a lot of low-cost conventional vertical plays.  Wells are cheaper for juniors, and they can still have fast payouts and much lower decline rates.  That provides a much more stable base of production and cash flow which means less investment is required to maintain production and makes growth easier to achieve.

The company’s with the lowest cost are able to generate positive cash flows and drill profitable new wells even today.  When oil prices are high these best in industry assets are like owning a license to print money.

By now, a few more candidate stocks have fallen off the table.  My list grows shorter.  On to the next step:

Trait #4 – A Multi-Year Inventory of Low Risk Development Drilling

So now you have a company with a proven management team, solid balance sheet and an asset proven to be low-cost and highly economic, even at today’s commodity prices.

But you still need more……you need a visible path to future production and cash flow growth.

Look at RMP Resources (RMP-TSX)—they have the single most profitable play in all of Western Canada, IMHO—their Coquina formation wells paid out in weeks when oil was up at $100.  They have a well respected team. But that asset is only proven on 6-8 sections, with a 1-3 year drilling horizon.  The Market is just not willing to reward them for a long inventory yet, despite almost all the boxes being checked there.

To be a really great investment a small producer needs growth, and lots of it.

I’m looking for companies that have at least a five year inventory of low risk development drilling locations in a “de-risked” conventional play.  These are wells where I know what cash flow I’m getting.

Box #5 – Few Shares Issued; Low Float

The best small cap oil and gas opportunities are also found in companies with tight share structures.  Americans use more debt and Canadians use more equity (shares) to grow. I want a small share count where I have leverage to the future success of this great management team.

I also think a low share count is a sign of respect by management to their shareholders.  If they’re not willing to dilute a lot, there’s a much better chance they own a lot of stock (see Box #1).

This criteria often narrows the field dramatically, so I keep it close to the end.

Box #6 – An Attractive Valuation

Valuation is likely the least important of the six criteria—a) because I’m not afraid of expensive stocks.  They tend to stay expensive…until they don’t meet one of the above criteria.  And b) all the companies on the zombie pile are cheap now.

If a company is dirt cheap–it is usually dirt cheap for a very good reason. Either the assets are sub-par and the market is starting to figure this out or the company balance sheet is stretched.

A really great small producer might look expensive on the surface, but the rates of growth that these companies are able to achieve quickly make that valuation look incredibly cheap in hindsight.

A lot of companies have most of my boxes checked…but few have all of them.  (And I already own most of them—they’re The Leaders).
Proven Management Team That Owns A Lot of Stock
Great Balance Sheet
Proven Play with Low Finding And Development Costs
Years Of Growth via Development Drilling
Tight Share Structure
Attractive Valuation

The work is finding these companies lying in the Market’s zombie pile. But unlike zombies, these stocks do exist today.

There is one at the Top of My List right now.   I did my research, and went through all the boxes.  They all got checked off.  Just as a hint, management has sold three companies for a total of more than $1 billion—yet this stock trades so cheaply right now.

This one has the type of low risk, high reward combination that only can be found in the midst of an oil crash.  This baby has been thrown out with the bath water for absolutely no good reason.

That’s what makes it mis-understood. And that’s where the Big Gains are—especially if oil stays here or goes higher.

More to come in Part 2 when I show you exactly how this company ticks all of these boxes……

-Keith

 

What if Oil Is the Best Investment of 2015?

By
Keith Schaefer
-
0

Investors can’t say definitively that the price of oil bottomed in the third week of March, but some very recent data  released by the International Energy Agency (IEA) that supports the premise that a bottom is in.  More on that in a moment.

From a low near $43 per barrel WTI has been bumping around $60 per barrel this past week–a not insignificant increase of 40% over only a fifty day period of time.

1

Source of data: www.eia.gov

As investors we need to try and figure out if this is a short term head fake or something that is sustainable and based on supply and demand fundamentals.

A Rally Despite Repeatedly Bearish American Inventory Numbers

The oil data point that is most closely watched on a weekly basis by oil traders is the Wednesday EIA inventory report.

Week after week in 2015–up until the most recent (May 6) report–these inventory numbers have been unquestionably bearish.

2

U.S. inventory levels aren’t just high relative to the trailing five year range, they are off-the-charts-high.   When oil was in its mid-collapse stage in December 2014 inventory levels were still within that five year range.

Today those inventory levels sit 100 million barrels above the highest level of the past five years experienced at this time of year.

Looking at this inventory chart in isolation would make you think that oil prices should have been driven right into the ground.  Inventory levels are so high that there is talk from respectable sources that we may actually run out of places to put the stuff.

This is bearish on a level that we haven’t seen before.

Yet oil has rallied.  Why?

The most recent monthly Oil Market Report from the IEA provides a few clues–clues that I have been writing about in recent weeks.

On April 14th I wrote a story entitled “Surprise, Global Oil Demand is Surging…” and focused on the data that was available both in the United States as well as in China and India.

The IEA’s April Oil Market Report which was released to the public this week confirms exactly what I wrote about nearly a month ago.

The IEA appropriately describes what is happening at “The Plot Thickens”.

The IEA notes that there has been unexpected demand strength across the globe.  Why there wouldn’t be a positive demand reaction from a 50% decline in oil prices may be a bit perplexing to some, but nonetheless.

According to the IEA global year on year demand for oil increased by a “surprising” 1.3 million barrels per day year on year in the first quarter of 2015.

The demand charge was particularly strong in Asia with deliveries of oil rising by 110,000 barrels per day in Korea, 200,000 barrels per day in India and 250,000 barrels per day in China.

The IEA noted that even Russia which is subject to punishing economic sanctions was able to grow its oil consumption in the first quarter.

The inventory chart referred to earlier with inventory levels that were completely off the charts presented an incredibly bearish picture for oil.

The demand side of the equation has a similar looking chart, but one that is decidedly bullish.

3

Source of Chart: April 2015 IEA Monthly Oil Market Report

This chart depicts OECD gasoil/diesel demand for the first two months of 2015.  Like the inventory chart, monthly oil demand is far above the five year average and range.

For the first time in four years OECD demand has grown for four consecutive months.  Now that we are through refinery maintenance season and refining levels are higher we should see this demand growth show up in the inventory levels.

There was a reason that oil prices bottomed in March and started to rise despite continued bearish inventory data.

The Market figured out that oil demand was also soaring and I suspect also that it determined (also accurately) that U.S. production was flattening and heading into a decline.

If that trend continues, oil price and oil stocks could end up surprising everyone this year.  There are six stocks that I think outperform the Market if this trend continues.

At the end of 2015, don’t look back thinking I wish I would have known what those stocks were.  You get to see them and read about them RISK FREE click right HERE.
 

How Can Oil Stocks Be Cheap AND Expensive

By
Keith Schaefer
-
0

Is it time for investors to load up on oil shares–or time to sell?  The answer is–it depends what metric you’re looking at.  On a cash flow basis, they’re expensive.  But based on Net Asset Valuations (NAV), they’re cheap.  How can oil stocks be both expensive and cheap?  I’ll tell you.

First–where are we at today? The upticks in the oil price have got energy investors excited the last few weeks. A 30% move in WTI since mid-March—to as high as $57—has triggered a nearly 20% appreciation in producer indexes like S&P Oil and Gas E&P (NYSE: XOP).

By some metrics, the scale of optimism around oil-weighted E&Ps has become way overdone.

Alarms were sounded in an April 7 report from Canada’s RBC Capital Markets, which noted that large cap integrated and independent oil stocks are now pricing in WTI at $89 in the long-term.

That’s right, these stocks need oil at $89 in order to justify their valuations. When in fact WTI is still trading at just $55.

That’s a big discrepancy. One that should give investors pause for thought.

But digging into the numbers it becomes clear there’s something else going on when it comes to valuations for oil stocks.

Namely—it’s critical to decide what analytical metrics you’re looking at when it comes to valuing producers.

One go-to method of valuation for many analysts is the price-to-cash flow ratio, which simply shows a firm’s enterprise value as a multiple to the underlying cash being generated by current production.

Using the price-to-cash flow numbers, oil stocks do indeed look expensive today. Just look at a few recent figures from BMO Capital Markets.

BMO’s research shows that price-to-cash flow multiples for senior producers—companies like Marathon, Murphy, and Whiting—have rocketed upward so far in 2015. Today, the average senior E&P is trading at 8.8x cash flow. Just a few months ago, at the end of 2014, the multiple was as low as 5x.

In fact, average cash flow multiples across the senior space are currently near the highest levels we’ve seen over the past 10 years–much higher than the average multiple of 6x that’s prevailed since 2000.

To find a period of higher multiples investors have to go back to the salad days for the E&P sector in late 2007 and early 2008—when soaring oil prices created one of the most optimistic periods on record for energy investors.

The fact that we’re once again nearing the heady valuations of that time is concerning.

But cash flow multiples are just part of the story. When we look at the E&P sector using different valuation metrics, we get a completely different story—one that shows producers may be a good buy right now.

Look at a metric like price to net asset value (NAV), which measures a company’s trading worth relative not just to the profits it’s producing, but to the total assessed value of its in-ground oil and gas holdings.

BMO’s research shows that E&Ps are relatively cheap today compared to NAV. Remember that I said that cash flow multiples are going for an above-average 8.8x (as compared to an average of just 6x for the sector since 2000)? Well, when it comes to NAV the story is the opposite—E&Ps are selling for below average prices.

Valuations based on NAVs from 2014 reserves reports are right now averaging 0.9x for senior producers. And when we factor in current forward pricing for oil and gas, the multiple drops to 0.7x, according to BMO.

The really interesting thing is that the average price-to-NAV ratio since 2003 has been 0.85x for the senior sector. Meaning that at today’s pricing strip, producers are valued well below historic levels–almost 20%.

But wait… how is it possible that the E&P sector is trading at all-time high multiples to cash flow—and at the same time selling for record-low levels in relation to net asset value? Is it time to sell, or time to load up?

It turns out—it could be both. The short explanation being that, in today’s oil and gas sector, it’s critical to look at a range of data beyond just any one simple metric.

That’s because resource drilling plays have critically changed production and reserves profiles for North American E&Ps. Because shale gas and oil plays generally come with much longer—and often more predictable—reserve life than conventional reservoirs.

That means a shale well will usually provide cash flow for longer than a conventional well. And yet, this long life isn’t apparent if you simply look at a multiple to cash flow—which is basically a snapshot of just one moment in the life of a well (or a group of wells, in the case of a large company).

In order to detect the financial benefits that long-life reserves bring, it’s necessary to look at overall net asset value—where engineers predict the total life of a well, and then assess the value of that cash flow. If the well life is longer, the NAV is going to be higher.

This fact is already starting to percolate into the consciousness of energy analysts. AltaCorp Capital, for example, recently stated in a research report that “traditional ‘point -in-time’ multiples such as EV/DACF [enterprise value to discounted cash flow] do not capture decline profiles and underlying value” when it comes to today’s oil and gas fields.

The firm instead advocates looking at net asset value as a better way to assess E&Ps. And their findings jive with the numbers above—showing that 70% of the stocks in their coverage universe saw a contraction in trading multiples to NAV during 2014.

The firm pointed out that some stocks—such as Painted Pony (TSX: PPY), Rock Energy (TSX: RE) and Bonterra (TSX: BNE) have seen their multiples to NAV contract by over 20% during the past year. A fact that shows these stocks are getting cheaper relative to the value they hold.

Those sorts of numbers may be much more useful for investors today, as more-traditional metrics like cash flow multiples only giving an idea of relative valuations between stocks—but less of a picture of the general buy or sell signals for the sector as a whole.

This Play is Big. This Play is Timely. This Play is FREE

By
Keith Schaefer
-
0

One of the largest undeveloped shale plays in the world will get its First Big Test next month–June—the Beetaloo Basin in northern Australia.

It’s timely, it’s big, and for shareholders of Falcon Oil and Gas (FO-TSXv), it’s free.  CEO Philip O’Quigley (yes he lives in Ireland) has done a novel-worthy job of aligning everybody’s interests—royalty owners, shareholders, joint-venture partners—into a $200 million drill program that starts in less than 90 days.  And none of that money is being spent by Falcon.

In Part 1  I introduced you to Australia’s Beetaloo Basin which is a potential international horizontal play that contains a best estimate of 21.3 billion barrels of oil and 162 trillion feet of natural gas.

Falcon has a big piece of that massive prize.

Falcon is a registered holder of three Exploration Permits (EP76, EP98, EP117) that cover 4.6 million gross acres.  The land is located 600 kilometers south of Darwin Australia and is under explored.

1

Last May, Falcon announced a farm-out deal with not one, but two major oil and gas players.   The deal was stunningly attractive relative to other farm-outs I have seen done by junior companies of a size similar to Falcon.

The terms of the deal tell us a great deal about how the industry views the potential of the Beetaloo shale.   The quality of the partners that Falcon was able to attract tells us even more.

The farm-out involves Australia’s Origin Energy Limited and South Africa’s Sasol carrying Falcon in a nine well drilling program.  The total dollar value of the deal is an impressive $200 million with Falcon retaining a 30% ownership in the play and Origin and Sasol acquiring 35% each.

2

These companies are two fantastic partners for Falcon.

Sasol is a $30 billion plus company out of South Africa that brings not only horizontal drilling expertise but is a major LNG and gas to liquids player as well.

Origin Energy may not be as familiar to North American investors, but it is also a large company ($15 billion plus) and more importantly an Australian operator.   They don’t just know the local culture, they ARE the local culture for oil and gas.

Origin already operates a 3 million acre coal seam gas project in Queensland Australia with 14 trillion cubic feet of reserves which have required a $20 billion investment.

They know how to deal with the service companies and the governing bodies of the energy industry. Origin’s Australian connection can surely lead to better deals with service providers and fewer mistakes operationally.

Falcon got $20 million in cash up front in their JV with Origin and Sasol, and a $180 million commitment for a three phase work program.

What that means is that Falcon isn’t going to have to spend a dime over the course of this nine well program.

The first phase of the program involves 4 vertical wells (one of which will be fracked) and 1 horizontal (also to be fracked) and will cost roughly $64 million in Aussie dollars. And not only is Falcon carried on this phase, there is no cap on the estimated Phase 1 $64 million capex program.

Like with any farm-out, after that first phase Sasol and Origin have the option to walk away if they don’t like what they see.

If they choose to continue Phase 2 (with Falcon still being carried), it will involve a full 90 day production test on two fully fracked horizontal wells.  Phase 3 will consist of another two horizontal wells being drilled, fracked and production tested for 90 days.

As I covered in Part 1, the Beetaloo offers multiple stacked pay formations.  This $200 million program is going to focus on just one of those formations called the Middle Velkerri.  It is the biggest, thickest formation in the Beetaloo and has the most oil and gas resource in place.

For some perspective on the leverage Falcon’s 30% interest gives the company to this play we can compare the Beetaloo to the world’s two biggest horizontal plays (the Bakken and Eagle Ford).

3

Falcon’s 30% interest gives the company exposure to 1.38 million net acres of the Beetaloo.   1.38 million acres in the Bakken would give the company 17% of the entire Bakken play, in the Eagle Ford it would be 23%.

Non-producing acreage in the Bakken and Eagle Ford can be worth up to $20,000 per acre.  We have no idea if the Beetaloo is going to be commercially viable, but if it is and Falcon’s acreage is worth even a small percentage of what raw land goes for in the Bakken and Eagle Ford……

Hess And Seismic Mapping

I’ve sat down with O’Quigley several times and heard the story of how he was able to put this deal together.  Politics, grace and common business sense means the details can never be printed, but it involves flying around the globe multiple times, and being firm in your convictions.

O’Quigley was lucky because he never had to bluff.  The quality and size of the land base, and the ongoing LNG development just north of the Beetaloo were really all the carrots he needed.

O’Quigley started with the company a few years ago, when Hess (HES-NYSE) was their partner in the Beetaloo. In 2011 and 2012 Hess spent $80 million shooting the largest 2D seismic program in the history of Australia (3,490 km) on Falcon’s Beetaloo lands.

As part of this agreement Hess had the option (after shooting the seismic) to acquire a 65% interest in Falcon’s acreage.  But at the last minute, Hess asked for an extension on the deal so that it could bring in another partner.

O’Quigley and Falcon said no–a bold statement for a junior with an unproven property. Hess walked away.  So Falcon got $80 million worth of seismic for free.

There was a lot of second guessing of Falcon’s management between the time they declined the Hess request and the signing of the Sasol/Origin farm-out….but they been vindicated.

4

Falcon’s remarkable deal with Sasol and Origin didn’t do anything for the company’s stock last year.

The reason was that drilling was a full 12 months away—which is now.  In Part 1 of the Beetaloo, I explained that for six months of the year the acreage can’t be accessed.  November through April in this part of the world is wet, wet, wet.

So the three stage farm-out will take three years—but the first drilling starts in June this year.  After Phase 1, time needs to be taken to process the information gathered and make plans for Phase 2—the next year, after the next dry season comes around.

This $200 million program can’t all happen immediately, and that is why the market really didn’t care.

I’m not the most patient guy either, but the interest that the Big Boys have shown in this acreage has gotten my attention.  The stock has 912  million shares out trading at 10 cents, for a $91 million market cap, and $12 million cash.   Almost $80 million has been spent on the asset and they’re being carried for up to $180 million in new drilling.

And that drilling is starting now.  Often the first discovery creates the greatest lift in value. If this drilling program is successful in outlining a huge onshore resource for Australian LNG, Falcon may not be around to see Phase 2.

Keith Schaefer

 

The Market has Waited 3 Years to See This Drilled

By
Keith Schaefer
-
0

The Shale Revolution is strictly a North American game.  Before the Great Commodity Collapse of 2014, it really never found its footing anywhere else in the world.

Of all the plays I looked and of the few I covered, only one showed any real promise—the Vaca Muerta oil play in western Argentina.

I’m now making that TWO plays—after researching the Beetaloo Basin in north-central Australia.

Northern Australia has just gone through the most focused Liquid Natural Gas (LNG) development the world has ever experienced, and is set to become the world’s largest exporter of LNG in the next two years—from basically zero.

As an example, France’s Total and Japan’s INPEX are investing $34 Billion in LNG in Darwin for two LNG facilities.  The feedstock for those facilities is 890 km offshore.

 1

So I found it really interesting that INPEX just picked up 2.4 million acres in the Beetaloo.  They must commit to a work program, and INPEX hasn’t said what it is yet.  But the point is there is now some well-funded, large international companies about to spend millions in some promising virgin geology.

All the infrastructure to process trillions of feet of cubic gas is already built; and a gas pipeline already goes through the Beetaloo up to Darwin.  That is key.  Oil infrastructure however would definitely cost more.

2

Natural gas prices in Asia—like the JKM benchmark—have come down a lot, but the Aussie LNG industry says their LNG is economic at $40 oil.  LNG is generally priced about 13-15% of Brent oil.

And I absolutely love that I get to watch this play unfold during the commodity collapse—because it means I get to watch for free.  There is no speculative premium in any play or stock, and the fundamentals here are very intriguing.

The Beetaloo reminds me a lot of the Permian Basin in west Texas—the granddaddy of oil plays in North America.

Any new horizontal play in today’s world must have stackedpay formations.  What stacked pay means is that there are multiple productive oil and gas formations on the same piece of land.  One well bore can pass through several formations.

It is common sense really.  Once you spend the money to build the roads, lay the pipelines and establish the drilling site to develop one productive zone, you can re-use all of that again to develop the other zones.

That means cost per barrel of production goes way down, and profits go way up.

It is that stacked formations that exist in the Permian Basin in Texas that  made it the hottest oil and gas area in the United States.  During the height of the boom last year, there were more rigs drilling in the Permian than anywhere else on the planet.

Like the Permian, the Beetaloo has several different formations with potential.

3

Having stacked pay doesn’t mean every formation will flow hydrocarbons, but it does offer the potential that oil and gas producers are interested in.

Given the multiple formations, the amount of oil and gas in the ground in the Beetaloo is big–Really Big.  With today’s energy pricing, you need Really Big to create economies of scale to make money.

According to the work done by reservoir engineers at RPS in 2013, the best case hydrocarbon resource in the Beetaloo Basin is 21.3 billion barrels of oil and 162 trillion cubic feet of natural gas.

The Beetaloo has pay zones for both shallower oil and deeper gas:

Shale oil –  Upper Kyalla, Lower Kyalla and Middle Velkerri

Shale gas – Lower Kyalla and Middle Velkerri

Tight gas – Moroak and Bessie Creek

4

The Beetaloo has been drilled vertically before—in the 1980s by Rio Tinto—and RPS used that core data (12 wells) to come up with that estimate.

Of course, there are still some Big Challenges operating in Northern Australia.  This is a remote frontier.

One such challenge will be the weather.  In this region you have 6 dry months where conditions are excellent (May to October) and 6 wet months where you aren’t going to be able to get anything done (November to April).  When the calendar hits October it will be crucial to get equipment out of the region or risk paying for it to sit idle for the rainy months.

Another challenge is a lack of infrastructure.  There is a pipeline there, but supporting a drilling and fracking operation 600 km away from any mechanical centre is difficult.  In Alberta or Texas, a missing or broken part is usually replaced the same or next day.

Rig repairs could realistically be a couple weeks in Northern Australia.

Developing the horizontal/unconventional part of the play is more expensive but less risky–because it doesn’t carry the exploration risk that a conventional drilling target does.   When you drill a conventional target (I’m talking about the oil pools everybody searched for only 10-15 years ago ;-)), there is always a chance that the hydrocarbons have migrated out of the structure.

With an unconventional play companies know that the resource is there, the only question is whether they can get it out profitably.

Down the road, companies operating in the Beetaloo might get a second life by going after the conventional opportunities.

This play has the ingredients that could turn it into a major international horizontal play.

It’s a huge play, and not a place you would expect to find a small company highly levered to succeed there.  But there is one, and they have arranged all the pieces of the puzzle so that their Big Partners are paying ALL the freight.  I like that.  Drilling starts next month; I like that even more.  I’ll get into that in Part Two of my look at the Beetaloo Basin.

-Keith

 

U.S. Oil Market Update- Blame Canada!

By
Keith Schaefer
-
0

By Nathan Weiss and Keith Schaefer

Where is all the oil coming from?  

Oil inventories continue to surge, but U.S. production has flatlined for weeks—even months.

I mean really—look at these simple facts that have been staring the Market in the face for months:

  1. Year-to-date (YTD) production in 2015 in the U.S. is only 160,000 bopd (barrels of oil per day) above December levels—multiply that by 7 days a week to get 1.12 million barrels a week.
  2. Demand in the U.S. is up by A LOT more—depending on which analysts/firm you want to believe—just under 800,000 bopd.  Refineries are running at record high through puts just to keep up (92.3% now vs. 5-yr average of 87.8%)!

Yet U.S. oil inventories continue to climb—by a stunning 6.54 million barrels a week so far this year—almost 300% over the typical December-May 1.71 million barrels per week.  So U.S. production YTD only accounts for 17% of this.  What gives?

This huge growth in inventories has caused some high profile analysts to call for $20 oil.  The idea of oil storage becoming full in the U.S. caused a second big downleg in March in WTI prices—set in Cushing OK—to a low of $42/barrel.

The reason behind this seeming paradox?  When you look at the data, the creators of South Park got it right – we should really ‘Blame Canada!’

Two new pipelines recently debottleneck crude flows from Canada to the Gulf of Mexico, resulting in a 13.99% increase (408,000 bopd) in U.S. crude oil imports from Canada in December (2.86 million additional barrels per week) that has largely been maintained.  When you contrast that fact to the US oil inventory build in the first chart below—well, that’s almost all  you need to know.

The vast majority of Canadian oil exports is heavy oil from the oilsands.  While shale production—light oil—begins to stall and fade, oilsands production will increase every year for at least the next five years.  Growing production and heavy discounts (pun intended) will keep U.S. refiners processing all the Canadian heavy oil—called Western Canada Select, or WCS—they can.

Even worse, crude oil imports are increasing as East and West coast refiners increase utilization, requiring them to consume additional seaborne crude (from Saudi Arabia and other places) in order to maintain their crude input blend slate: As U.S. refinery utilization increased from 89% to 92% over the past four weeks, total U.S. crude oil imports have averaged 7.56 million bopd, well above the YTD average of 7.26 million bopd and the March average of 7.25 million bopd.

Unless U.S. shale production falls dramatically (and soon), the U.S. crude inventory situation could get very ugly this summer as 1-3 million weekly builds continue – just as investors have written off full inventories as a risk factor!

The Development of U.S. Crude Oil Inventories 

Analysts generally blame a surge in domestic crude oil production or reduced crude oil refinery utilization for the sharp growth in U.S. inventories over the past three months. Others hold onto various conspiracy theories, including the belief Saudi Arabia is intentionally stuffing crude oil (from various countries) into Gulf Coast storage facilities in order to drive down WTI crude prices and spare Brent pricing.

Before we truly “Blame Canada!” let’s put those theories to bed first: See this chart of U.S. crude oil inventories (DOESCRUD <Index> on Bloomberg), which clearly shows the surge began in early January:

oil sands production 1

Rebasing the above chart to show the seasonality of inventories over the past five years (see below), shows that on average, U.S. crude oil inventories grow by a total of 36 million barrels (1.71 million barrels per week) from the end of December through the end of May.

So far in 2015, inventories have increased by a stunning 98.23 million barrels (6.54 million barrels per week) and unless U.S. shale production falls off a cliff in the next 3-5 weeks, are on track to grow by a further 20+ million barrels by the end of May!

oil sands 2

Is Surging U.S. Production to Blame?

The previous crude oil inventory  charts show something clearly changed at the beginning of the year.  While many  blame surging U.S. crude oil production,  the  official  EIA monthly  data  shows production  increased from 9.11 million bopd in November to 9.32 million bopd in December, before declining to 9.19 million bopd in January.

The EIA’s Weekly Petroleum Status Reports estimate  U.S. crude oil production  increased from 9.06 million bopd in November to 9.13 million bopd in December, 9.19 million bopd in January, 9.28 million bopd in February and 9.39 million bopd in March – as the following chart from Bloomberg shows (DOETCRUD <Index>):

oil sands 3

The continued growth in U.S. crude oil production isn’t surprising given the lag between drilling activity and first production.  The DOE weekly crude oil production data shows production has increased 0.26 million bopd since December.

More importantly, year-to-date production has only averaged 0.16 million bopd above December levels – an increase of just 1.12 million barrels per week. This says two things: First, the average increase in U.S. crude oil production year-to-date accounts for only 17% of the 6.54 million barrel per week average increase in inventories.

Second–unless U.S. light oil production growth falls dramatically–and soon–weekly inventory builds should be increasing.

Refinery Utilization is Seasonally High 

Low crude oil refinery utilization is another commonly-cited reason for rising crude inventories, but in reality refinery utilization (DOEPPERC <Index> on Bloomberg) sits at 92.3% compared to an average of 90.2% for all of 2014 and an average of just 87.8% over the past five years.

If we look at the seasonality of refinery utilization, we find the current utilization rate is a stunning 6.8% above the five year average of 85.3% for this week in April. Despite what is reported in the media, since November U.S. crude oil refineries have regularly been running at the highest utilization rates in more than five years, as the following chart shows:

oil sands 4

If refinery runs revert to the mean, it would mean a big jump in inventories. All this means analysts are now potentially under-estimating the risk U.S. crude inventories will continue to grow through the summer.

Look at the calculations: U.S. crude oil refining capacity, as reported by the DOE, is 17.89 million bopd.  The current refinery utilization rate of 92.3% equates to 16.51 million bopd of total throughput.  If refinery utilization increases to 94% this summer, roughly 1.0% above peak summer utilization rates of the past five years, total refinery throughput will increase by 0.30 million bopd (to 16.81 million bopd).

Even with the resulting increase in crude oil demand (+2.13 million barrels per week), U.S. light oil production would have to collapse or else crude oil inventories could continue to increase one to three million barrels per week during the peak refining season!

This is exactly what happened in December when U.S. refinery utilization rocketed to almost all-time highs (an unbelievable 94.2% for the month of December—traditionally the LOWEST time of year) as refiners took advantage of newly increased flow of cheap Canadian crude and built refined product inventories.

U.S. Crude Oil Imports from Canada (finally–BLAME CANADA!)

As mentioned in the intro–two new pipelines recently debottleneck crude flows to the Gulf of Mexico from Canada: Enbridge’s 600,000 bopd Illinois-to-Oklahoma Flanagan South pipeline and Enterprise Products Partners’ 450,000 bopd Oklahoma-to-Texas Seaway Twin.

While the Texas Seaway Twin pipeline was technically operational in October, the December start-up of the Flanagan South pipeline was necessary to feed it Canadian crude. Together these two new pipelines led to a 13.99% increase (408,000 bopd) in U.S. crude oil imports from Canada (DOCRCANA <Index>) in December (2.86 million additional barrels per week), as the following chart shows:

oil sands 5

A 2.86 million barrel per week increase in crude oil imports from Canada accounts for 44.7% of the 6.54 million barrel per week growth in U.S. crude oil inventories so far this year. This is by far the largest single factor driving the sharp increase in inventories, yet it is rarely reported as the cause by the media or analysts.

The Outlook for Canadian Crude Oil Production 

With WTI crude priced at $55.00 per barrel and Canadian heavy crude (WCS) priced $12.00 per barrel below WTI, it is easy to see why Gulf Coast refiners welcome all the Canadian heavy crude they can process – but how will Canadian crude oil producers respond to the current price environment?

Most of Canada’s production is heavy oil from the oilsands in Alberta. BMO Nesbitt Burns, Canada’s 2nd largest retail brokerage firm, says that despite a sharp drop in spending, they expect oil sands production to grow roughly 10% in 2015 to 2.4 million bopd as several new start-ups come on line.

And with break-even costs of $25/barrel for in-situ producers, that growth is not threatened.

oil sands 6

Canada’s National Energy Board (NEB) is calling for Canadian crude oil production to increase from 3.76 million bopd in 2014 (3.91 million bopd in December) to 3.89 million bopd in 2015, while OPEC is expecting Canadian production to increase by only 20,000 bopd in 2015.

First Energy suggests that overall Canadian oil production will continue to rise even with a decline in light oil production:

canada 7

A wide array of Canadian production forecasts from Wall Street analysts effectively predict production will be flat.  This is what overall Canadian oil production looks like in the last three years:

canada 8

Conclusions 

Oil prices have rallied the past few weeks as investors believe (for various reasons) the worst of the U.S. inventory builds are behind U.S. That’s true, but it’s still unclear how much U.S. crude oil production will decline or that refiners will be able to consume all of the crude available this summer.

But Canada’s oil supply continues to increase, and more of it is finding a way into the U.S. As a result, U.S. crude oil inventory builds could continue through the peak summer refining season – possibly at a rate of 1-3 million barrels per week.

This negative surprise could lead to another leg down in crude prices (particularly WTI) as investors (eventually) realize just how oversupplied the North American market is.

Even worse, crude oil imports are increasing as East and West coast refiners increase utilization, requiring them to consume additional seaborne crude in order to maintain their crude input blend slate: As U.S. refinery utilization increased from 89% to 92% over the past four weeks, total U.S. crude oil imports (DOEICESP <Index> on Bloomberg) have averaged 7.56 million bopd, well above the YTD average of 7.26 million bopd and the March average of 7.25 million bopd.

The U.S. crude inventory situation could get very ugly this Summer – just as investors have written off full inventories as a risk factor!

And you can Blame Canada!

(SouthPark’s (very) off-colour sketch by the same name can be found here–http://bit.ly/BlameCanada1)

EDITORS NOTE:  If this scenario plays out this summer, refinery stocks will benefit the most.  They are very profitable right now.  Click HERE to understand the profit potential for my two favourite refinery stocks.

-Keith

The Big Opportunity in US Energy Right Now–and Why

By
Keith Schaefer
-
0

Logistics are a bigger piece of the energy pie than ever before—especially rail.  Most energy investors are familiar now with the huge rise in crude-by-rail; getting Canadian and Bakken crude to the east and west coast refineries in the United States.

It saved the profit margins for many oil producers, and allowed them to choose from more customers (refineries)  that many chose to continue railing crude even when pipelines became available.

Logistics made me and my subscribers huge money in 2014 as there wasn’t enough rail capacity to get ethanol to markets during the Polar Vortex that year—especially along the west coast.  Profit margins for ethanol producers soared from 20 cents a gallon to over $2 a gallon in four months, causing ethanol stocks to go up 200-800%.

This year I think logistics can make investors a lot of money in another energy sector: frac sand.

Demand—and therefore pricing pressure—for frac sand has declined the least among the OFS—OilField Services sub-sectors.   Pricing is dropping 5-20%, depending on which analyst you want to believe.

But the frac sand market is still tight for Tier 1 sand or white sand–the best sand.  It’s the lower grades that have been hardest hit.  Analysts are projecting a continued tight market for Tier 1 sand in the United States as all the producers still drilling  believe the lower rig counts mean they can use Tier 1 frac sand.

Wisconsin—a northern state that borders Lake Superior—holds almost all the Tier 1 frac sand in the USA.  This adds huge cost to get the best frac sand south to Texas to the Permian and the Eagle Ford plays.

And despite the downturn in rig counts, there are a lot of Drilled-but-UnCompleted wells (the industry calls them DUCs) that will get fracked before the rig count turns up.  That will keep frac sand pricing well ahead of other service sub-sectors.

A March 13 2015 report by RBC Dominion’s Houston office (they’re the largest Canadian retail brokerage firm) shows that at December 31 2014, there was over 4000 wells drilled and waiting to be fracked in the USA:

Permian Basin                     1100 wells
Eagle Ford                            1750 wells
Williston (Bakken)              800 wells
Wattenberg (CO)               600 wells

1

Source: RBC Capital Markets March 13 2015 Oil Shale Well Backlog Analysis

2

Source: RBC Capital Markets March 13 2015 Oil Shale Well Backlog Analysis

That’s why even in the face of the oil and gas downturn, everybody is trying to control more frac sand—the producers, the frac sand specialist suppliers (think Emerge (EMES-NYSE), US Silica (SLCA-NYSE) and Hi-Crush (HCLP-NYSE)), and the Big 3 service companies—Halliburton (HAL-NYSE), Schlumberger (SLB-NYSE) and Weatherford (WFT-NYSE)

Frac sand per well is increasing so much that even with a big drop in the number of wells being drilled in 2015, overall frac sand use is expected to only be down 15-20%.  And most of that is the lower quality sand.

Even as the oil price was collapsing, the major energy services companies had some eye opening data about how much frac sand (proppant) the industry is using.

Halliburton CEO Dave Lesar disclosed that the average amount of sand being consumed per horizontal well has surged 50% year on year.

I knew the “more sand is better” trend—I wrote about it when Whiting and EOG both said they were getting greatly increased flow rates from their wells by using tightly spaced short wide fracks instead of long skinny ones.

But the fact that the entire industry is—on average—using 50% more proppant year on year really blew me away.

It has become crystal clear that the industry has discovered that the cost of using more sand is more than justified by the increase in flow rates that are the result.  And according to Halliburton’s Lesar—the upper boundaries of how much sand is optimal are still being defined.

For the big service players like Halliburton and Baker Hughes (Hallibaker?) this big increase in sand consumption has fundamentally changed their business.  It is both a huge opportunity and a huge challenge.

The speed of the increase has the service companies scrambling to secure enough sand and to have the ability to transport it to the well sites in a timely fashion.

Late last year both Halliburton and Baker Hughes noted that each had experienced some disruptions in having the sand at the well site on a timely basis.  Halliburton in particular went out of their way to tell the market they plan to vertically integrate the frac sand supply chain right from the mine on through to the well site.

Halliburton alone has more than doubled its sand-storage capacity at its shale play terminal, is on track to double its rail car fleet and has cut 30 deals with trucking companies for additional transport capacity.  The company has even started a “sand-logistics” command centre to monitor sand supply levels in the various US basins.

That is how vital frac sand is to this industry.

The amount of sand that is being used in each and every well is a bit hard to comprehend.

Halliburton CFO Mike McCollum indicated that one year ago it was taking 20 rail cars of sand to do one frack job and that today that number has increased to 75.  For some perspective, that means that each frac job has gone from consuming 4 million pounds to 15 million pounds of sand.  It literally takes an entire train load to frack one well.

You can see how this increase is causing all kinds of logistical headaches for the service companies.

Fracking involves injecting highly pressurized water into the horizontal well which cracks the oil bearing rocks—creating fractures—allowing oil and gas to seep out.  The frac sand gets lodged in these cracks and pores keeping them “propped” open so that as much oil and gas as possible escapes into the well.

Recent history is clear: more and more proppant is resulting in higher and higher flow rates.  These higher flow rates have more than offset the additional frac sand cost resulting in better return on capital invested.

Even with lower crude prices, frac sand is one expense that the oil producers will not be skimping on—it’s the key ingredient in creating the highest flow rates per well and therefore the key to profitability.

Now back to logistics—interestingly, the sand itself is less than half the cost to the producer.  Transportation costs and logistics are more important—as much as two-thirds the cost of their end-price.

And because most of the good quality sand is up north in Wisconsin,  producers in Oklahoma (Fayatteville shale), Louisiana (Haynesville Shale) and Texas (Barnett, Permian and Eagle Ford) producers are desperate to find a large Tier One frac sand deposit much closer to home.

Here’s a quick look at how the final frac sand price breaks down for producers:

3

So when a producer pays $180/ton for sand, only about $60 of that is the sand itself.  Over half is transportation.

Even with the drilling downturn, the industry desire to control more of the value chain around frac sand is continuing.  And the Market wants more sand closer to Texas.

That combination makes me very intrigued about one completely off-the-radar  company that is now proving up a key source of Tier One frack sand right next door to America’s most active horizontal plays. 

They’re very close to rail, and would have HALF the transportation cost to Texas and Louisiana. If you are thinking that a company like that could be a tempting takeover target….you would be right!

I’ll introduce you to that company next time….

Keith Schaefer

 

Bakken Oil Production Is Already Declining, But is it about to Crash?

By
Keith Schaefer
-
0

Bakken oil production has already declined in 2015.  There is compelling evidence that this decline is going to accelerate significantly in the next couple of months.

If that happens the recovery we have seen in oil prices in recent weeks is also going accelerate.

Being as the market likes the fact that U.S. production growth appears to have already halted, it will be thrilled to see production start to unexpectedly decline.

These are the numbers nobody is talking about even though they should be.

Drilling Into The Data

bakken monthly

Source of data: https://www.dmr.nd.gov/oilgas/stats/statisticsvw.asp

The chart above shows average daily North Dakota state production over the last six months as provided by the North Dakota DMR.

February 2015 production of 1,177,094 barrels per day was below the September 2014 level of 1,186,355 barrels per day and considerably less than December 2014’s 1,227,529 barrels per day.

Six months ago you wouldn’t have found anyone who would have believed that North Dakota production would be flat in the subsequent six months.

There is now reason to believe that six months from now North Dakota production will have experienced a much more significant decline.

Let’s follow the numbers.

It is generally accepted that there is roughly a three month delay between the time a horizontal well is drilled and when it starts producing.  The lag is due to the fact that each horizontal well also has to be fracked and then tied into pipelines.

Continental Resources (CLR-NYSE) CEO Harold Hamm referred to this three month lag in his recent appearance on CNBC.

That means that North Dakota (essentially Bakken) production in the first quarter of 2015 was influenced by the drilling rig activity in the final quarter of 2014.

Here is what that rig count looked like (again from the North Dakota DMR):

industrial commission

The average rig count on the far right is useful, but the number of “spuds” (new wells commenced) is even better.

The average spud count per quarter in 2014 was as follows:

Spuds Q1 2014 – 211

Spuds Q2 2014 – 217

Spuds Q3 2014 – 237

Spuds Q4 2014 – 208

The number of new spuds on a monthly basis stayed above 210 for all of 2014 until December.  While that spud count was above 210 North Dakota production kept growing.

But in Q1 2015 that production growth ended.  In fact production declined following the slightly reduced rate of drilling at the end of 2014.

Now have a look at the number wells spudded so far in 2015:

industrial commission 2

Even in January the spud count was as high as 186.  February was down a lot more at 142 and March (unofficial) further still at 125.

Remember that there is unquestionably a lag between wells being drilled and put on production.  The impact of these first quarter spud count is going to show up in April, May and June.

That spud count on average in Q1 based on those DMR numbers is 151.   That is considerably lower than the average Q4 spud count of 208 which produced slowly declining Q1 production.

What are we going to see in the coming months with the reduced Q1 number of spuds?  Answer: Even lower production.

Now there are a lot of variables involved here–including whether a drilled well has actually been completed and put on production.  There are companies that have drilled wells but have chosen to not spend the money to frack them until oil prices improve.

But consider this.

The current rig count in North Dakota is now all the way down to 88.  We have seen a decline in North Dakota production with rig counts of twice that level.  Even in January the rig count still averaged 188.

If North Dakota production was declining with 188 rigs in action doesn’t it make sense that the rate of decline is going to increase further with the rig count and number of wells at less than half that level?

What is happening in the Bakken and North Dakota is not unique to that area.  The same trends are being seen in the Eagle Ford and the Permian.  The Permian rig count was slower than the Bakken to drop, so the impact there may be a little later.

The flattening of U.S. production was enough to get a bid under WTI prices (a bigger bid than I expected this fast).  If the market gets a whiff of these shale plays heading into actual decline already the price of WTI could really catch a bid.

If it does, you are going to want to know which oil stocks to own.  Fortunately I’ve already done the heavy lifting for you.  Access The Only Three Oil Stock Reports you’ll ever need:

Report #1 – What to Buy if Oil is $50/barrel – The Top 3 Defensive Names

Report #2 – What to Buy if Oil is $65-$70/barrel – The Junior Leaders Who Outperform

and if my thesis on North Dakota production is right, this is report you want to read right now:

Report #3 – What to Buy if Oil is $75+/barrel – The Tier 2 Stocks With Great Leverage to Oil

Prosperity is about Peace, not Worry.  You can have peace knowing what stocks to buy when-–Click HERE to stop worrying and working so hard to make money.

Keith Schaefer

 

1...585960...119Page 59 of 119
© Copyright 2023 - Profit Prospects
Powered by  GDPR Cookie Compliance
Privacy Overview

This website uses cookies so that we can provide you with the best user experience possible. Cookie information is stored in your browser and performs functions such as recognising you when you return to our website and helping our team to understand which sections of the website you find most interesting and useful.