The Only Play on Earth Bigger than the Bakken

By
Keith Schaefer
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Argentina is the “Comeback Kid” story of 2014. After getting vilified for nationalizing one large ownership block in the prolific Vaca Muerta shale play in 2012, Big Oil is coming back in a Big Way—and dragging up the share price of the fast growing juniors in the play.

Most investors have forgotten that it’s the only shale oil play in the world that appears to be better than the giant US shale oil deposit in North Dakota and Montana—the Bakken. That’s right—more productive, more oil charged, and thicker—than the Bakken.  It’s located in west central Argentina, in the Nequen Basin.

Energy gurus Wood Mackenzie recently called Argentina’s shales the best in the world. And just this month, market strategists Lux Research named Argentina as one of the top spots to watch in the race to bring shale production to new lands.

Neuquen basin

In 2012, Argentina became hot as a pistol in the junior energy markets—and then went from hero to zero as soon as the government announced it was nationalizing the shareholding of its National Oil Company, YPF, that was owned by Spain’s NOC, Repsol.

Stocks that had meteoric rises—came down to earth. The leading Argentine juniors had a bottoming period through 2013 but are now make their way back because Big Oil is pouring a lot of money into the Vaca Muerta shale.

And why are they doing that? Because, as the government said at the time, the Repsol deal was a one-time thing. And in the two years since then–while the Vaca Muerta translates as “Dead Cow”–the action there has been very lively.

The area’s biggest booster recently has been petro-majors like Shell, Chevron, Wintershall and Total SA.  Shell announced in December 2013 that it was increasing its capex three-fold, spending $500 million in the Vaca Muerta shale in 2014.

That’s a big outlay in a country that even a year ago was considered high-risk for incoming capital.

But Shell officials say that recent changes in the hydrocarbon sector have today made Argentina a great place to work. “Now we feel a different wind blowing and we are assessing our possibility to invest in exploring the resources,” said the company’s Argentina chief executive officer Juan Jose Aranguren.

What’s happened to change the tune of a big player like Shell? Several key developments—ones most investors haven’t yet taken stock of.

The Repsol deal was the biggest cloud hanging over the Argentinean energy sector—and caused a flight of capital out of Argentina’s oil and gas fields.

But after mulling this move for over a year, Argentina’s government seemed to realize they had done wrong. In November 2013, reports emerged that Repsol would likely be compensated for its lost oil and gas fields—to the tune of $5 billion.

That got the attention of international operators–especially as that came on the heels of another key regulatory development—a decision to allow producers to export up to 20% of their oil and gas output, tax-free.

The government also said it will remove foreign exchange controls for companies that invest over $1 billion in Argentina over a five year period, which most petro-majors are doing.  This addresses two major concerns that made the industry pause.

(That makes their cheap currency even more profitable for energy producers.)

Those changes were enough to bring big firms back to Argentina. In July 2013, Chevron finalized a deal for $1.2 billion in investment alongside local producer YPF.  That partnership is now producing 16,000 bopd from the Vaca Muerta shale.

Soon after, ExxonMobil and Apache committed to $250 million and $200 million, respectively, in local spending and Total SA announced an estimated $400 million pilot in the Vaca Muerta. All of this cash was earmarked for unconventional shale exploration and development.  Then in late 2013, Wintershall announced a three-phase joint venture in the Vaca Muerta shale for up to $3.3 Billion for a net 12,00 acres.
It’s attention like that led analysts Lux Research to put Argentina atop their list of global shale hotspots this month. The firm noted that all of the new “powerful government incentives” in Argentina make this one of the best destinations going for unconventional (tight oil) plays.

Despite the growing excitement over Argentinean shale, there’s an issue here for investors. How to play this emerging story?  That answer comes in my next story.  Stay tuned.

by +Keith Schaefer

Canadian Natural Gas Forecast

By
Keith Schaefer
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Natural gas prices have been soaring on both sides of the US-Canada border all through January—but just the leading natural gas stocks are breaking out–tepidly, and only after an extended stretch of very cold weather across the entire continent.

That’s the Market saying it believes that once this cold winter is over, continued supply increases will keep a lid on gas prices. The so-called Polar Vortex has definitely decreased gas in storage—North America is below the five year average for the first time in five years—so investors can expect a floor in prices roughly the same as last year, despite increased supply.

Unless you’re in Canada, that is, says the US arm of brokerage firm Raymond James in a January 27 report. It’s very sober reading for Canadian natural gas producers and investors.

They outline how the fast growing and low-cost gas production from the stacked Marcellus and Utica shales in the northeastern US could displace ALL of Western Canadian gas in Eastern North America–the entire eastern US seaboard and Eastern Canada–in the short-to-medium term. (Canadians should read that sentence again.)

Canadian gas exports to the US are down almost 50% in the last six years. Losing Eastern Canada as a market–which is 1.4 bcf/d and growing–would be a major problem for Canadian producers if another outlet to sell natural gas isn’t opened up. It makes west coast LNG—Liquid Natural Gas exports to Asia—a must.

Canadian gas prices are already seeing a greater discount to US prices than normal just to stay competitive in North America. Canada is usually 30 cents an mcf (million cubic feet) cheaper than US gas in winter and 50 cents in summer. Now it’s a 68 cent discount and it’s a steadily increasing discount to 90 cents by the end of 2015 in the futures market now.

This winter’s recovery in natural gas prices may not be the light at the end of the tunnel–that may be from a train barreling down the track, with the name MARCELLUS in bold letters.

RAYMOND JAMES RUNS THE NUMBERS

From June 2009 through December 2013 United States natural gas production (including Alaska and the Gulf of Mexico) increased from 70 bcf/day to 83 bcf/day.

Of that 13 bcf/day increase, a whopping 10 bcf/day came from the Marcellus Shale alone. The Marcellus has grown at a rapid rate even in the face of stubbornly low natural gas prices.

marcellus-dry-gas

 

When will Marcellus production peak? That is Big Question #1. There are thousands of undrilled well locations remaining in the play and Marcellus economics work at very low gas prices.

At just $4/mcf, rates of return from drilling wells in the Marcellus reach as high as 60%. These stellar economics will keep Marcellus production growing in all but the most pessimistic of natural gas price scenarios.

Expectations for the Marcellus are for production to increase by another 3 bcf/day in just 2014 alone. The Marcellus is the monster shale gas play and is already turning the North American natural gas game upside down—just recently it forced the partial reversal of the $4 billion REX pipeline, which was built only a few years ago to get Rockies gas east to the lucrative New England market. Now Marcellus gas will flow west.

Big Question #2—where is all of this natural gas going to go?

It appears a chunk of it will be heading north to Canada.

For decades Canada has exported a lot of natural gas to the United States. Western Canada produces way more natgas than all of Canada consumes.

With American natural gas production seemingly in permanent decline, this was a comfortable situation for Canadian producers.
But the shale revolution that was launched initially in the Barnett Shale in Texas in the late 1990s changed everything.
Canadian exports of natural gas to the United States peaked in 2008 at just over 8 bcf/day. By next year that figure will have dropped to 4.5 bcf/day.
net natural gas expors us

 

Almost all Canadian natural gas production comes from Alberta and British Columbia on Canada’s west coast.

It costs a lot of money to get that production to the East Coast along the TransCanada Mainline pipeline.

That creates an advantage for natural gas produced near the East Coast consumer. This of course favors both the Marcellus and the Utica shales in Pennsylania/Ohio/West Virginia and New York State (if they ever approve fracking).

These two plays can provide cheap gas that will not only replace Western Canadian gas that is imported into the U.S., but also Western Canadian gas that is used by Eastern Canada. In 2007, Pennsylvania gas was priced 70 cents/mcf (million cubic feet) more expensive than Canadian gas. But now with all the low cost Marcellus gas, it trades at a small discount–so there is no incentive for Canadian imports.

There has already been almost a 1 bcf/d swing in gas exports at Niagara Falls. Canada used to export 0.5 bcf/d there to the US, but now Canada imports 0.4 bcf/d.

The Future Of Canadian Natural Gas Prices

The TransCanada Mainline has a capacity 7 billion cubic feet per day (bcf/d). In the year 2000 it was full, but now only sends about 2.5 bcf/d of Western Canadian natural gas eastbound. On average Quebec and Ontario consume about 1.4 bcf/d (though Raymond James points out that number has risen 45% since 2009 and may continue to go up).

Marcellus production growth in 2014 alone–expected to be about 3 bcf/d–will be enough to displace all of this Western Canadian gas in 2014.

Raymond James says the situation is a bit more complicated than that—but not much. It will just take time to build the infrastructure that will allow Marcellus gas to be shipped more directly into Canada.

There are currently four major projects under way that are going to make the inevitable export of United States natural gas to Canada happen:

  • National Fuel Gas / Kinder Morgan 0.2 bcf/d Northern Access expansion project (Nov ’15 startup)
  • National Fuel Gas Chippawa 0.3 bcf/d Chippawa project (’16 startup)
  • Nexus Gas project 1.0 bcf/d to export from Ohio to Toronto (’16 startup)
  • Iroquois South to North project 0.3 bcf/d (’16 startup)

Those projects combined should allow for enough U.S. natural gas to get into Eastern Canada so that no Western Canadian natural gas will be needed.

This will mean that the Northeast United States will have gone in just a few years from being almost fully dependent on Canada for natural gas to having the ability to export natural gas to Canada–and fill all of eastern Canada’s needs.

Meanwhile a BIG portion of Western Canadian natural gas production will need a new home, and that isn’t bullish for AECO gas prices (AECO=Canadian benchmark price set out of Edmonton AB).

Investors can expect a lot of volatility in AECO natural gas prices before Western Canadian natural gas is completely forced out of Eastern Canada. It will still need gas in winter, but not as much in summer. But that low seasonal will turn permanent once infrastructure is in place to get Marcellus and Utica production into Canada. And without a new market to go to, Canadian natural gas prices are going to be facing some stiff headwinds.

The current rise in AECO spot prices may not be the end of depressed prices. It may be a temporary reprieve before Canada gets a full taste of the Marcellus.

by +Keith Schaefer

EDITOR’S NOTE: This story suggests that the best investments in the junior oilpatch are:

1. the “wet gas” stocks, where condensate is produced with natural gas and condensate pays for the well, and
2. oil stocks

I have just found an undiscovered junior oil producer in the sweetest spot of the market—and I’m going to share it with you in my next story. I expect big things from this company in the very near term. STAY TUNED.

 

Offshore Oil Stocks: Where Should Investors Look in 2014?

By
Keith Schaefer
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0

We’ve seen in the first parts of this series there’s a revolution underway in offshore oil drilling.

Techniques like directional drilling and multi-stage fracking—perfected as part of the onshore shale revolution—are yielding some of the highest returns on capital anywhere in the world.

That’s because of new technologies like “logging-while-drilling” applications. That allow operators to pinpoint oil-bearing horizons and drill offshore wells at low costs that make these fields economic like never before.

To date, successes have come mainly in the U.S. Gulf of Mexico. The place where offshore drilling was initially perfected in the 1960s.

But as with that initial offshore boom, operators wielding unconventional offshore drilling tech are now bringing it to other basins globally.

Judging from the big gains such drillers have seen in the GOM, this expansion will be extremely profitable. So the question is—where should investors be looking with offshore oil stocks?

The most obvious answer is Southeast Asia—at least according to one major player in this space.

That’s John Schiller, CEO of successful unconventional driller Energy XXI (Nasdaq: EXXI). Schiller noted on the company’s most recent investor call that Southeast Asian geology is very similar to what his firm is drilling in the U.S. Gulf Coast.

He also said that Energy XXI is looking at opportunities here—in places like Malaysia.

Recent results from a nearby oil hotspot—the Gulf of Thailand—confirm the potential of this area.

Former OGIB portfolio stock Coastal Energy (TSX: CEN) has been using unconventional completions on its Thai offshore wells. And seeing excellent returns. In 2012, each dollar spent by the company yielded nearly $2.20 in proved reserves.

That’s an industry-leading operational performance—anywhere in the world. And likely a driver for a $2.3 billion takeover offer recently tendered for Coastal by the government of Abu Dhabi.

The opportunity here is largely driven by new logging-while-drilling technology—that’s allowing directional drillers to exploit thin and/or stacked reservoirs. Such technology enables operators to “geosteer” a well—making corrections to the drill angle in order to keep the well bore within the target reservoir, even if these rock layers are only a few metres thick.

Going For The Skinny Pay Zones

Such thin reservoirs are where the offshore horizontal drilling boom has the biggest potential to create big production and reserves adds.

In many parts of the world, thin reservoirs were traditionally not a target for drilling. There simply wasn’t enough reservoir rock in contact with a conventional, vertical well bore to pull in economic amounts of oil or gas flow.

In many cases, drillers even passed through such thin reservoirs—on the way to thicker horizons deeper down. The thin pay zones were often left behind pipe without being completed.

That can make such zones a low-hanging target for today’s beefed-up drilling technology. In many parts of the world, we know exactly where these thin reservoirs are located—and we have a lot of information about their geology and mechanical properties.

Using this data, drilling engineers can complete these zones with horizontal techniques—at very low risk of a dry hole.

A lot of the pioneering work in this regard has been done in deep-pocketed regimes in the Middle East. In late 2012, operators in the United Arab Emirates began reporting good results from using long (read, 15,000 feet) horizontals to produce thin carbonate units, where traditional completions had been struggling.

But offshore unconventional technology and techniques are now becoming so well-understood, they are being applied commercially in many parts of the world. Mature basins have particularly been a target—with operators in the North Sea being early adopters of horizontal drilling as well as fracking.

As with the U.S. Gulf of Mexico, unconventional development in the North Sea has begun mainly in the near-shore environment, within the southern parts of the Sea.

Last September, operators from Centrica reported that they had completed a frack delivering 1.4 million pounds of proppant (the grains that keep cracks in the rock propped open) in just a four-day period.

Centrica estimates this task would have required 12 to 25 days a few years ago. Probably making the well uneconomic—given the high day rates charged by services companies in the offshore. As a bonus, the frack was also engineering to use seawater—further reducing costs, and making the process more environmentally palatable.

Established locales like the North Sea could thus become the next big thing in unconventional drilling. Helped along by low prices for development acreage here.

That’s because several cornerstone developers have recently been divesting projects—in December stalwart player Wintershall announced it will sell 14 North Sea licenses to Hungarian energy major MOL for $375 million.

Those reserves are selling at a very attractive price. Analysts have pegged the deal as costing about $20 per barrel of in-ground reserves. That’s a price point similar to what unconventional developers have been paying for old acreage in the Gulf of Mexico.

At such prices, the economics start to look very good around recompleting such fields with unconventional technology. Thus we could be looking at the start of a renaissance, where a new breed of enterprising E&Ps takes the reins—then use new drilling to coax more oil out of old, thin reservoirs.

Offshore Unconventional Tech Goes Global

But it’s not just old, established offshore fields where big finds from new unconventional drilling are lurking. These techniques have recently been used to revitalize oil output from oil fields further afield. In the South China Sea, for example.

Chinese petro-major CNOOC reported last year that horizontal logging-while-drilling technology helped turn a Bohai Bay marginal oil field here into a moneymaker.

The advanced equipment helped place nine horizontals within a narrow target zone in the small field. By steering straight, the company estimates it improved its drilling efficiency by 60%. Equating to a cost savings of $32 million.

Production from the advanced horizontals also came in higher than expected—to the tune of a 30% improvement. Creating a very profitable field development—in tricky spot that easily could have turned into a money pit.

Advances in fracking technology are having a similar impact in places like Africa. In late 2012, Total completed its largest-ever offshore frack treatment—on an old oil field off the coast of the Republic of Congo.

The Tchendo field here had been in production since 1991. But the conventional oil was starting to dry up. Noting that a large amount of oil in place still remained, Total pushed to design an unconventional completion to up recoveries.

Results are still pending, but fracking looks to have the potential to unlock big new reserves here—and potentially at look-alike fields along the west African coast.

The re-development of old fields like Tchendo likely represents the most immediate opportunity for profits from new offshore drilling techniques. Risks are low and upside is big in places where billions of barrels of oil have been left in the ground over the decades.

Look for keen drillers to start picking up such projects on the cheap—and using new technology and know-how to improve production and profits from the world’s aged giant fields.

Catch up on part 1 of our series here, and part 2 here. 

The Offshore Oil Drilling Revolution, and its Game-Changing Technologies

By
Keith Schaefer
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Last week I looked at the phenomenal success of a new breed of offshore explorers who are using unconventional drilling (read: horizontal drilling and fracking) to unlock billions of barrels of bypassed oil in places like the shallow-water U.S. Gulf of Mexico.

Offshore producers are now getting returns as good as their onshore competitors—but offshore stocks are valued much more cheaply.

But before investors jump off the dock, we need to understand the opportunity. What’s happened with drilling technology to create such big returns? And why is this happening now in the offshore space? What techniques are delivering the biggest successes? And what companies are best-positioned to take advantage?

After all, horizontal drilling offshore isn’t a new idea. French firm Elf Aquitaine was drilling horizontal wells in the Adriatic Sea off Italy during the early 1980s.

In fact, major producers in the U.S. Gulf went through a horizontal “mini-boom” in the early 1990s. Over 20 wells were drilled by operators like Amoco. Results however, were mixed and the technique was largely abandoned for the next decade.

Better Technology Arrives Just In Time

So why is horizontal drilling suddenly back in the offshore game and having a big impact?

I see two reasons for today’s surge in activity. One is just moving the new exploration techniques that were perfected onshore—offshore. Offshore wells are 3-100x more expensive than onshore, so there is obviously less financial risk onshore if it fails.

But the energy sector is also using some funky technology from other industries—like Apple’s iPhone.

The iPhone uses something called a “small-scale accelerometer”—a device that measures changes in movement around them, telling it you’ve turned the screen sideways and should adjust the view accordingly.

Petroleum engineers simply took this technology and applied it to the drill bit—designing “smart” tools that can tell exactly where they are in space as they move down a well bore.

All this new technology does two things:

  • it makes the well cheaper, and
  • improves aim

One of the major challenges in drilling horizontally is making sure the horizontal leg of the well stays within the target formation. Steer too high or too low and the well can pass out of the oil-bearing rock formation. Or the driller could penetrate the oil-water contact—resulting in big inflows of value-killing water (water supersedes oil in the well bore).

But keeping a horizontal well level through the target formation is difficult—especially in places like the Gulf of Mexico, where oil columns can be just tens of feet thick.

That’s where a recent advance called logging-while-drilling (LWD) comes in.

The latest revolution in LWD is a combination of improved technology (machines to collect and transmit data) and better technique (interpreting collected data and using it to make decisions).

All of these improvements cut their teeth initially in onshore U.S. shale plays.

When horizontal wells began developing shale basins like the Barnett in Texas, operators thought shales were one big blanket of rock. You could basically poke a drill hole into any part of the formation and get more or less the same result. (Stock Promoters still believe that!)

This turned out to be completely wrong. While shales are blanket formations that extend for hundreds of kilometers, they have lots of local variation—thickness, amount of sand, and natural fracturing of the rock.

Operators soon realized that placing a drill hole in the exact best part of a shale could make the difference between a three-month payback and a completely uneconomic well.

The problem was there was no way to tell from the surface where these sweet spots might be. Drillers needed a way to know what the drill bit was “seeing” as it moved through rock—and then react by steering the well into the most favorable location.

Luckily, this need for better downhole tools came just as technology was making some critical leaps. The result is that drillers today can collect very accurate, real-time information on the exact path of a well. That’s critical if you’re trying to steer a drill hole through an eight-foot think layer of shale.

More Information Means Better, Cheaper Wells

Shale drilling also pushed drillers to develop a bunch of other tools for collecting downhole geological information. Today, geophysical tools like gamma ray and resistivity meters are all “looking” into the rock around a wellbore as it’s drilled—and transmitting real-time information back to the drilling engineer.

Drilling technology is in fact getting so good that it may make some parts of the exploration process—like seismic—redundant.

That’s incredible—revolutionary even—as almost all E&Ps collect seismic before drilling begins. But the American Association of Petroleum Geologists recently forecast the industry is not far from being able to run “seismic while drilling”, where downhole tools collect seismic data while the well bore is being driven through the formation.

Using this information, drillers can spot—for example—sandy sections within a shale. And steer toward them, or away from them, depending on the best completion techniques known for that particular formation—that’s known as “geosteering”.

Engineers today thus have a lot more data to look at while drilling a well. In fact, initially there was more information than most professionals could interpret on the fly.

That’s led to the development of sophisticated computer modeling techniques. Software packages that combine all of the data coming from the downhole tools into a comprehensive model of the target reservoir. Updating every few minutes to show drillers exactly where the well is—and what rocks and other geologic features lie ahead.

Drillers have made a quantum leap in using such technology over the past few years. Where they used to fumble, they’re now capable of threading a well bore through thin, complex rock layers to pinpoint oil and gas pools.

The accuracy of this technology and technique also means quicker drilling. Which is key when expensive drilling equipment is sitting on a lease. Less time drilling means much lower well costs. And it’s this productivity from the services sector that’s ultimately made North America the only spot on Earth where shale drilling is economic.

What This Means for Offshore Development

Which brings us back to the offshore environment—and the revolutionary changes going on there.

Smart offshore operators looked at the developments happening in shale and realized that applications like geosteering and logging-while-drilling are perfectly suited to a place like the shallow-water Gulf of Mexico.

That’s because much of the oil here is hosted in an array of thin sand layers, stacked on top of each other. In the past, only the thickest of these reservoirs were targeted for production.

But all of the new drilling technology—and the skill of drillers in interpreting information from it—has opened up new options for skinny pay zones. It’s now possible to run a horizontal well through a sand that’s only a few feet thick, keeping the well within the formation, and allowing for an effective completion.

For the moment, only a select few operators are taking this game to the offshore. After all, the well costs here—even in shallow Gulf Shelf—are several times higher than in the onshore. Today, only the most skilled engineers are willing to take that risk.

But the moves are paying off—unlocking millions of new barrels in proved reserves for pioneering E&Ps. This is oil we always knew was in the ground—but no one thought would ever be produced economically.

Thus drillers here are essentially turning nothing into something. And from the look of returns on recent wells, that something might be the biggest play to come along globally for decades.

As mentioned, this revolution is beginning in the Gulf of Mexico. But where else might it soon spread?

Signs are already emerging that places like Asia and the African coast could be the next step for the offshore revolution.

In the third and final part of this series, I’ll look at where in the world investors can expect big profits next from offshore unconventional drilling.

From Dave Forest, Contributing Editor

Investing in Offshore Oil Production: Unconventional Drilling Emerges

By
Keith Schaefer
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0

With so much excitement over U.S. shale plays lately, it’s hard to justify why investors should be looking anywhere else in the oil and gas space.

After all, what other sub-sector offers the kind of big production and returns enjoyed by unconventional shale drillers?

But there’s a fundamental shift in value underway in the oil and gas space. One that savvy stock buyers are now moving to get ahead of.

It all has to do with share prices. Just look at the chart below from Deutsche Bank—showing how multiples for onshore stocks like shale explorers (orange line) got notably richer in 2013, as compared to their peers offshore.

offshore mulitple spread

Source: Deutsche Bank
Offshore E&Ps have been all but abandoned. Leaving their share prices to lag the overall sector.

And those low valuations are starting to grab attention—at least amongst energy insiders. Pros attracted not only to the cheap assets here—but also the potential for big production adds on the back of emerging technological developments that are revolutionizing offshore development.

Insiders like Fieldwood Exploration, who this past October paid $3.75 billion for a package of GOM properties this September. Purchased from oil major Apache—part of a strategic directive by that firm to exit the Gulf.

And just this month, Fieldwood took another step into the GOM—paying $750 million for a portfolio of properties from SandRidge Energy. Establishing this upstart firm as the largest asset holder in the Gulf—now producing 125,000 barrels of oil equivalent per day here.

Now, you’ve probably never heard of Fieldwood. It’s in fact a brand new company. But the people behind it are some of the biggest names in the energy business.

The firm is backed by funding from major energy private equity outfit Riverstone LLC. A well-heeled group whose partners include former BP chief Lord John Browne and former Anadarko CEO James Hackett.

Seeing these players going after Apache’s GOM assets is intriguing. And a little perplexing. After all, the Gulf is thought by many to be a play on the decline—with output having fallen nearly 25% over the last four years, to just 1.3 million barrels per day. Certainly not as exciting as the shale revolution that’s happening onshore.

The properties that Fieldwood shelled out billions for aren’t even in the high-impact deepwater. They’re in the shallow Continental Shelf. An area where most of the major discoveries were made a half-century ago.

Why would the world’s top energy minds stump up such a huge sum for picked-over project acreage?

The answer lies in some recent—although little-reported—developments on the Shelf. The kind of undercurrents only oil insiders are watching. For the moment.

Insiders like Riverstone’s James Hackett. An industry pro who has worked the Shelf as head of a succession of major Gulf players—Anadarko, Devon, and Ocean Energy.

Knowing the Gulf like no other, Hackett has undoubtedly been following the work of some of his old compatriots—at emerging oil producer Energy XXI (Nasdaq: EXXI).

Energy XXI has been a big—although very quiet—success in the Gulf the last several years. The company started with a blind $300 million raise on the AIM in 2005, and then began acquiring assets in the Gulf. Picking up fields from groups like ExxonMobil and Pogo Producing Co.

Eight years later, Energy XXI owns five of the fifteen largest oil fields on the Gulf Shelf, holding a combined 1.6 billion barrels of crude.

Conventional wisdom however, is that most of the oil left in these aged fields will never come out of the ground. The easy-to-produce crude has long been pumped. Leaving behind only table scraps—not the sort of thing you could build a significant production base around.

But Energy XXI’s results defy these doubts. As the chart below shows, the company has increased proved reserves at its Shelf fields by nearly 200% since taking them over.

reserves growth

Source: Company filings

How is such growth possible in a “played out” area like the Shelf?

The answer is simple: unconventional drilling.

Look at the quantum leap in Energy XXI’s reserves during the last year. The company’s proved reserves surged almost 50%, or nearly 60 million barrels of oil equivalent. Reserves value also leapt by 50%–to over $6 billion.

That jump coincides with the company taking a revolutionary tack—becoming one of the first companies to drill directional wells, AKA horizontals, into big GOM oil pools.

Horizontal drilling has a number of advantages. As the diagram below shows, horizontal wells put more well bore in contact with the reservoir formation. Meaning it’s easier for crude to flow into the well than with a conventional, vertical hole.

horizontal program

Source: Energy XXI corporate presentation
This means bigger production rates. With Energy XXI seeing initial production of approximately 1,500 b/d from its recent directional wells.

But horizontal wells don’t just pull crude out of the reservoir faster. Early results suggest that this advanced drilling will ultimately produce more total barrels out of the aged fields here. Creating billions of dollars in new reserves.

Look at some of the numbers. Recovery rates for crude oil pools in the Gulf have historically run about 45%. Meaning that more than half of a pool’s oil in place was left behind when operators plugged and abandoned a well.

Management at Energy XXI believes that its current drill campaign will increase recoveries by 5%. You can see the difference in the production curve below—from one of the company’s recent presentations. The red line at the right represents the forecast production curve using traditional drilling techniques. The black line above is the improved production profile from horizontal wells. And the shaded area in between is the increase in total recovered reserves.

year-over-year

Source: Energy XXI corporate presentation

That extra 5% recovery makes a big difference when you’re talking about oil pools containing billions of barrels in place. A 5% increase in recoveries across Energy XXI’s Gulf holdings equates to at least 80 million additional barrels.

And that 5% is just the company’s initial target for recovery increases. As management learns more about the effects of advanced drilling on the reservoirs here, they believe recoveries can be taken even higher. Potentially unlocking hundreds of millions of new barrels—on their properties alone.

Applied across the Gulf, such advanced technology will add billions of barrels in new reserves. At very low discovery costs (we know the oil is there, we just need to poke better holes in it). During the past year, every $1 that Energy XXI spent on development created $2 in proved reserves. A phenomenal performance.

These stellar results beg the question—why have drillers in the GOM waited this long to apply horizontal drilling?

The answers lies in some recent revolutions in drilling technology. Techniques that are unlocking the old Gulf oil plays in ways few investors have realized. Yet.

By Dave Forrest, Contributing Editor

In Part II of this series we’ll look at exactly how this drilling technology works—and where it will create the next major investment opportunities in the “new” offshore oil industry.

My 2014 Outlook for Oil & Gas Stocks

By
Keith Schaefer
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0

by +Keith Schaefer

In part one I wrote about the 3 oil patch sub-sectors I’m most bullish on, and how I’m trading them: refineries, oilfield services, and heavy oil producers.

Today, my outlook for the remaining oil and gas sub-sectors—from best to worst…

LIGHT OIL PRODUCERS

Here’s the dilemma with them: improvements in fracking are enabling a lot more production—so much so it’s dropping the light oil price. But the technology is also dropping the break-even price of said oil—so I don’t think cash flows will drop as much as people think. At first. ;-) — let’s see just how far the oil price drops.

But the Street doesn’t care, the Hot Money is leaving the producers—pricing in cheaper oil.

Look at two big US producers’ stocks—EOG-NYSE and PXD-NYSE. They peaked just as refinery stocks bottomed, and they have been moving against each other ever since—which makes perfect sense. But the international US producers like Exxon (XOM-NYSE) are still at or very, very near their highs.

The Street is steadily pricing in a big drop in the light oil price—expected to happen no later than Q1 2015—when all the imported light oil is squeezed out of the Gulf Coast Refinery Complex. That has been the relief valve for US light oil prices, as production surges.

CANADIAN CONDENSATE

Condensate prices are about $6/barrel below WTI in Canada (or $88/barrel), vs. Canadian light oil being $16 below WTI now (or $78/barrel).

That makes condensate the most valuable/profitable hydrocarbon up in The Great White North. In the US it is mainly produced as a byproduct of oil in the Eagle Ford formation in Texas. In Canada it is produced with natural gas out of the Montney formation on the Alberta BC border.

Condensate is a very light oil—so light it’s a gas underground—that has a lot of uses, but the main one in North America is to dilute heavy oil from the oilsands so it will flow in a pipeline.

And with two multi-billion dollar oilsands projects announced in November totaling 200,000 bopd, I expect demand for condensate to stay strong. Alberta produces 125,000 bopd of condensate now but uses 300,000 bopd.

Enbridge announced a $1.4 billion pipeline to import US condensate from the Eagle Ford up here. And production out of the Duvernay and Montney continues to ramp up fast—but from a low base. So I see the condensate producers in Canada actually having the best relative fundamentals in the North American market.

That’s not helping the stocks of the junior condensate producers in Canada—even though condensate pays for the well and the associated natural gas has close to a zero cost base—or less—investor interest is leaving this sector despite wells that pay out in just months—even with a very low natural gas price.

Again, there is the paradox of good fundamentals but declining investor interest stalling these stocks.

CANADIAN LIGHT OIL PRODUCERS

Canadian light oil producers will likely have the worst relative oil fundamentals. Canadian oil has dropped from $100-$77/barrel in a hurry.

The Market believed moving oil by rail would radically reduce Canadian oil price discounts this year, but Canadian light oil is tracking the Bakken oil price, or a few dollars below it (about $2.50/bbl below at time of writing). So Canadian oil has the lowest price and the highest transportation costs to refineries.

Personal feedback I’ve received from oil and gas marketers in Calgary—the guys in charge of selling the physical commodity for the producers—suggest the Canadian “diffs”—the difference between US and Canadian oil prices—will stay for at least another 2-3 months.

I shaved a lot of my positions in Canadian producers on the first Friday in November.

U.S. NATURAL GAS STOCKS

Natural gas production from Pennsylvania’s mammoth Marcellus formation continues, and more infrastructure is getting put into place to get the gas to market.

And right behind that is the neighbouring and overlapping Utica Shale. And right behind that could be New York allowing fracking and start drilling the Marcellus there. Get the picture?

At least 600 million cubic feet of gas (mmcf/d) has recently come onto the market from the Marcellus, and 2 billion cubic feet (bcf) is coming online throughout the winter.

October will almost certainly have set a new all-time monthly record for US dry gas production—over 67 bcf/d. (The latest official stats are from August.) So right now I don’t see any increase in fundamentals for US gas producers—just continued improvements in fracking that lower the cost of production, and of course—Old Man Winter.

Without him—at his fiercest—the next shoulder season of Spring 2014 could get really ugly again for producers; US gas could be back below $2/mcf.

Even the best natgas stocks in the US—like Cabot Oil and Gas (COG-NYSE), which is the big Marcellus player—are dropping now when the onset of heating season says they should be going higher.

Natural gas prices in the US are all about the Marcellus shale formation in Virginia/Pennsylvania/New York.

It’s gone from 2 bcf/d in 2009 to 12 bcf/d today. Until Marcellus production flatlines for three months, you don’t need to worry about natural gas prices moving up. But every other natgas basin in the US is declining, so when that does happen, GET LONG GAS.

INTERNATIONAL OIL STOCKS

Probably the biggest paradox of all—North American listed international oil stocks have very low valuations—1-3x cash flow—despite great fundamentals—i.e. Brent pricing; especially expensive, high capital projects like the North Sea.

CANADIAN NATURAL GAS STOCKS

A hedge fund manager friend of mine said, Keith, you can’t separate out Canadian natural gas stocks from condensate stocks—they’re really the same thing.

And he’s right to a very large degree. There really is no such thing as a Canadian natural gas producer anymore—except for Peyto (PEY-TSX) and Tourmaline (TOU-TSX). You’re either a condensate producer or oil producer with natgas as an associated byproduct.

In Canada, the only reason you’re drilling for natgas is because it’s really a condensate or an oil well—those are the two commodities that pay for the well.

Canadian producers have the same problems US producers do, only worse—they’re being displaced by Marcellus gas. AND ironically, natgas prices in Canada are being LOWERED right now because of LNG—Liquid Natural Gas.

The Market sees a lot of excess Canadian gas in the coming years as drilling ramps up for LNG exports off Canada’s west coast. But until exports actually happen, that glut of gas being drilled is now being priced into the market at a much greater than normal discount to US gas in the futures pricing.

Normally natgas in Canada trades 50 cents/mcf below the US in summer and 30 cents below in winter. But now strip pricing is calling for 60 and 80 cent discounts in the coming two years.

There you have it—my favourite subsectors from first to worst.

– Keith

 

Investing in Oil Refinery Stocks: Trading the Spread

By
Keith Schaefer
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by +Keith Schaefer

There’s always a bull market in energy—you just have to know which sub-sector to buy.

So where do my subscribers and I make money right now? You might be surprised by the answer…but first some context…

In Q3 2103, oil producers in North America were the place to be, as higher international oil prices (Brent) dragged the North American price (WTI) up.

Another big factor in Q3 was the sucking sound of new pipelines moving the oil logjam from Cushing, Oklahoma (where WTI is priced) down to Houston.

Now, in Q4, the sound of autumn leaves being crunched is actually the institutions rolling out of producers… and into refiners.

That’s the Market all of a sudden waking up to the huge production increases coming out of the Bakken, Permian, Eagle Ford and Wattenberg oil plays.

Refinery stocks are soaring this week.

So let’s have a quick look at the various sub-sectors of the North American energy complex, and see where investors should be putting their money (and I’m going to go from first to worst):

1. REFINERIES

The investment case here comes down to one simple fact.

The US cannot export crude oil, but they can export refined products.

That means all the new light crude coming out of the tight oil plays (READ: shale) is hostage to the limited light oil refining capacity in North America.

And as domestic light oil replaces the last drop of imported light oil—which should happen sometime in the next 15 months—light oil will drop in price. It is dropping in price right now in anticipation of this.

But geopolitics—and a tighter oil market—is keeping Brent high.

And the US is now exporting 3.5 to 4 million barrels a day of refined products. Americans have to compete with foreign buyers for their own driving gasoline, home heating fuel, jet fuel, etc.!

And all those foreign buyers are willing to pay Brent based pricing for refined products. The profit for refiners is the spread between that cheap domestic crude and the expensively priced refined fuels they sell. And right now Brent is $19 above WTI, and $30 above Bakken light oil.

A couple things could ruin this trade—a Presidential exemption to export oil (good luck with that), Brent prices also falling a lot, or US oil demand increase a lot.

There are no pure play refinery stocks in Canada; you must invest in US independent refiners to play this trend.

2. OIL FIELD SERVICES (OFS) SECTOR (also called Energy Services)

I believe North America will continue to get drilled like Swiss cheese, for both oil and gas.

So that should be good for the services sector like drillers and frackers and other supply chain companies to the drillers and frackers.

The charts of the big integrated OFS companies—Halliburton (HAL-NYSE) Helmerich & Payne (HP-NYSE) look great.

Other stocks like Nabors and Schlumberger (SLB-NYSE) have just come off year highs.
There’s not a lot of pricing power in OFS now however—except for one sub-sub-sector—and they have great charts—but you have to be a paid subscriber to my service for me to tell you what they are ;-).

3. HEAVY OIL PRODUCERS

Heavy oil producers should fare better than the light ones. That’s because there is a lot more heavy oil refining capacity in the US than light oil.

BP’s big Whiting refinery in Illinois is supposed to be coming online in January, increasing heavy oil throughput from 85,000 bopd to 350,000 bopd—that’s a lot more demand!

Heavy oil actually traded at a premium to light oil in the Gulf Coast some days this year. And when Devon Canada put their assets up for sale this week, they kept the heavy oil assets.

As I said, though, the Hot Money is leaving the producers—pricing in cheaper oil.

– Keith

P.S.  Here’s Part 2 of my 2014 Outlook for Oil & Gas Stocks… which rank all the sub-sectors from best to worst — plus you’ll learn where I’ve shaved a number of positions in my portfolio.

 

Top Ten Oil and Gas Deals in Canada 2013

By
Keith Schaefer
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Top 10 OandG deals in Canada 2013

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