A New Industry Was Born Today–and so far it’s a Monopoly

By
Keith Schaefer
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0

There is a multi-billion dollar problem in the oil patch just looking for a solution—get oil to flow better along the horizontal leg of a well.

A small Canadian company called Raise Production Inc. (RPC-TSXv; GLKFF-PINK) thinks it may have the answer.

They have developed a way to place many small motors down the horizontal leg of a well bore and have them fire in parallel—that means right after each along the well—creating multiple draw down points for oil to be hurried along the well to the vertical part of the well bore.

This beta technology is not yet commercial, but on April 10 they announced their first test well increased production by 300%, and the stock has moved 100% today—a double. The Market believes it will work.

They’ve created an entire new industry—horizontal leg engineering. There is reservoir engineering, and now this. This management team had an idea that oil reservoirs are all very different, and should not decline at the same rate. They assumed that the reason most decline rates are so similar is because of a mechanical issue in the horizontal leg.

And they believed they could fix that. Their little motor system appears does that.

The potential is enormous. Over the next three to five years there will be 26,000 horizontal oil wells drilled in the United States alone just to meet the drilling requirements of land leases.

In the five years that follow that, the energy industry is still going to be making “swiss cheese” of the North American landscape drilling thousands of wells.

There are billions and billions of barrels in the ground in these horizontal plays that we still can’t get at with the current methods of horizontal drilling.

Five years ago this horizontal drilling revolution was barely on anyone’s radar. Today millions and millions of barrels of oil are being produced from horizontal wells.
Precipitous Decline Curves – The Curse Of Horizontal Oil Production

At this point everyone knows about the horizontal oil boom that has transformed North American oil production. But North American horizontal oil wells today likely needs an oil price of $85 or higher to generate any positive return.

What makes these horizontal oil wells require such high oil prices is their production profile. The current nature of a horizontal oil well is an initial surge of “flush” production. That flush production is followed by a first year decline curve that is incredibly steep.

yearly decline

 

The major horizontal oil fields in Canada and the United States all have similarly high rates of first year declines:

horizontal flow

 

Every one of the major oil fields in North America loses more than half of their initial rate of production after just one year.

Compare that to a vertical oil well that is drilled into a conventional reservoir. Those wells decline at much slower rates which allows for much stronger cash flow for a longer period of time.

The solution proposed by Raise Production could turn the decline curve of a horizontal well into something that looks more like a conventional vertical well.

Any decrease in the rate of decline would increase the return on capital invested drilling a well. It would mean that every single horizontal well that is drilled going forward using this technology would make more money for the driller than it would without it.

Such a significant increase in the rate of decline would mean tens of billions of dollars of value to the energy industry.

Therefore, a patented solution that significantly changes the decline curve on horizontal oil production would also be worth billions.

Raise Production Inc’s Novel Production Management System

Raise Production believes that problem with horizontal wells that creates the steep declines is the lack of flow management. A horizontal well goes straight down vertically and, over quite a distance, turns at a right angle and continues straight sideways.

Raise Production’s technology aims move oil along the horizontal section of the well much better to the vertical section where it is “lifted” to the surface.

horizontal flow

According Raise Production current horizontal wells suffer from the following:
  •        Isolation of the oil at the toe (the far end) of the horizontal well
  •        An increase in gas to oil ratios
  •        Inefficient mobilization of fluids
Raise Production’s patented technology addresses these challenges.

The Raise Production system is designed to go to work in the horizontal section of the wellbore.  The system places multiple pumps along the horizontal section of the well.

The system “sweeps” the oil along the horizontal section of the well and toward the vertical section.   This helps the oil reach a point where the normal artificial lift in the vertical portion of the well can influence the flow of oil to the surface.

The result of all of this should be that more oil gets to the vertical section of the well, and oil that would have eventually gotten there on its own arrives faster.

More oil sooner equals higher profit per well and higher rates of production.
First Field Testing Is Complete

Raise Production has spent two and a half years and lots of blood, sweat and tears developing the system.

The company has gone from the conceptual design phase, to industry focus groups, to detailed design, to securing patent protection and finally construction of a proto-type.

All of that work culminated last August with the deployment of the first proto-type system into the field.

On October 21 of last year Raise announced the completion of that initial 60 day field test.

The company was pleased with the results which indicated that the system worked as designed, is stable and that it can have a meaningful impact on horizontal flow.

Raise also announced that through the testing some additional things were learned that can lead to improvements in the system and additional patents.

Based on the results of this field test Raise and its industry partner agreed to try a second deployment of the system at the end of November on the same wellbore.

Those next set of test results were announced last night from a well in the Viking play in Saskatchewan—and showed increases in well bore production of 300%

If this second field test also yields positive results Raise intends to roll out a commercial version of the system in the Viking light oil play in 2014.

The potential is huge, but it’s early, early days. But the Market believes.

DISCLOSURE–I do not own this stock.

PS–Global Cooling Part III is coming Monday!

PPS–The OGIB rate increase happens on April 23–beat the rush and save money! http://oilandgas-investments.com/subscribe-here/

What’s The Bright Spot for Investors in Global Cooling? Part II

By
Keith Schaefer
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0

Part I of this series is here.

If history is any guide, the world will continue its current 15 year cooling trend for another 20 years potentially.  In fact, there is a good chance the earth is about to go into one of its coolest periods in the last 250 years.

In a new report by Boston-based Unit Economics, they explain how sunspot activity is the key to understanding earth’s temperature.   Sunspots have very predictable and accurate cycles.   The last sunspot peak was March 2000 in the sunspot cycle that ended in 2008.

CRU global temperatue
What does near term global cooling mean for energy investors?  Among other potential trades, CEO Nathan Weiss suggests grain crops for the next two years should provide bumper harvests, keeping supplies high and prices low—which is great news for ethanol stocks. (Yes I am long ethanol ;-))Unit Economics says the best way to assess solar activity is through sunspot activity.  (I’m going to get a little technical here so you may have to re-read a couple paragraphs.)The sun is a ball of circulating plasma. Sometimes the circulations become so energetic that plasma escapes, ejecting out into space, where it cools rapidly and is pulled back by the sun’s gravitational pull.

From earth, the cooler returning plasma appears darker than the rest of the sun, creating a sunspot. And the more active the sun, the more frequent its spots.

A more active sun also has another important characteristic: a stronger magnetic field.

Grade 9 science shows that a magnetic field forms when electricity runs through the coils of an electric motor.  Well, in the same way, the circulation of charged plasma creates a magnetic field around the sun. When those circulations ramp up, the magnetic field strengthens.

A stronger magnetic field means fewer particles from outside our solar system (cosmic rays)  make it to earth. However, that actually makes for a warmer world.

The reason is clouds. Cosmic ray particles  actually seed cloud formation. When the sun is not very active, lots of particles penetrate its relatively weak magnetic field and make it to earth. Those particles seed lots of clouds, creating a cloud layer that reflects the barrage of particles back into space.

Of the solar energy that reaches (and warms) our atmosphere, about 30% are reflected right back into space, largely thanks to clouds. Thus the cloudier it is, the colder our world.

When the sun is active (more sunspots) and its magnetic field strong, fewer cosmic ray  particles means less cloud cover and a warmer planet.

That’s the theory – and the data backs it up.  Look at these three charts:

 400 years sunspot
 temp solar radiation
 sunspots counts
It seems clear solar activity plays a major role in global temperatures.But the best news is yet to come: solar activity follows surprisingly stable – and thus predictable – cycles. The shortest solar cycle averages 11 years in length. Other concurrent cycles have durations of 22, 53, 88, 106, 213, and 420 years.Cycles also vary in intensity. Shorter cycles are more intense. That’s because total solar electromagnetic output is pretty consistent from one cycle to the next, and so  shorter cycles have higher peaks.

Combining these cycles and their intensities, scientists created a model of solar activity that fits historic sunspot observations quite well – and tells us what to expect from the sun in the future.

The bottom line is that the current lull in solar activity is highly likely to persist for another 19 years. Yup, lots of cosmic particles will create lots of clouds and keep the earth cool for the next two decades.

Moreover, we are going through one of the quietest periods of solar activity in known history – and it may well herald another Dalton Minimum—the sunspot low of the last 1000 years from 1650-1850 that is the reason we have  all the paintings of skating on the River Thames in London England.

Remember that long solar cycles are much less intense than short ones. Scientists time cycles from trough to trough, so a new cycle starts when solar activity begins increasing after years of decline. The duration of the decline – the time from peak to trough – gives good hints as to the nature of the next cycle.

Solar cycles that don’t get underway until more than 92 months after the previous peak reach less than half the intensity of those that kick off before 92 months have passed. Delayed cycles are also much longer. The current cycle, dubbed Solar Cycle 24, did not really get going until early 2010 – 126 months after the peak of Solar Cycle 23.

The weakest solar cycle of modern times was Cycle 5, which lasted from 1796 to 1830—that was the  Dalton Minimum.  Temperatures were a full 2 degrees lower than average and history books talk of summers that never arrived. Solar Cycle 5 started 123 months after the peak of Solar Cycle 4.

The sun is also very quiet these days. We are supposed to be in the midst of an upswing in solar activity but the best guess puts the peak of Solar Cycle 24 at between 33.75 and 40.5 sunspots per year (after accounting for our ever-increasing ability to detect sunspots today compared to two hundred years ago). Solar Cycle 5 peaked at 49.2 sunspots.

As NASA solar physicist David Hathaway puts it, describing the great plasma conveyor belt of the sun: “It’s off the bottom of the charts… We’ve never seen speeds so low.”

BOTTOM LINE–Sunspot activity is suggesting we are moving into a time of lower temperatures on Earth this solar cycle.  (You can see the times of the sunspot cycles here: http://en.wikipedia.org/wiki/List_of_solar_cycles)

There are two intriguing investment implications from this sunspot theory. Grain production is obviously impacted by weather and climate.  The world is now into Year 7 of the current sunspot cycle.  In a statistical review of grain prices in the last few solar cycles, Unit Economics found that Year 4–2011–was the peak for grain prices.  Corn was up 57% that year and wheat was up 21%.

But this year–2014–should be the top growing year for these crops; bumper harvests are to be expected, keeping agricultural commodity prices low.    This should be continued good news for US ethanol producers–Green Plains Renewable Energy (GPRE-NASD), Pacific Ethanol (PEIX-NASD), and REX American Resources (REX-NYSE).   They already have great stock charts.

(In the long run (five or so years out) – shorter growing seasons resulting from colder weather will send grain prices higher)

The second bit of data crunching Unit Economics did was much more macro-oriented.  In simplistic terms, when temperatures
decline by 0.25 degrees Celsius in a year vs. the 5 year rolling trend, the stock market generally declines.  And the opposite holds true: when temperatures increase by 0.25 degrees against the trend, market action is positive.

Wait, you say. All of this seems to make sense…but what about everything I’ve hear for the last 20 years about our warming planet?

Manmade climate change theories and solar activity can co-exist!  Weak solar activity can overwhelm long-term trends and result in cooler weather for the next two decades, even if man is warming the Earth.  You may change your mind about ‘Climate Change,’ however, when you read Part III.

Global Cooling– The REAL Inconvenient Truth: Part 1

By
Keith Schaefer
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0

Three months ago, it snowed in Cairo, Egypt for the first time in 112 years.

2013 was the largest one-year temperature drop ever recorded in the United States.

The extent of the Antarctic sea ice is at record highs.

Global Cooling--snow in Cairo

It’s the Real Inconvenient Truth—right now the world is getting colder.  And it’s likely to get even colder for the next 20 years—before a new, stronger cycle of sunspots begins, as they have for eons.  They are statistically very, VERY accurate.

But there’s more, and it’s A Sad Truth: there is ample evidence that suggests private scientists and public servants have been manipulating the basic raw data that most everyone relies on to calculate climate change.  (This story has great timing as the IPCC–International Panel on Climate Change–just released Part 5 of their most recent major assessment on climate science (even they can’t bring themselves to call it Global Warming anymore).)

There are some investment trends that come out of this new Truth, and some of it is as simple as get long snowmobile makers and get short lawn mowers.  One trend is that Global Cooling should bring more seasonality in oil and gas prices, making energy ETF and commodity traders happy.

All of this is part of a new ground-breaking study completed by Unit Economics, an investment think-tank from Boston.  They are a non-partisan group with no axe to grind on this issue; like me, they are here to make money for their clients.  Show us a trend and we’ll figure out how to profit from it.

In Part I, you’ll understand the big swings in temperature the earth has experienced in the last million years, and the last thousand years, and the last 50 years.  In Part II I’ll explain how sunspot activity directly correlates to ALL these temperature changes.  And I’ll give you a hot, near-term investment trend to capitalize on this cool idea.

And in Part III, I’ll show you how some original research by Unit Economics has uncovered some disturbing data about the integrity of Global Warming science.  And really, all they’re doing is adding to an already big pile.

BACKGROUND AND CONTEXT

Satellites first started measuring earth’s temperature in 1979. Over the next 20 years, temperatures did rise, by roughly 0.5 degrees Celsius (0.9°F). In the 15 years since, that trend has reversed–rendering the total temperature increase since 1979 a mere 0.35°C (0.6°F), well within the range of statistical noise.

The real culprit for climate change is simply—the sun, through a complicated but predictable set of cycles.

Those cycles predicted today’s cooling trend – and they predict it will continue for another two decades and may well lead to the coldest period on earth in the last 1,200 years.

The Earth, the Sun, and the Temperature

The earth’s cycle around the sun stretches and contracts, creating 100,000-year temperature cycles. Our planet also slowly tilts one way and then the other, resulting in 41,000-year temperature cycles.

We know this because scientists have several methods to estimate historic weather, an effort that has produced this general result:

global cooling--temp swings over 1000s of years

A few things jump out.

1.    The 100,000-year temperature cycles are very apparent – and the current one is peaking.
2.    The timeframe of this chart covers ice ages and tropical periods, which means it takes only a small change in global temperatures – only two to four degrees – to separate a very warm world from a very cold one.
3.    Through the cycles of the last 800,000 years, the average global temperature is creeping upwards.
4.    The magnitude of each cycle seems to be increasing.

Now, this chart should be taken with a grain of salt because the methods we use to conjure these numbers are not perfect.  But at least the chart lets us put recent climate changes into historic context – a context that deserves a closer look.

The key takeaway is that the earth has been through some very warm periods and some pretty cold ones. Take the years between 800 and 1200 AD, for example.  During these 400 years it was so warm that vineyards spread across central England and bountiful harvests almost doubled Europe’s population.

Then it all changed. By the mid-1300s England’s vineyards were gone and sea ice expanded so much that polar bears crossed to Greenland. This short cold snap was truncated in about 1400, when warmer weather returned for 150 years.  Get the idea? Up, then down, then up, then down.  And then came the Little Ice Age.

Lasting from 1550 right until 1850, the Little Ice Age froze Austria’s vineyards, forcing parched Austrians to switch from wine to beer. Winter fairs were held on the frozen Thames River for 20 years (you’ve all seen the paintings) and Hudson Bay was littered with ice chunks in mid-summer.

This period of time was so cold it earned the moniker The Dalton Minimum—a reference to the very low number of sunspots then.  In the year 1816, storms dumped snow across New England and Quebec in June, lake ice lasted until August in Pennsylvania, and failed crops led to food riots in Britain and France.

So when you get asked, is the world warmer over the last 200 years, since the Industrial Revolution started? Yes, but it has squat to do with industry.  That just happens to co-incide with the smallest sunspot activity in “modern” times.

Eventually the world started to warm again. From 1890 to 1934 central Europe barely saw any snow. Another warm spell from 1942 to 1953 had scientists predicting the death of Europe’s glaciers, a forecast invalidated when the world once again cooled.

Here’s some interesting data as we get closer to the present day:

1.    Temps continued to fall from 1953 until the mid-1970s – despite rising CO2 levels.  This was during the single most industrializing time on earth—and temperatures fell while CO2 levels rose.

2.    Another point: if CO2 emissions cause global warming the layer of the atmosphere 5 to 10 km (3-6 miles) above the earth where CO2 interacts with sunlight should be warming more quickly than the earth’s surface. In fact, temperatures at these levels have been unchanged since accurate balloon measurements became available 50 years ago.

3.    There has been a large outcry about the decline of Arctic Ice. While Arctic sea ice extent is just above average levels, Arctic sea ice is near record thickness: the volume of ice in the Arctic last fall was 50% higher than 12 months prior, following a very cold summer in 2013 in which temps climbed above freezing only 45 days compared to an average of 90 days.

I bet you didn’t read about that.

4.    There’s a lot of ice at the other end of the globe too. In eight of the last ten years global sea ice extent has bested the 30-year average, aided by an Antarctic sheet that in October hit its highest extent since record keeping started in 1979.

5.    The Northern Hemisphere had its second, third, and fourth highest snow extents on modern record in 2010, 2011, and 2013. In the United States 2013 brought the largest year-over-year drop in temperature on record and the winter is on track to be labeled the third coldest in 200 years.

Evidence of this cooling is everywhere – even if politicians and the media try to pretend it isn’t.  Of course, the media has short memories. Only 40 years ago, in mid-1974 Time magazine ran a cover story entitled “Another Ice Age?” noting a 12% increase in New Hampshire snow cover in 30 years.

Conclusion: over the last 1,200 years the earth has been through several pretty extreme temperature swings. What gives?

The answer lies with the sun. Cold periods coincide with solar minimums, which generally happen every 150 to 200 years. Warm periods coincide with solar maxima, which happen every 700 years or so.

In Part II, you will read about how accurately sunspot activity relates to earth’s temperatures, why the signs are indicating a deep cooling trend for the next 20 years (brrrrrr……), and one near term investment idea in the energy patch that should prosper greatly from this new trend.

Part II of this series is here.

Ride with the Bulls – Stock Picking

By
Keith Schaefer
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0

Meeting management is key.  To ride the  Big Bulls—those stocks that just keep going up—meeting the CEO gives you that extra conviction to hang on for big capital gains.

The 200+ investors who heard the CEOs of OGIB companies got that opportunity on Saturday, March 1st, at the Subscriber Investment Summit in Toronto.

They also got a chance to win $1000 cash after listening to everyone—and now you get to play too.  More on that in a minute.

We had people from all over the Eastern Seaboard at the show.  One couple drove up from Maryland.  Pete flew in from Chicago.  Tom came in from Maine (he owned a lot of my ethanol stocks).  Marie flew in from Halifax.  I talked to two gents who got up at 430 am that day in Saskatoon (where it was -50 with the wind chill) and caught the 6 am flight to Toronto just to be with us.

And Gene from Minnesota came—he was one of my original subscribers back in 2009.  And of course, my friend Olivier flew in from Belgium, as he has every year.

I love meeting subscribers, and hearing their stories about stocks that made them a lot of money or caused grief.  There’s a story behind every stock tick in the market.

Now back to the prizes! This year, we did an online stock picking contest , and after listening to the eight oil and gas CEOs, attendees entered which three stocks they believe will perform the best in the coming 12 months.  We will be handing out the $1000 first prize at cash at the beginning of next year’s Summit—and the free one year subscription.

And now you get to play too, online and for free.
We have teamed up www.stockpools.com –so you can see which eight OGIB companies presented, and after doing some of your own research, can determine which three you think will do best.

I had both service companies and producers present—and they were both domestic and international.  So there is a wide range to choose from.

Attendees at the SIS only heard 10 minute presentations—nobody was able to go through their entire powerpoint.  But attendees get two hours of one-on-one time to meet and speak with the CEOs.

And that’s what makes the Subscriber Investment Summit so powerful—energy companies mostly only do institutional shows, and rely on the brokerage firm analysts who cover them to reach retail investors.

But brokerage firms are paid to be bullish.  Meeting the team yourself can save you or make you a lot of money, without that layer of interpretation in between.

That’s why next March, you should come out—and win $1000.

So there is a small catch (of course).  You had to show up at the SIS event to win the $1000.  But you can win the free year subscription.

The pool starts on April 7, 2014 and ends February 20, 2015.  I will be sending out periodic updates letting everyone know who leading winners.  It’s all free, online, no credit cards or paypal or anything—just fun. I’ve known the principals of www.stockpools.com personally for ten years, and in a previous life worked at the desk right beside them.  Solid people.

The link for the pool is below. First, here is the list of companies eligible, in alphabetical order, and a quick synopsis:
Canamax Energy (CAC-TSXv; DTEYD-PINK) has gone from zero to over 500 boepd since forming last August. Small land package in the same prolific Brazeau play that has rocketed DeeThree to $9. Key player-Kevin Adair  www.canamaxenergy.ca

Enterprise Group (E-TSX; ETOLF-PINK) is a fast growing energy services company in western Canada.  Higher than average profit margins.  Key player—Len Jaroszuk.  www.enterprisegrp.ca

Entrec Corp (ENT-TSX; ENTCF-PINK) is an oilsands service company with great LNG optionality—they own the largest crane operator on the central west coast. Key player—John Stevensonwww.entrec.com

High North Resources (HN-TSXv; HNTHF-PINK) is developing an oil play in the Montney formation in Alberta, where neighbours are getting 1 year paybacks (which is very fast!) Key player—Colin Soareswww.highnorthresources.com

Iona Energy (INA-TSX) was the fastest growing oil junior I saw in 2013, and the stock still trades 1x cash flow—with their latest offshore well paying out in a year.  Key player—Neil Carson www.ionaenergy.com

Madalena Ventures (MVN-TSX; MDLNF-PINK) is the leading junior in Argentina’s Vaca Muerta shale—which looks to be 3-5x as productive as the Bakken.  Key player—Ray Smith www.madalenaenergy.com

Manitok Energy—(MEI-TSX; MKRYF-PINK) is almost unique in western Canada with its focus on old-style conventional oil pools in the Alberta foothills. 8-12 month payouts on wells.  Key player—Massimo Geremia  www.manitok.com

RDX Technologies—(RDX-TSXv; RGDEF-PINK) has a waste-water-to-fuel technology that is not only commercial but generating positive cash flow. It’s like turning straw into gold and it’s happening now.  www.rdxh2o.com

Here is the link to join the pool now:

http://www.stockpools.com/pools/keith-schaefers-oil-gas-investments-pool

Good Luck!

Why Buy $3 Billion Dollars Worth of Gas, Sight Unseen?

By
Keith Schaefer
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0

by Shaun Polczer

Smart money isn’t making big investments in natural gas.  It’s making HUGE investments.

One of the industry’s most fiscally conservative — and notoriously cheap — operators, CNRL (CNQ-NYSE/TSX; $36) reportedly bought Devon Canada’s entire conventional oil and gas—but mainly gas—assets for $3.1 billion;  reportedly sight unseen. It didn’t even wait go into the data room, pre-empting the entire process with its all-cash offer.

We’re talking 2.2 million undeveloped acres, and another 2.7 million acres of freehold royalty lands, scattered across a diagonal line running from northern BC to southeast Saskatchewan.

It’s conspicuously contrarian for a company that since 2008 has shut in money losing wells and let total gas production fall by two-thirds. Even more curious is the fact that CNRL in January shelved plans to dump 6.7 trillion cubic feet of Montney reserves when it couldn’t get the price it wanted — presumably more than the $30,000 per flowing barrel it was willing to pay Devon, which isn’t exactly cheap.

This deal could unlock the doors to a lot more M&A in the natural gas market.  There is now a firm price both buyers and sellers can start from to get the games going.

The timing of those decisions will be set by the gas price. Though Henry Hub spot prices spiked in the last week of February, at $6.50 US per million British thermal units (Btu), nobody — not even CNRL — is predicting a real turnaround in natgas prices until the first LNG export terminals in Canada and the US kick in after 2016.

But CNRL obviously sees something in gas market fundamentals others don’t.

Storage overhang melts in freezing cold

Aside from the cold, the last week of February was notable for extremely bullish natural gas storage numbers. According to the US government’s Energy Information Administration (EIA) storage levels are a trillion cubic feet (tcf) lower than they were last year and 39% below the five-year average. The EIA is projecting winter storage to bottom out below 1 tcf for the first time since 2003. That’s what a polar vortex will do.

Summer’s going to come eventually, so it would be remiss to think short term prices are going to stay aloft, but the trend is heading in the right direction. The EIA expects the US to consume in excess of 70 billion cubic feet per day in 2014 for only the second time since 2013, after seeing spikes in excess of 135 bcf/d in January.

The demand side is looking equally bullish. Later this year the Obama administration will enact the first restrictions on coal-fired power, which will increase the call on gas. He’s also expected allow LNG exports through the Gulf of Mexico, which will also support prices over the longer term.

Most of it will come from domestic plays like the Marcellus, which the EIA projects will become the largest gas producing region in the US this year.

But even as overall US imports from Canada continue to fall, Washington state, Idaho, Oregon and parts of California continue to rely on Canada for 65% of the gas consumed in the Pacific Northwest. Some 6.5 bcf/d arrives from northeast B.C. via Spectra’s Westcoast pipeline that runs from Fort Nelson to the US border.

According to Housely Carr with RBN Energy in Houston, extra pipeline capacity from Canada will be needed to meet an extra 2.1 bcf/d of new gas demand in the region, roughly a 30% increase from present levels.

This time the story isn’t coal. Hydro production is threatened by drought and low reservoir levels experts attribute to long-term climate change. Consequently electricity producers are switching to gas as a backup, and many are using it as their primary fuel source.

Tying it together

That’s good news for gas producers in B.C. that are tied into west coast pipelines.  CNRL included. And it should provide some welcome relief for struggling juniors, who haven’t been able to raise the capital needed to even bid on Devon’s land.

With CNRL and Devon setting a new benchmark for deals, many companies are trading below the value of their land holdings, setting the stage for a new round of M&A activity.

Artek Exploration is a case in point. Following its latest reserve report, the company is claiming net asset value of $5.43 a share for its 150,000 acres in northern Alberta and B.C. versus a share price of about $3.50. However it has gained as much as 60 cents since the Devon deal was announced, to hit a new 52-week high of $4.08.

Robert Pare of Clarus Securities is the most bullish analyst covering the company, with an estimated after tax asset value of $8.64 per share and a 12-month target price of $6.50.

Other maligned producers are in a good spot too. After more than doubling in 2013, TSX-Venture listed Storm Resources continues to make new all-time highs just below $5. It could either be a tempting prize or a potential acquisitor in this environment.

But juniors aren’t the only ones to benefit. Bellwether intermediate Birchcliff Resources has gained nearly $2, or more than 25% since mid-February, and is now trading around $10. That in turn sparked a round of analyst upgrades; TD Securities upgraded the company to ‘buy’. Scotia Bank upped its target to $12 with a ‘sector outperform’ and CIBC tacked in at $11.75.

Birchcliff is notable because it put itself up for sale three years ago and hasn’t been able to find a buyer. CEO Jeff Tonken has made no secret of his intentions to sell the company when the price is right. That time could be now.

But like the weather, that could change in a hurry. The bigger question is whether this is a blip or a long term trend. The smart money thinks it’s here to stay.

To understand CNRL’s newfound enthusiasm for gas, a little history lesson is in order. Oklahoma-based Devon made a big splash into Canada in 2002 by buying Anderson Exploration for $4 billion, a tidy sum in those days. Fronted by the legendary JC Anderson, his namesake was notable for its takeover of Home Oil in 1995.

For those who don’t know, Home inherited the mineral titles of Hudson’s Bay Oil and Gas, which in turn inherited them from Radisson, Gooseberries, and King Charles II way back in 1670. CNRL didn’t need to go into the data room to know that these are literally, the Crown Jewels.

Most energy investors in Canada are aware that the Canadian Pacific Railroad freehold lands that Encana has, it now plans to spin into a separate entity.

In fact, the Hudson’s Bay titles — which formed the basis for the Canadian National Railroad — are just as big. It is likely that CNRL will follow similar feats of financial engineering with a spinoff of Devon’s so-called ‘fee simple’ royalty lands later this year.

That spinoff would effectively double CNRL’s existing royalty revenue to $150 million by 2015.

Combined with its own freehold lands, it will be at least as large as Encana’s plans for its Clearwater IPO, at 5 million acres or more.

That still leaves 2.2 million acres that CNRL would need to drill at some point, if only to keep the leases. It could bring in a foreign partner to offset costs, but that’s not CNRL’s style — it likes to keep 100% control of everything and set its own pace.

Devon’s 86,600 boe/d of production — including 343 million cubic feet a day of gas — is 72% operated, giving the fiscal and operational flexibility to respond to changing market signals.

Energy Sectors Poised to Run…Except One

By
Keith Schaefer
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US energy stocks outperformed Canadian ones last year—but in the last few months, E&P equities in the Great White North have soared. Why? The low Canadian dollar has a lot to do with it, adding an extra 6-10% to the Canadian oil price—which of course is ALL profit.

The second reason is the natural gas prices have rocketed up, thanks to repeated cycles of the Polar Vortex. Canada is a gassy basin, despite all the tight oil finds of the last five years. And lastly, the continued growth of the oilsands—along with the potential of LNG exports off Canada’s west coast—have kept a bid under the services sector.

I talked with Chris Theal, CEO of Calgary’s Kootenay Energy Fund—as I do every quarter—to help me get a handle on the future of Canadian oil, natural gas and energy services. He has a one year return of 19.6%, and was up almost 7% in February alone.

Keith: What are you seeing in the services sector right now?

Chris: We’re seeing massive out-performance. The services sub-index finished January on a low because everyone was talking down numbers on almost all the stocks. So I think it sort of reset expectations coming into the quarter this year and now they’re journaling out a real strong lift and utilization and all adds up.

I think we’re going to come out of winter drilling with a backlog of completions which is good for pumping and good for coil tubing. But you need to start seeing these guys pass through price increases–variable costs like fuel, sand, land transportation which is the biggest part of sand and those are the things that I think you need to start seeing to buy into the pumping thesis.

The Montney and Duvernay are the two most pumping intensive plays in the western Canadian basin and activity is really picking up in both. When we start to see built-for-purpose rigs delivered into Horn River (in northern B.C.) for Chevron Apache—the fracking market is going to go real tight. The bottom line is that we think pricing power is coming in the second half.

Keith: How is the higher commodity pricing in Canada impacting your outlook?

Chris: When you look at strip pricing, you’re probably putting $8 billion more cash into the jeans of producers and they’ll spend that at a minimum. They’ve raised equity and those proceeds are for more rigs and more drilling.

Then you see Encana and CNQ (Canadian Natural Resources) carving out their own royalty companies. They are going to look to aggressively farm out land and get juniors drilling on it, so the dynamic for activity is really good in Western Canada. Combined with the strength in commodities, a weaker dollar and new equity, you’re going to see pricing strengthen.

Keith: You and I talked late last year about heavy oil—are you still keen on heavy oil?

Chris: I think the heavy oil commodity move is done. I think that what nobody is focusing on and something that is going to impact profitability is the natural gas price. They’ve enjoyed low priced gas for 5 years and the fuel cost for SAGD (Steam Assisted Gravity Drainage) and integrated mining are going to be quite substantial in Q1 and for all this year. So as much as we have the tail wind on differentials, there are other factors impacting profitability.

Keith: So you think natgas is going higher and staying higher?

Chris: I’m surprised the NYMEX forward curve–and I’m looking out 5 years on the curve–has dropped $2 in the last year. Where are the industrial consumers buying the hell out of 5 year gas? I don’t understand why the forward curve is so low.

In Eastern Canada, gas storage is going to be fully depleted by the end of March–none left, zero. This March is looking like it’s going to be colder than last year which was a high water mark in itself which will leave us with no gas in Eastern Canadian storage.

We’re going to be sucking gas like mad out East to get it back in storage for next winter.

Keith: Aren’t there new pipelines coming across from the Marcellus in Pennsylvania to Ontario?

Chris: They can’t be Ontario’s savior this year nor can they be the gas supply solution for US storage. They need to get more pipe to take gas out of the Marcellus, and infrastructure will be coming on in stages. So egress is now a governor on Marcellus output growth.

We think US storage is going to be 750 B’s (ed note—Billion Cubic Feet or bcf) to finish winter now. We think the market will need to loosen by 4 B’s a day just to get US storage back to full. Typically to loosen the market you’re going to need to add supply and we aren’t seeing movement in the gas rig count and we don’t think we’ll see it until $5/mcf. And even after that it’s probably 3 or 4 months before any pads start yielding new supply.

Or you have to kill demand and when you kill demand it’s actually pretty constructive for gas prices; it signals scarcity.

So you’re going to start seeing gas to coal switching. But you can even see that California’s in a 25 year record drought which means more gas consumption. So we like the gas story all year long. We are in a very tight market for gas in 2014.

I think what we see on the forward curve right now is the floor on gas. The hard part for storage is you have $4.61 an mcf (ed note—mcf=million cubic feet) on the front month and next winter its maybe $4.75 per mcf.

There is no contango to cover your storage carrying costs and so there is no incentive for merchants to inject cash into storage.

So what it is telling you is that either the front end is going to drop a lot or the back end is going to start cranking up. The way the weather picture is going right now, the front end isn’t dropping and so I think the forward curve is going to start lifting.

Keith: Interesting. Now, once the Polar Vortex is over by the end of April should we have a much better handle on how long-dated strip pricing will workit? Or is there no way to gauge the back end of the curve?

Chris: Well we’ll know better by the end of April, but one of the US brokerage firms put a research piece out recently suggesting that with all the Great Lakes frozen you’re seeing lower peak daily temperatures in the most populated part of the whole US.

It’s keeping temps lower because you’re not getting the lake effect of warmer lake water warming air around big cities and so they actually concluded that you can very well see pulls on gas storage in April with the Great Lake phenomenon.

Keith: So that’s a segue that you’re bullish on gas?

Chris: Big time. You got the gas story and you can lock in your gas at $4.25 through the rest of the summer season to November 1 in Canada. I think with the way the storage dynamic is shaping up, the gas market will be stronger in summer.

Keith: Okay. So you’re not quite as keen on heavy oil as you used to be and you’re much more keen on gas. The higher gas price is not reflected in the upcoming financials of these energy companies and it’s probably going to affect the big guys more than the little guys.

Chris: Yeah I guess on heavy oil it’s not much…I do think the commodity trade or thesis’s played itself out. We’re just not as bullish on crude. We like oil stocks but confine our exposure to where we see more catalysts.

Keith: Okay. So we talked about oil, we talked about gas, we talked about services. Is there anything in the North American energy complex that is political for you? Is anything going on in the political realm that you think might have an impact on stocks or fundamentals here in the near to medium term?

Chris: There are a couple things. I guess the fiscal regime in BC is one. What we’re hearing is all the big players are going to have the full fiscal regime in hand by the end of the 2nd quarter. They’ll have a good grasp of what they’re looking at. And we’re hearing the royalty changes may come in the next month or two.

Royalties are the biggest sensitivity on the whole integrated projects. If they lighten up on the royalties all the way to the Alberta border it’s pretty lucrative to those gas producers in that wedge of northeast BC. You’re going to wake up one day with a new royalty framework and NPVs as well are going to go up 12 to 15%.

In the US—there is increasing noise in North Dakota about gas conservation requirements and new rules coming down on public lands …

Keith: Is way overdue.

Chris: Yeah and it’s starting to get some headlines. There can be some risk for the Bakken players. To be honest, the half cycle cost of that oil is in low $80 range and if we start investing in gas conservation and fuel compression, etc. it makes it a high $80 proposition. So the US has energy independence, but it has a price.

Keith: Chris, that’s all the time we have today. Thank you for sharing your insights.

Chris: You’re welcome.

Investors can check out Chris’s energy focused funds at www.kootenaycapital.com. He has a monthly letter with his strategies on energy investing–to which investors can inquire through the website.

by +Keith Schaefer

Why Shell Needs This Junior’s Big Play

By
Keith Schaefer
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Elephant hunting for huge international oil plays usually means going into (very) politically risky areas. That’s what makes junior Petromanas (PMI-TSXv) stand out from the crowd.

They’re chasing a potential 500-800 million barrel target in Europe—Albania to be exact. Lots of energy investors are familiar with Bankers Petroleum and their heavy oil play there—it’s the largest onshore oilfield in all of Europe.

But few people know about Petromanas. I expect that to change in a hurry in Q3 2014 if their next well hits. They already have one success under their belt.

But even better, they’re getting carried for $100 million on exploration and seismic costs on two high-impact Albanian blocks by oil industry super major Royal Dutch Shell (NYSE:RDS.A).  Plus, Shell paid them cash for their sunk costs. 

It’s rare to see a super major aggressively seek out a partnership with a company the size of Petromanas. Shell’s interest is ahuge validation of the true potential of the assets that Petromanas owns.

However, Shell knew the geology very well—they’re already a partner in two large producing properties that are analogous to the Petromanas property in Albania, just across the Adriatic Sea from Albania in Italy.

 

italy-albania

 

Not only does Shell bring to the party big financial and geological resources, but also in this case specific field experience in this particular type of play. (It’s a sub-thrust play which is very similar to what you see in the Canadian foothills in western Alberta).

I was intrigued by Shell’s interest in this play so I called up Petromanas CEO Glenn McNamara to get some background.

He said Shell had started expressing interest in the property even before Petromanas had formerly opened up a data room in 2011 to seek out a joint venture partner. Once the data room was officially opened Shell bid on the property.

McNamara said that Shell’s joint venture bid was clearly one that Shell knew Petromanas would find attractive. Shell didn’t do any beating around the bush. It wanted these assets.

 

In February 2012 Petromanas had Shell in as a partner for 50%, and by June of the next year (after the first well) Shell had upped its interest to 75%. Again, they knew the geology.

Those two Italian properties are big, 500 million and 300 million barrel fields respectively.

The first field started production 14 years ago and it is still producing over 80,000 barrels per day. The second field will commence production in 2016 and is expected to hit 50,000 bbls/day quickly.

Individual wells on those fields can be prolific with rates ranging from 1,000 bbls/day up to 7-10,000 bbls/day.

Shell needs multi-hundred million barrel discoveries to move the needle. Clearly Shell thinks it has a good chance of finding something like that in Albania.

A positive needle move is something Shell shareholders would welcome. Despite spending $46 billion on exploration and development in 2013 Shell’s production actually declined by 5% to 3.25 million barrels a day year on year.  2013 earnings were also down from 2012.

chart for RDS

 

Albanian Blocks 2-3 – Activity to Date

Shell and Petromanas have already drilled a well (Shpirag-2) on these blocks.
The result of the drilling was a light oil discovery. The well was tested in the fourth quarter of 2013 and flowed at rates of 1,500 to 2,200 boe/day (60% oil).

Drilling problems at Shpirag-2 meant they had to tap the reservoir with smaller diameter hole at the bottom—so the rates of the flow test make it difficult to predict how much oil the well can produce.

But the discovery at Shpirag-2 did confirmed there is definitely oil in the tank.

The question now becomes “how much oil”?

To help determine that, Petromanas and Shell will be drilling another well (Molisht-1) 18 kilometers to the south.

Shpirag-2

 

When I spoke with CEO McNamara he was clearly trying to keep a lid on his enthusiasm, but he did say that the Molisht-1 well target could actually prove to be the same structure as the Shpirag-2 well.

That would mean this discovery is actually an oil field that is at least 18 kilometers long.

If that is the case, it could easily mean that this field is 500 million to 800 million barrels in size.

That is the potential. The challenge with this play is that the wells are very complicated and very expensive.

Which is another reason why having Shell as a partner is a big plus for Petromanas. Shell has been drilling exactly these types of wells for 15 years across the Adriatic in Italy.

Experience counts, but even after 15 years, these wells aren’t easy for even Shell to drill.

The complication lies in the fact that the companies are drilling through a “flysch shale” rock enroute to the carbonate reservoir. It is flaky stuff that is not very stable.

On the Shpirag-2 well the rock caved in on the drill string three times.

Petromanas CEO McNamara described the flysch shale rock as being “coal like” with a tendency to “sluff” in on the well bore.

Every well sounds like a challenge.

On the Shpirag-2 well those challenges compromised the actual flow rates. That well ended up being only 4.5 inches in diameter instead of the 6 inches that the companies had hoped to use.

As I said, we know there is oil in this tank. We just need another well or two to understand how much oil is there and how profitable it will be to produce.

Shell’s interest in this Albanian property is what put Petromanas on my short list.

Some back of the envelope math is what keeps the company close to the top of that list

The size of the prize here is huge. We are talking about 500 to 800 million barrels.

And these aren’t resource-play barrels that require hundreds of wells that decline very quickly. This is a conventional play–prolific wells with lower decline curves.

Little Petromanas could have a 25% interest of a 500 to 800 million barrel field. That would be 125 to 200 million barrels net to them.  Based on the analogous fields across the Adriatic in Italy, barrels in this type of field have NPVs (net present values) of $10 to $12 per barrel.

Now the simple math:
120 million barrels worth $10 each adds up to………………… $1.2 billion.

Petromanas has a market capitalization of $90 million and an enterprise value of $60 million (market cap less cash on hand).

Now, Petromanas has had to issue a lot of stock for that money—there is now 694 million shares out basic and 890 million fully diluted. That’s 100 million warrants at 45 cents due February 2015, 50 million performance shares depending on how much oil is discovered, and 46 million options at an average 27 cents.

So at some point, management will almost certainly do a reverse split. But with a good well, that will mean the stock trades higher, not lower.

And if this Albania play is the real deal Petromanas isn’t going to be a double or triple. Petromanas has the potential to be a multi-multi-multi-bagger. 1.2 billion divided by 60 million = 20x.

That’s the potential. It’s exciting and why I’m interested, but it is very important to note that this Albanian play has not been “de-risked”. Petromanas CEO McNamara was careful to stress that several times when I spoke to him.

We know there is oil, the Shpirag-2 discovery confirmed that. And we know the tank appears to be very large.

What is needed next are a couple of additional wells to provide further detail on the find and a better indication of commerciality.

There are two big events for Petromanas in 2014.

The first will be the results of a new 51-101 resource assessment that Petromanas will get from a third party.  TSX listed stocks must get independent resource appraisers.  Since the last resource assessment was done Petromanas has obtained twice as much seismic data on the play and drilled a well.

Petromanas believes one interpretation indicates that the structures could be a lot bigger than they appeared the first time around.  Now we need to wait and see if the resource appraiser confirms this, and just how big they think it is.

I think there is a very good chance that the third party reserve engineers come back with a big increase to their original resource assessment.

I would expect those resource assessment numbers to show up in the second quarter.

The second big event is the Molisht-1 well.  Results from that well are expected in the third quarter of this year.   It is possible this well will confirm that it has been drilled into the same structure as Shpirag-2 which is 18 kilometres away.

That would be a day that Petromanas shareholders would welcome.

by +Keith Schaefer

PS—It’s interesting that the Point and Figure chart for PMI is now calling for a $2.19 share price—this is fromwww.stockcharts.com

petromanas

 

How to Win Bigger than the Bakken

By
Keith Schaefer
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In Part 1 I explained how Argentina’s Vaca Muerta shale is the only international play—so far—that looks like it could be bigger than the Bakken.

For investors, the challenge is that most of the activity in Argentina today is controlled by major companies. Names like Shell, ExxonMobil, EOG Resources and Total. Those stocks are not the kind of pure plays that will give investors serious upside from a big discovery.

In fact, there’s really only one way to make a direct investment in Argentina’s shale today—through a junior firm that’s had the foresight to stick with the play since day one.

Madalena Energy—MVN-TSXv; MDLNF-PINK.

Madalena was a significant acreage holder in the Vaca Muerta shale back when the whole play was just an engineering pipe dream. The company grabbed nearly 300,000 acres of exploration blocks here way back in 2007—at a time when even shale in the U.S. was just starting to take off.

It wasn’t until three years later that things really started to click in the Vaca Muerta—in November 2010—when major oil player YPF (the federal Argentine oil company, which is publicly traded) brought Argentina’s first shale oil well online here.

That well was drilled into YPF’s Loma La Lata field, and completed (fracked) using fracking techniques of the kind that have transformed U.S. shale. The result was initial production of 250 barrels per day of oil—numbers that at the time were considered a major success in this new basin.

This kicked off a round of frenetic activity in the Vaca Muerta shale. Work that’s shown this formation to have some of the best petroleum geology on the planet.

For one, the shale is exceptionally thick—100-200 metres in the shallower, oily part of the basin and 1000 metres as it dips to west in the deeper gassier parts. It’s also very high in organic carbon—the stuff that sources oil. It has up to 12% “total organic carbon”, or TOC–similar to the peak values seen in mega-producing shales like the Marcellus.

As operators learned more, they realized the Vaca Muerta could be much more productive than first thought. They pushed to understand the rocks and optimize completion (fracking) techniques.

The result has been steadily increasing flow rates from new wells—and that’s evident in Madalena’s results over the past two years.

When the company completed its first test of the Vaca Muerta in early 2012, the well flowed 314 barrels per day. But just a few months later—in July 2012—the company tested its CAN-7 well at 1,340 barrels oil equivalent per day from a light oil reservoir sourced from the Vaca Muerta. That well showed the huge difference a little knowledge can make in emerging plays.

That learning curve is continuing–with recent wells showing even better performance. Two months ago, Madalena drilled its first horizontal well and it came in at 2,238 barrels of oil equivalent per day. That’s a quantum leap!

This sets the company up for a lot of development work ahead. Initial vertical test wells have already identified six separate light oil pools across Madalena’s acreage in a light oil reservoir sourced from the Vaca Muerta shale.

The Big Prize is the massive Vaca Muerta shale itself, and other tight oil or liquid rich gas plays like the Lower Agrio and Mulichino. The industry pays big to have this kind of stacked formations on top of each other that can be reached from one surface location (called a pad).

Madalena has an independent engineering report showing a best-case estimate of 34.8 billion barrels of oil equivalent in place net to Madalena across its three Nequen basin land blocks.

Projections on recoverable resources are currently pegged at 2.9 billion barrels of oil equivalent net to Madalena, of which ~2.0 bilion barrels are driven by the Vaca Muerta alone.

That’s a lot of oil, gas and natural gas liquids in the ground. And if horizontal drilling and fracking can produce the large amounts suggested by initial testwork, it’s easy to see how the Vaca Muerta could indeed become the leader in the international race for shale.

skyvaluation

What’s It All Worth?

The key of course is—what kind of economics will producers like Madalena get when they start pulling Vaca Muerta crude out of the ground?

Here are some eye catching numbers: $8,000 an acre. GYP, the provincial (Nequen) oil company, will likely go public in 2014, and $8000 per acre is the Chairman is saying he’ll get for valuation. Note that GYP holds a 10% interest in all three of MVN’s blocks.

Mackie Research oil and gas analyst Bill Newman says: “If one applies the $8,000/acre value to MVN’s three blocks (135,000 net acres) it equals $1.1 billion. MVN’s Curamhuele and Cortadera blocks might not attract this valuation given the relatively earlier stage of appraisal.

“However, given the drilling and acquisition activity on and around the Coiron Amargo block, we believe that $8,000/acre for this block is a fair value, which equates to $280 million or ~ $0.77/sh.”

Just one asset–Coiron Amargo is the crown jewel so far for Madalena–is worth 77 cents, and the current share price for the whole company is 65 cents.

Analysts are also estimating that Chevron’s July 2013 joint venture with YPF is valued at $10,240 per acre, and roughly $48,000 per flowing barrel. That makes Coiron Amargo worth 99 cents a share for Madalena.

stockchart

Energy Prices Are Moving Up; Costs are Coming Down

The government ‘s improving fiscal regime helps a lot. Producers are now able to receive an increased price for oil sold outside Argentina—solving the issue of low domestic prices. The fact that 20% of exports are tax-free also adds to the bottom line.

On top of that, Argentina has made recent moves to boost natural gas prices, to $7.50 per mmbtu, up from $5.

That should lift economics on many Vaca Muerta wells—given the significant volumes of natural gas associated with oil production. Madalena Energy’s recent CAN.xr-2(h) horizontal well tested 2.7 million cubic feet per day, along with big oil production.

The other big part of the profit equation will be drilling costs. That’s where many other shales globally have stumbled—with high costs for drilling and completing wells eating up profits from the ensuing production.

But the Neuquen basin is a mature petroleum-producing region–so road access is good, and there’s a lot of pipelines and infrastructure already there. That cuts down on costs for bringing in drilling rigs, and for tying in production once wells have been completed.

The Neuquen also has a key drilling resource: water. In other parts of the world, fracking activity is limited by water availability. But the nearby Limay and Colorado rivers should help Vaca Muerta producers overcome this challenge, and avoid the high cost of sourcing far-afield water.

Parts are a big question for the Vaca Muerta. But the government is making a specialized industrial park just to service drilling and fracking.

All of this suggests Argentina has a legitimate shot at becoming The World’s Next Big Shale Play—with a billion-barrel prize for early developers.
The last thing to remember about Madalena—is management. CEO Kevin Shaw spent a lot of time in the field before spending some time as one of Canada’s top oil and gas brokerage analysts.

Ray Smith is the Chairman. Smith has set a new bar for Canadian management teams in attracting foreign joint ventures into his Alberta gas play, Bellatrix Explorations (BXE-TSX/NYSE). Madalena has the potential to do the same in Argentina, and with their assets in Canada.

It all creates some exciting blue sky numbers–and an obvious exit strategy with all the Petro-Majors involved in the Vaca Muerta–for investors to think about.

by +Keith Schaefer

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