Colombia Oil Stocks: Time To Invest Once Again?

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1940bkg
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Two years ago Colombia was the hottest international oil play in the world (for Canadian investors), with big wells creating big valuations and stock runs that left investors hungry for more.

Now, these stocks have not only fallen to earth, they’ve crashed through the floor into the basement—despite good oil prices.

What happened? And more importantly, is this an opportunity for investors?

The opportunity answer is… almost, says Fred Kozak, former oil and gas analyst at Canadian brokerage firm Canaccord Genuity, and now an independent.

“Colombia still has FARC issues, environmental permitting is still a big problem and pipeline constraints are all impacting the investment climate,” he said in an interview.

FARC is the Spanish acronym for the left wing guerrilla movement in Colombia.  Former President Alvaro Uribe was able to secure billions of dollars in US aid in the last decade, which was used for the military and other means to reduce the FARC’s impact on the country.

With the FARC risk down a lot, foreign investors felt secure in investing billions of private capital into the country’s energy sector—especially the upstream oil and gas producers.   The Canadians were VERY active, led by companies like Frank Giustra’s and Serafino Iacono’s Pacific Rubiales (PRE-TSX) and John Wright’s/Corey Ruttan’s Petrominerales (PMG-TSX).

Both companies were very successful developing assets in the Llanos Basin in the middle of the country, and both had GREAT stock runs—PRE went from $2-$34 in 2009-2010, and PMG went from $6-$40.

(Rubiales was the very first stock pick for paid-up OGIB subscribers in 2009 at $9/share, and I also rode PMG from $11-$33/share during that time).

There was a perfect storm of exploration success, a lower royalty rate, and the sense that this under-explored country could continue its string of high profile discoveries for years.  Promoters created new junior exploration companies with bloated share counts—hundreds of millions of shares out—and investors still ate it up.

But now?  In what I would call the senior Colombian stocks—Rubiales, Gran Tierra—they’re just above 50% of their highs, and the rest are anywhere from 20-50% of their highs.  Those second round of bloated share count juniors quickly lost 80% of their value, and have only recently popped their head up.

Did anybody get the license plate on the truck that ran over these stocks?

It was actually several trucks, says Kozak.  He says one of the big factors hitting these stocks was the Arab Spring of 2011—all international juniors the world over sold off after institutional and retail investors lost their appetite for foreign risk, as dictators got toppled one after the other starting in early 2011.

But sadly for everyone, FARC violence has increased this year.  After several years of declining activity, brokerage firm Raymond James reports in an Aug 13 report that  has been a “material” increase of security incidents reported since the beginning of the year. Pipeline attacks increased 3 fold year-over-year and 5 Ecopetrol contractors were killed in Putumayo this summer, near the Colombian/Ecuador/Peru border.

The FARC attacking pipelines doesn’t help an already difficult situation — increased oil production in Colombia has strained pipeline capacity.

“As much as 100,000 barrels a day of oil production (bopd) could be shut in, I’m not exactly sure, but it means that you have to truck oil,” says Kozak.

This means higher transportation costs, and companies can’t produce new discoveries at full throttle. In a negative market, this is deadly to a company’s share price.

Colombia’s daily oil production currently exceeds 900,000 bopd, having risen more than 60% since 2006, but pipeline constraints have not allowed it to crack the magic 1 million bopd mark.

Producers in Colombia are also experiencing long delays in permitting.  Wells are not being drilled as fast as before as companies are left waiting for up to a year without knowing when they’d be able to drill.

This has hurt exploration activities, and several of the leading Colombian juniors are now spending a big chunk of their exploration in Brazil, Ecuador and Peru—and sometimes even farther afield.

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This Stock Has DOUBLED for OGIB Subscribers…
And It Could Be the Next Big Junior Buy-Out Target

Exceptional drill results — one set after another — have validated my favorite junior oil company (to the tune of triple-digit gains, since January 2012).

But it’s not just the great success of its new core plays that has me so excited.

It’s the fact that they have only drilled a few wells in each one. There are still hundreds of wells left.

So, not only are there A LOT of gains still on the table, but it makes this junior my top takeover target for the rest of the year.

Plus, analysts just upped their price targets —so they almost match mine.

Click here to get my original research on this break-out trade, risk-free.

—————————————————

Another factor, Kozak adds, is that the new discoveries in Colombia just aren’t coming as quickly as they did a couple years ago.

“Colombia had great success at one point—but today look at Petrominerales PMG-TSX and GranTierra Energy GTE-TSX —PMG is now struggling while GTE is focused on developing discoveries. New discoveries are still limited.”

Colombia reported that 34% of all wells were successful in H1 2012 vs. 48% average from 2008-2010.

Canadians formed a big part of the foreigners that entered into the Colombian oil and gas sector in 2008-2009. I asked Kozak why that was, and he answered:

“We in Canada are entrepreneurs.  We have so many teams chasing so many opportunities and recent success with our “resource plays” here has been technology related.  Then guys say, hey, we can apply that somewhere else. We go apply our best practices and use our technology and turn things around.”

The Canadians focused on the Llanos basin which looks geologically a lot like Alberta’s foothills (light oil) and the Putamayo in the south which is similar to Alberta’s plains (heavy oil).

Colombia is one of a few countries in South America where you could go into the country and do business a lot like you would do in the west. The country is out of favor right now but Fred believes the question is when do you invest in the country, not if.

“With $100 Brent oil, you have $60-$70 netbacks—you can make phenomenal money in that country, but there are short term issues.”  Kozak says these short term issues reflect growing pains as the oil and gas sector continues to mature.

“Success is responsible for the delays we’re seeing now—Colombia redefined its fiscal regime to attract new investment and kicked FARC out of most of country since President Uribe started his 2nd term in 2006.”

Recently, the army has increased its size and activity in the oil producing regions, improving security. This may lead to an improved perception regarding security in 3-6 months.

Permitting times have been slowly improving—the government is adding more people here as well. This should allow several companies to carry their plans of drilling high impact wells in the second half of 2012.

A new pipeline starting in Q1/13 is expected to carry more than 490,000 bopd.  As that new capacity becomes imminent, it could be a huge catalyst for Colombian juniors.

An intriguing potential catalyst will happen sooner, however. The government has a new bid round in October for 115 blocks including 1/3rd for shale exploration in the Magdalena Basin.

Says Kozak: “There have been a number of wells drilled that have seen shale but nothing like western Canada. Remember that the drilling density in this part of Colombia is a fraction of what North America is used to. Both Exxon and Shell are scheduled to drill a well each on Canacol (CNE-TSX) farm-in lands, but depending on the bid round results in October, those results are not likely to be a 2012 catalyst.”

Kozak concludes that addressing the country-specific risks will help (FARC, permitting delays, pipeline constraints) but the tide that would lift all boats requires the risk on trade to come back.  But he says investors should not sit on their hands waiting for the tide to come in:

“There’s going to be opportunity there especially through mergers & acquisition. These companies are very cheap.  At these levels it’s almost cheaper to buy than to drill. The acquisition of PetroMagdalena (TSXC-PMD) by Pacific Rubiales (TSX-PRE) being an example.”

So how should investors approach investing in Colombian juniors? According to Fred the approach is not any different from domestic E&P juniors.

“Remember it’s always about the people.  When looking at companies to invest in, who are the people involved—and projects—how quickly can they take it to production.”

by +Keith Schaefer

How a U.S. Oil Refinery Got Saved — and a Supply Shut-Down Averted

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1940bkg
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These guys got it done.

In a few short months, they saved hundreds of jobs, increased industry profits, created some energy security for the US east coast, and set the stage to improve the environment through reduced air emissions.

They are the epitomy, the poster child, of how business, labour and government can and should work together to create solutions in the North American oil patch.

Who are “these guys?” They are the United Steelworkers of America, Pennsylvania Governor Tom Corbett’s team, Sunoco senior management, and management from the Carlyle Group, a large private equity firm.

What they did was save 850 direct, high-paying jobs at the Sunoco refinery in Philadelphia. But even more important, if this 330,000-barrel-a-day refinery closed, there was a serious supply issue for drivers on the east coast—and the industry.

They are a textbook lesson that certainly the polarized Canadian stakeholders should be reviewing in issues like the Northern Gateway oil pipeline from Alberta to the Canadian west coast.

And if the American stakeholders around the Keystone pipeline could work together like this, there would be environmental and economic security—and commerce would flow.

What’s surprising to me is that this monumental feat of consensus got only one day of media attention in the US. I interviewed several people involved in the negotiations to get a sense of the attitudes, the friction points, and the lessons that this issue brought to the oil patch. Here’s how it got done:

Last September when Sunoco and ConocoPhillips announced they would each be closing their Pennsylvania refineries, it seemed like a dark day for energy in the Northeast.

The facilities — Philadelphia and Marcus Hook for Sunoco, Trainer for ConocoPhillips — not only kept the region supplied with the fuel it needed… but they accounted for hundreds of direct jobs. The closure of these three refineries would have led to increased unemployment figures and rising fuel prices.

September 2011 to July 2012

When the United Steelworkers (USW) heard of Sunoco’s announcement to shutter the refineries if buyers couldn’t be found, they sprang into action. Letters were written to politicians and officials to call attention to the situation. After all, it could cause a huge negative impact on the region.

By October, Democratic House Leader Nancy Pelosi had mentioned the closure of the refineries at a White House briefing. But the USW didn’t let the issue fade away and kept up its tireless campaign to raise awareness among the country’s top decision makers. In January, Gene Sperling, President Obama’s top economic advisor, was involved in the process.

The end of February saw a report from the U.S. Energy Information Administration come out that confirmed many people’s fears:

The Northeast’s fuel situation would be in dire straights if the refineries were to be shuttered.

In March, Sperling organized a conference call with newly promoted Sunoco chief executive officer Brian P. MacDonald, who had previously been the company’s chief financial officer.

As it turns out, that call was a major turning point in keeping the Philadelphia refinery—with its 330,000-barrel-a-day output and its 850 direct jobs—open, according to The Philadelphia Inquirer. During that call The Carlyle Group was identified as a possible buyer for the facility. In addition, the government gave assurances to MacDonald it would do whatever possible to allow a deal to get done.

David M. Marchick, Carlyle’s managing director for external affairs, touched on a point that would be echoed by all sides in the matter when he told The Inquirer, “This is a rare example of federal, state and local officials, business and labor, Republicans and Democrats, all coming together for one common purpose.”

In April, Sunoco announced that it had established an exclusive sales negotiation agreement with Carlyle, and by July the two companies said they would form a joint venture called Philadelphia Energy Solutions, which would keep the plant open. Just days after, USW ratified their contract with a near unanimous vote.

And so, the Philadelphia refinery was saved.

How the Labor Union Saved a Shut-Down

The news of the refineries closing last fall went largely unnoticed by the national media, but it was obviously big news to the USW. And they worked hard to get it on the political agenda—including a candlelight vigil at Pennsylvania Governor Tom Corbett’s mansion.

Lynn Hancock, a USW spokesperson, says that if not for the union, the plant would have been shut down.

“If these facilities had been non-union you wouldn’t have seen this kind of campaign. They probably would’ve been shut down by now,” she said.

Bringing together the stakeholders and the government was an important step, but that didn’t guarantee that a deal would get done.

Hancock said that she knew Carlyle was serious about its offer when they wanted to talk to the union.

“When I heard that they were going to meet with the local union, 10-1, leaders I knew that this was moving and there’s a good chance it was going to result in a sale,” she said.

And when Carlyle and the union did meet to talk about the workers’ contract, both sides worked together to get something done. Ultimately, a three-year contract was negotiated that gave the union a 2.5% raise the first year and a 3% raise in years two and three.

In exchange, the union would give up its defined-benefit pension plan for a 401(k) and allow some union jobs to be performed by contractors.

These negotiations are another example of the cooperative theme that permeated the whole campaign and talks about keeping the facilities open. Hancock emphasized what can be done when business and labor get together:

“It shows that a lot can be accomplished when business works together with its unions. Instead of seeing them as adversaries they should see them as helpmates in improving things and in making businesses stronger,” Hancock’s spokesperson reported.

Private Industry’s Part

When Brian MacDonald became the CEO of Sunoco in March of this year, it marked a turning point in the process. Hancock said that MacDonald’s involvement was vital in getting a deal done.

After his meeting with Sperling, MacDonald left a message for Carlyle Managing Director Rodney S. Cohen, who had previously helped save a refinery in Kansas. Having someone with previous experience was likely a big plus in the deal.

After several weeks of negotiations a deal was struck to create a joint venture that would see Sunoco get a one-third, non-controlling stake in the venture, and Carlyle would get control of the 1,400-acre facility. In addition, Carlyle will receive $25 million in state funds to match its $200 million investment in upgrades to the plant.

MacDonald said that the joint partnership was an example of across-the-board cooperation.

“This partnership is a great example of what can happen when motivated people think creatively to solve pressing problems,” he said. “The private sector, government and labor all played important roles in getting this done. This is the best possible outcome for everyone involved: existing jobs will be saved, new jobs will be created and new business opportunities will be given the chance to develop.”

Still, some key technical concerns remained in order for the partnership to succeed. One of the key questions was:

Where would oil come from for the refinery?

Typically refineries in the area have relied on expensive, imported Brent crude.  But Carlyle’s investment will open the door for the light shale oil from North Dakota—the Bakken formation—to be shipped in.

Carlyle officials said that plans are in place to connect the facility to the west through a high-speed train unloading facility, which could reportedly handle 140,000 barrels a day.

The Pennsylvania Department of Transportation will reportedly be contributing about $10 million to the effort to extend the rail lines. Dennis Buterbaugh, a spokesman with the Pennsylvania DOT, said that more details will emerge in the coming weeks once Carlyle’s application comes through.

The Bakken won’t be the only play that will be a part of this venture, as the Marcellus shale will also be involved. Carlyle said that it plans to use natural gas from the formation to power the refinery, and also said it would explore the possibility of liquid natural gas at the plant.

Government’s Part

Many prominent politicians including Governor Corbett, U.S. Representative Bob Brady and Philadelphia Mayor Michael Nutter were involved. What was impressive about their efforts is that no one took the opportunity to try to get a political “win.”

Corbett, a Republican, decided that even if this project would be good for the Democratic White House in the upcoming election, he would not let so many of his constituents lose their jobs.

“Obviously, if you take it from a political perspective, this is important to the White House. They’re going to be able to count this in an election year… Working together and getting this done was a lot better than seeing this facility shut down,” he said.

Support from these high-level lawmakers was an important factor in the refinery being saved but there was also a great deal of behind-the-scenes effort from local officials and government employees—like Mike Krancer.

Krancer is the secretary of Pennsylvania’s Department of Environmental Protection (DEP), part of a team put together by the governor in December to evaluate what could be done to save the refinery.

Krancer said his job was to make sure all the stakeholders knew the government was here to solve problems, not create barriers.

Once Carlyle was identified as a potential buyer, he said it was important they had confidence in the government to help them through any air permitting issues.

Krancer and key members of his team had spent a large part of their career in the private sector. He said that he knew what it is like to work with stubborn government officials who have no interest in solving problems. By bringing a “can-do” attitude to the table, Krancer helped give Carlyle the confidence it needed to make the investment.

One of the technical keys that made this deal viable for Carlyle, Krancer said, was bringing in Bakken crude, which is lower in sulfur than many other crudes. This light oil leads to lower emissions, so it was a win-win for both the environment and economics.

Another state agency that was on Governor Corbett’s task force was the Department of Community & Economic Development.

Steven Kratz, the department’s press secretary, said that one of the keys for the government’s success in this situation was that it was extremely active, but not visible. This allowed strong bipartisan cooperation within the government.

Kratz said that the project was a “terrific example of … coordination within state government” and a “great example of all levels of government working together.”

While the deal is not yet finalized (that is expected to happen in the third quarter), the example of the Philadelphia refinery should be held up as what can happen when the private sector, labor and government put their heads together to solve energy problems.

by +Keith Schaefer


 

Waterfloods: The Next Big Profit Phase of the Shale Oil Revolution

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1940bkg
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Dear OGIB Reader,

The cheapest and most profitable oil North America has ever seen is now “flooding” into the market, as producers once again use old technology to create a wave of new profits.

Producers are using “waterfloods”—pushing water into underground formations to flush a large amount of oil out to nearby producing wells—to increase production and profits. It’s the next big money-making phase of the Shale Revolution.

Waterflooding has been around for 70 years or more, but the Big Question over the last five years has been—can you do it effectively with tight oil?

The answer is a Big Yes, and waterflood potential has become so important that institutional investors now see them as major share price catalysts for junior producers—and track them closely.

Waterfloods start 1-2 years after drilling the well, in a time window producers call “secondary recovery.” (Drilling is primary recovery.) Waterfloods are cheap to try and cheap to run (with most operations costing just $5-10 per barrel!), and now the industry is seeing that they are sometimes doubling reserves from a well.

“Secondary recovery is where you really make all your money in this industry,” says Dan Toews, VP Finance and CFO of Pinecrest Energy (PRY-TSX.V).

Pinecrest is very vocal about their waterflood potential. They say they can double the amount of oil they recover (called the Recovery Factor, or RF) from a well—at less than $15/barrel—half the price of primary recovery costs, which are over $30/barrel.

 

“Everyone is trying to find a new resource play,” says Toews. “First you find a resource, and then you drill it like crazy. But the second stage is to go in for your secondary recovery, through waterflooding of some kind if possible.”

To date, Pinecrest isn’t yet flowing even one barrel of waterflooded oil—so their powerpoint slide is just projections. Toews and his team expect to be waterflooding all of their operations by the end of this quarter. But analysts are already seeing the waterfloods as a share price catalyst.

“Just about every investor and institution we talk to wants to know the status with our waterfloods,” says Toews. “The buyside (fund managers= buyside, brokerage firms=sell side—ed.) is very savvy on waterfloods. Once we apply the method, this is what has the potential to shoot up our share prices.”

Realistically, the effects can be seen within 2-3 months, but it’s best to give them a year—or more—of operations before judging their impact. Waterfloods can last up to 20 years or more.

Another Canadian oil junior, Raging River Exploration (RRX-TSX), also explains the waterflood potential in their powerpoint. They expect to be swimming in 1 million EXTRA recoverable barrels of oil per square mile, courtesy of waterfloods—at an even cheaper cost of $5-10 barrel, vs $30 barrel for the first 600,000 barrels.
Raging River is developing the Viking formation in SW Saskatchewan—a large, tight oil play that since the 1950s has had an improved outlook from 2 billion barrels of oil to an estimated 6 billion barrels of oil in place, all thanks to horizontal drilling.

Raging River expects waterflooding to increase its RF from 8% from primary recovery methods (drilling vertical and horizontal wells) using 16 wells/section, to 16-20%. The simple math says that will increase the number of barrels recovered from 480 million at 8% to 1.25 billion at 20% RF.

If Raging River—or any producer—can show a steady RF for over a year, I would suggest to investors those barrels will be worth $10-$15 each—creating huge value to shareholders on a buyout.

Some Viking waterfloods have even seen results as high as 30% RF.

“A small change of recovery over a large oil field is significant and adds a tremendous amount of value,” says Scott Saxberg, President and CEO of Crescent Point Energy (CPG – TSX), arguably seen as the industry leader in the waterflooding revival.

“A lot of these unconventional plays (tight oil) are in high decline. By implementing waterfloods, we can lower the declines in the field, and increase reserves. There’s huge value to that.”

Crescent Point started waterflooding its properties five years ago when multi-stage fracking (MSF) was new on the scene. Now they have five years of knowledge that the method works, and that they can use it across all of their fields.

“We recognized right away to implement a strategy to increase the recovery factor on a multi billion barrel pool,” says Saxberg. “If you change even 1%, that ends up being huge.”

“Waterflooding is the next step past in-fill drilling (ie. drilling more holes in less space to increase ultimate recovery). It takes a lot of time to accrue knowledge and data on how to properly implement it. The sooner you start, the better data you have.”

According to Saxberg, waterflooding is more than just a cheap way to float balance sheets.

Over the course of Crescent Point’s five-year waterflooding program, they’ve developed hundreds of different combinations of waterflooding techniques coupled with fracking techniques, well spacing and plenty of other factors.

“Water flooding is basic, in that you pump water into the ground,” says Saxberg. “So to enhance that, you have to look at what type of patterns are in your reservoir. Now these are unconventional tight reservoirs, so the question was, can they actually be water flooded?”

Again, the Big Answer is Yes, and management teams are now using the promise of waterfloods as a cheap way to float their balance sheets earlier in a resource play. But Saxberg says waterfloods are truly more long-term value.

“They are a long term day-after-day technical grind and process. So it’s not the same as drilling a well and seeing 100bbls/day. It’s a lot of ups and downs and a lot of long term view.”

There’s only one negative here that I see—how will all that cheap oil affect North American pricing, when the continent is already swimming in the stuff?

In the short term, the pro-forma economics of waterfloods are making a splash with both management teams and the market.

But medium term and beyond, it will create a quandary for juniors—the easy money comes after huge capital spending.

by +Keith Schaefer

Oil & Gas Investing Strategies for the Near Term

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1940bkg
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In Part 1 – How To Trade the Oil Markets, Canadian oil and gas research analysts Josef Schachter and Martin Pelletier explained one of the key strategies to make money in the junior oil sector—trade the volatility; learn how to read the swings.

Here, they share some of their best money-making strategies moving forward.

To me, it’s intriguing that Schachter says the future for juniors is not so much in big Resource Plays in the near term. These are the tight oil plays like the Bakken, the Cardium, the Alberta Bakken, etc. that have a much larger size and lower risk than conventional, old-style pools of oil/gas. They have been the bread and butter of the junior energy sector in North America for the last three years. Companies couldn’t get financed without one.

“There is a future for the juniors but it’s in lower cost plays.” He says stock valuations are so low now that financing with new equity (issuing shares) is too expensive and dilutive. And these resource plays have voracious appetites for capital.

“New technology is really making a difference. (High cost) Horizontal wells have increased the “ante” of playing in the fairway. The main plays are not entry level plays for the juniors anymore. It’s now a science play, and who pays for that?

“When well costs in the Montney (a high-profile, liquid-rich gas play on the BC Alberta border—ks) are $6-$10 million, and these juniors have market caps of $30 million, they can’t do it. One bad well and you’re hurting, and two bad wells and you’re done.

“You need to find lower cost plays, where well costs are $2 million all in, that produce 75-100 barrels of oil a day.

“It’s a treadmill, slow process now; it’s not a home run game anymore. (Management teams should be saying) let’s spend 70% of budget for conventional slow production build and take 10-15% for the home run swing.”

Here are his four top junior stock picks, and he warns they could get cheaper before they get expensive:

Delphi Energy Corp (DEE-TSX; DPGYF-PINK)—“It’s liquid rich, and has new Montney wells this month, and lots of runway (large area of undeveloped land with low-risk drill locations—ks), and new (production) facilities they’ve put in. They’ll exit 2012 at 9500 bopd exit, maybe 10,000. DEE will have 28% of their production in Natural Gas Liquids.”

Guide Exploration Ltd (GO-TSX; GLNNF-PINK)— “They have 30% oil and Natural Gas Liquids, heading to 40%.”

Niko Resources (NKO-TSX; NKRSF-PINK)—“Niko has a big Indonesian portfolio (they’re starting to drill) now and have a chance for resolution of some issues in India, and they’re financed for 2 years. The wells, if successful, could be worth more than stock price. Everyone hates India and they’re excessively negative. To me it has low downside and upside into $70s in a good market.”

Western Zagros (WZR-TSX)—“They’re drilling the TLM zone. They’ll test it through the summer. I’m pessimistic on the market short term, but this could outperform. It has already doubled this year. The politics are still up in the air, but pipelines in Kurdistan Regional Government will be built to Turkey and they’re protected by Turkey. All that is helpful to the story.”

Pelletier offers a different tack for investors to consider.

He says the first movers in the energy sector will be the beaten-up large cap stocks. Small caps likely have another 6-12 months of living within their means—which means slower growth, because they can’t raise money to fund expansion.

He likes to actively manage his risk in energy stocks, and suggests there are two fairly simple way for retail investors to create a profitable trade, based on their own beliefs:

“At times oil and gas stocks will factor in a premium or discount to their commodity. For example, we calculate that oil companies are factoring in a $20 to $30 per barrel discount to current oil prices.

“So if you believe that the oil market is set for a recovery, then the cheaper buy is clearly Canadian oil stocks rather than owning oil itself.

“But if you’re worried about the broader market—and in particular oil prices—then you can short the spread. That means owning oil focused companies while shorting crude oil prices through an ETF. In a falling market, both oil prices and oil stocks will fall, BUT oil prices will fall faster than oil stocks. This will give you some downside protection to your portfolio.

“So if you want to own oil, it’s cheaper to own the stocks. You can do this trade by using ETFs—on the Toronto Stock Exchange, you would buy symbols XEG (a basket of senior energy producers that mirror the TSX index–ks) or COS (Canadian OilSands) which pays a very attractive 6% dividend) and buy HOD (that’s double levered).

“Investors can also do this exercise for natural gas versus natural gas focused companies as well. For example, Encana, is now trading at  a 15-20% premium to the forward curve on gas prices.

“So if want to play a recovery in gas prices, it’s better to own the winter gas ETF on the Toronto Stock Exchange—HUN. Then you could short Encana to play the spread.”

I asked Pelletier to give readers one junior energy stock they should go do some of their own research on—and he repliedSurge Energy (SGY-TSX; ZPTAF-PINK).

“Whenever we look at a company, we break it out into 3 categories People, Assets and Value.

“This is a very technical team with strong track record of growth. This year they are estimating to increase production over 40%. Their assets are moving beyond exploration stage, so there’s more predictability going forward. And they’ve got a big incremental upside from waterflood at some properties.

“We estimate that it is trading at roughly a 25% discount to its oily peers on a cash flow multiple basis, and 20% discount on 2P reserve basis.”
by +Keith Schaefer

Disclosures: Keith Schaefer does not own any of the stocks mentioned. Pelletier’s TWC Risk-Managed Canadian Energy fund owns Surge Energy—SGY.  Schachter owns Delphi—DEE.

by +Keith Schaefer

How To Trade Today’s Oil Markets

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1940bkg
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What’s the biggest lesson retail investors need to learn to increase profits in these markets?

It’s knowing how and when to trade volatility.

The professionals say trading volatility really is the only way to make money in a flat to down market, which the energy sector (especially the juniors!) has gone through since February 2011—a full 16 months ago.

“A flat bear market can give flat performance, but with a lot of volatility,” says Martin Pelletier, Managing Director at Trivest Wealth Counsel of Calgary. “Fifty per cent to 100% swings either way are quite common.

“Unfortunately investors have reacted incorrectly—buying the tops of secular bull markets and selling the lows of secular bear markets.”

Josef Schachter, President of Schachter Asset Management Inc., says “the oil and gas sector has been good to investors—just sell during euphoria and buy during duress.”

Now of course, that’s easier said than done, and to a large degree that separates out the wealthy investors. But Schachter—who is bearish on oil for the next 3-5 months—says there are some turning points investors should look for in the Toronto Stock Exchange Energy Index.

TSX Energy Index - 5 Years

TSX Energy Index 5-year chart

TSX Energy Index 1-year chart

TSX Energy Index 1-year chart

“Given how devastated the S&P TSX Energy Index is, if it goes below 180 then it’s a great buy. We would then switch from being bears to being bulls again.

“I look at the market internals. We’re in a bounce wave now. It could go up again, but then it could go below 200 down
to 180 maybe. I expect the timing on that to be the 3rd or 4th week of October.”

Are other sectors as volatile as energy?

“From a broader perspective, if you overweighted telecom, utilities and financials you would have best risk weighted return,” says Pelletier, but adds “over the last ten years, if you were willing to accept a little more risk to get better returns, then energy is the best space to invest.”

And that means a little more active trading—even in the senior producers’ stocks.

“Just look at large cap Canadian energy stocks like Suncor (SU-TSX; NYSE) and Canadian Natural Resources (CNQ-TSX; NYSE). Both have shown a lot of volatility through the year, but there’s nothing good for those who bought and held the stock over the past 5-6 years.

suncor

“It’s been even worse for junior oil and gas have even more volatility given their greater capital demand. They typically spend 2-4x their cash flow on exploration.

“Therefore buy and holding juniors is not the way to play them AT ALL—you have to trade them to manage risk,” because when the market turns down, they can’t raise money to bridge the gap between exploration spending and cash flow—so the junior stocks get hit really hard.

The junior oil and gas market has definitely turned down—but for how long?

Schachter says, “If they (national governments) face the music (on their debt issues), we could see a multi-year bull market in energy through to 2015-2016 and set all-time highs. But if they just continue to kick the can down the road, then the market malaise could drag out with trading rallies and year end bounces, and you’ll need a trading mentality, as we’ve had a good year then a bad year.”

Pelletier believes there is another 2-3 years to go before the next secular bull market in the major indexes and energy markets—it’s a traders market until then.

But the juniors will once again have their day, says Pelletier.

“Juniors will outperform when the market returns to normality especially those with good management teams with attractive growth profiles.

“Interestingly, there is an opportunity among those who have sold off from their financings. We think these companies will be able to take advantage of this market environment and consolidate. And there are some other stories well liked among my peers which we think are attractively valued—we think it’s important to own stocks everyone likes that are backed up by strong fundamentals.”

In Part II, both Schachter and Pelletier will share some of their favourite investment ideas going into the last half of 2012.

by +Keith Schaefer

How the Shale Boom Is Causing a Drop in the NGL Price

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1940bkg
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The shale oil boom is causing a steep price drop in Natural Gas Liquids (NGLs) in North America, hurting gas producers.

Natural Gas Liquids are the raw, associated gases and liquids that come up along with oil and natural gas from the well.  NGLs are very important—vital even—now for regular, dry gas (methane) producers, as they are separated and sold as more expensive products like ethane, propane, butane and condensate.

But for shale oil producers—especially in the new prolific Texas oil shales—they’re just a byproduct.  The oil pays for the well and the NGLs are just gravy.

For the last two years, many natural gas producers have been acquiring and drilling gas plays with high liquids content. NGLs are typically valued as a percentage of crude oil prices, and are worth 2-10x what dry gas is worth.

In fact, junior Canadian and American gas producers have been desperately trying to portray themselves as “liquid rich” gas producers.  Analyst reports from brokerage firms promote their increasing NGL production.

The problem for the gas producers is—the oil producers have been acquiring and drilling them, too.

Between oil and gas NGL production, supply has overwhelmed the petrochemical industry, which uses most of these NGLs as feedstock.

Prices have rebounded from lows seen in late June, but are still down a lot from last year:

  • Ethane at 31 cents/US gallon is down 61% from last July
  • Propane at 85 cents/US gallon is down 44%
  • Butane at 121 cents/US gallon is down 31%
  • Condensate at 192 cents/US gallon is down 24%

Profitability is down even more—add another 15% to each of those numbers. (This means ethane profits are down 70% or more.)

These prices come from Mont Belvieu, Texas, which is the main pricing hub for NGLs in the US.  What Cushing is to oil in the US, Mont Belvieu is to NGLs.

Even these numbers don’t tell all the pain—some gas processing plants aren’t accepting ethane at all, which of course lowers the price to crazy levels—the 2nd NGL hub in the US, in Conway Kansas, has seen ethane prices fall to 8 cents a gallon.

Here’s a rough guide on these products.

The “C2” type number you see beside each entry is how many carbon atoms a molecule of each product has, and the industry interchanges the names Ethane and C2 (Propane and C3 etc) all the time.

Ethane (C2) – Demand is primarily driven by the ethylene production industry, which uses ethane to meet nearly half of its feedstock needs to produce chemical compounds used in making plastics.

Propane (C3) – Propane use is predominantly split between heating, which is seasonal, and for certain petrochemical applications.

Butane (C4) – Demand for butane is usually quite robust since it has a wide range of uses. It has both industrial and residential heating uses and is often blended with propane to produce liquid petroleum gas. Butane pricing is most similar to that of crude oil.

Pentanes or Natural gasoline (C5-C9) – The heaviest of the non-condensate liquids. It’s frequently used as a fuel additive and blended with regular gasoline as well as a petrochemical feedstock. Receives a premium to crude oil at times.

Condensates (C10+) – It is basically equivalent to crude oil with many of the same end markets. Its pricing is also similar to crude oil.

As juniors—and even seniors like Encana (ECA-NYSE; TSX) and Chesapeake (CHK-NYSE)—have tried to increase NGL production, the market has not been impressed.  The stock prices of these gas producers has not improved much of the last year.  My experience is that until the juniors have reached about 70% oil and NGLs of overall production, the market doesn’t care.

This huge rise in NGL production is primarily due to the Shale Gas Revolution—especially in Texas where a lot of the new “oil” plays are really 25%-35% gas and NGLs.

Then there’s also the Marcellus and Utica shale gas plays in the US Northeast and the Granite Wash play in western Oklahoma that have NGLs, along with Canada’s Montney and Duvernay plays on the BC/Alberta border… which are also NGL rich—and just ramping up.

In 2011, NGL production hit a then record of about 2.2 million barrels a day. The U.S. Department of Energy estimates that in March of this year (the latest data available), NGL production rose to 2.3 million barrels a day. This figure is a jump of nearly 50 percent from January 2009 levels.

In fact, NGL output in the first quarter of 2012 accounted for a record of almost 30 percent of the U.S. oil production. At the beginning of this decade, according to industry estimates, this figure was only 20 percent.

It looks like the shale boom will only make the pricing situation worse in the years ahead.  Bentek Energy estimates NGL production will increase by more than 950,000 barrels a day to over 3.1 million barrels a day by 2016, adding to the NGL surplus.

BENTEK’s Jack Weixel adds that “as (NGL) pricing continues to decline, operators will continue to pursue even oilier plays, with the activity in the Utica being the best example of this.”

The US is exporting more NGLs to help relieve this production glut.  About 220,000 bopd are exported, mostly to Latin America, and by 2016 BENTEK expects that to be 400,000 bopd of mostly ethane and propane.  Canada is doing its part, as US condensate exports to the US—where it’s used to dilute heavy oil; make it flow better—have increased 10x in the last year.

However, Weixel adds “the real constraint is domestic demand.  While several world scale ethylene crackers have been proposed, until facilities are actually built that can use product such as ethane and propane, we’ll continue to see downward price pressure.”

US public companies whose stock prices are tied to NGL profitability include Targe Resource Partners (NGLS-NASD) and Enterprise Products Partners (EPD-NYSE).

The bottom line here is that the NGL surplus looks set to be around for several years, which is good for the petrochemical firms but bad for gas producers. Wells Fargo Bank, one of the biggest lenders to the U.S. natural gas industry… with intimate knowledge of the industry, recently sounded a pessimistic note. It warned that the price downside for NGLs had a “few more legs” to go and that “the pain could continue into 2013.”

by +Keith Schaefer

Investing in Oil: 5 Questions To Ask Company Management

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1940bkg
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The North American oil market is going through a fundamental change that will affect the price of oil for the rest of this decade—fast-rising shale oil supplies from North Dakota and Texas.

(Other shale oil plays will contribute as well, but none will come close to the revolution happening in those two states.)

This could mean lower oil prices for the next several years.  I don’t foresee the collapse in oil prices like what happened to natural gas, but even a 30% permanent drop to $70/barrel from $100 will impact junior and intermediate producers who spend all their cash flow.

And folks, almost all of them spend all their cash flow.

To me, this situation has two outcomes:

1. The juniors/intermediates will reset to a lower valuation/lower multiple to take into account lower profitability from lower oil prices. That is happening now and is almost done, IMHO.

2. Balance sheet will become more important than it was in a bull market, when juniors could raise money with no problem to fill the gap between cash flow and spending.  Now the financing market is very fickle—one day it’s open; the next—no way.

With this in mind, here are a few questions for you to ask management teams in your research.  Most of these answers can also be found in the middle of the Management Discussion and Analysis (MD&A) in the quarterly financial statements.

QUESTION #1 –
What price deck are they basing their cash flow on?  Because if it’s above $75, I would expect downward revisions this year. OK, maybe they can use $80, but that would be, IMHO, a bit optimistic (especially north of Cushing, Oklahoma, which includes all of Canada ;-)).

The price of oil in 2012 may average better than that, but moving forward from now, it’s tough to see North American oil improving much more than $10 a barrel (i.e., over $80-$85) for the next 18-24 months.

I hope I’m wrong and we all make buckets of easy money in the next year at $95 oil, BUT the fast-growing supply in the US is competing with Canadian oilsands for pipeline and refinery capacity, which is already close to being full. Whoever is willing to take the lower price gets to sell their oil.

QUESTION #2 –
What is their net cash/net debt? Make sure you use the word NET, as the number you get could be GROSS… as going into this downturn, in April, the market was still focused on growth and the income statement. Now it will be focused on the balance sheet. That’s a BIG change, especially for Canadian producers who for the most part spend AT LEAST 100% of cash flow… often up to 150-200%.

The “growth at any cost” mantra of a bull market could mean that some high growth companies that got premiums in their stock in the past will now have their valuations lowered by the market.

QUESTION #2b –
What is their “total liquidity”—how much money do they have available to them?  This would be how much room they have left on their debt capacity, plus any net cash they have.  If they have $10 million net debt on a $50 million line, they have totally liquidity of $40 million.  With $10 million net cash, the total liquidity is $60 million.

QUESTION #3 –
What is their debt to cash flow ratio at $70 oil? Anything over 1.5:1 in the juniors will get punished a bit, and over 2:1 will get punished a lot. Institutions will buy those stocks last in any new bull market, and without institutional liquidity those stocks will not move up.

QUESTION #3b –
With the yield stocks, the same question is phrased like this—what is your all-in, payout ratio at $70 oil? When you put their drilling budget and dividend payouts up against cash flow, if it’s even over 100%… that’s bad news now.

As reference, every single one of the 10 companies in a most recent Macquarie Capital weekly energy update showed payouts higher than cash flows. 10 of the 17 US mid-cap producers were scheduled to spend more than their cash flow. It was 8 for 14 in the Canadian mid-caps, and all 12 of the small caps were spending more than cash flow. You get the picture. Spending cutbacks this year must happen, which will reduce growth.

QUESTION #4 –
Will they reduce their spending to meet their new lower 2012 cash flow? As I said above, there is almost NO FREE CASH FLOW in the Canadian junior/intermediate energy patch—they regularly spend more than they cash flow.

And in a declining price environment, the market gets more sensitive about energy producers spending within their cash flow.  If the oil price declines so much that their cash flow goes down below what they plan to spend, they may have to cut back drilling—slowing production growth.  Slower growth means a lower multiple in the stock.

That makes companies NOT want to cut back spending/drilling.  But once The Market KNOWS a management team must cut back, it starts to price all that in, anyway.

Investors will punish a stock quickly when it announces a spending cut (despite the fact that saving the money and preserving the balance sheet is the right thing to do)… and punish it slowly if management doesn’t quickly cut back spending.  So the stock either does a quick cliff dive when management does the prudent thing, or it drowns slowly until they do cut spending or everyone thinks the price of oil will stay high.

The reality is, they won’t tell you that. By law, they have to say “no” even as they are sending out the press release that they are indeed reducing spending (“lowering capex” is the industry jargon)… because that’s a material fact, and they need to make disclosure to everybody at the same time via a press release.

QUESTION #5a, b, c and d –
How much production do they have hedged now—at what prices? (i.e., how much future profits have they locked in?) What percentage of their production is that?  And when do the hedges run out? Not many companies have hedged production at higher prices, but those who have will get rewarded with a slightly higher valuation—especially if it’s a Tier One junior.

So what kinds of stocks should I be investing in as the market adjusts to this new, lower oil price scenario?

1. Those with net cash, then those with very low debt ratios (less than 0.5:1)

2. Oil focused (there are only 4-5 gas stocks worth looking at in Canada now)

3. International stories that get Brent pricing, which is based out of London, England—it is now $10-$15 above WTI, the US benchmark oil price.

by +Keith Schaefer

Floating LNG: The New Revolution in Offshore Natural Gas

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1940bkg
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A decade after hydraulic fracturing, or fracking, started the shale revolution and ended high natural gas prices, another revolution is set to rock the industry—Floating Liquified Natural Gas—FLNG.

It’s the leading edge of the natural gas world, and it could impact Canadian and US hopes for huge LNG exports. A full 10% of the LNG world is expected to be sourced from offshore LNG by the end of this decade, with costs potentially as much as 40% lower than onshore projects.
floatinglng1 3
You see, there isn’t a single FLNG terminal/ship producing anywhere in the world—but they’re coming. But Royal Dutch Shell’s $10-$12 billion Prelude Project will be the first in 2017 when it anchors down 200 km off the northwest coast of Australia at the 3 tcf Prelude field—its home for the next 25 years.

Prelude will be—by far—the largest floating vessel in the world—and could produce LNG for just 60% of what onshore facilities do. While it will only produce 0.5 bcf/d of LNG, some industry players are forecasting rapid growth for FLNG around the world.

flng tanker 2
Shell estimates there is a mind boggling amount of stranded natural gas underwater, all over the world—some 240,000 billion cubic feet—and much like onshore shale gas, the industry knows where a lot of it is, but hasn’t had the technology to produce it at a profit.

So is there potentially ANOTHER huge amount of cheap, clean natural gas available to the world? Yes, but unlike onshore shale gas, however, the capital costs are so high that only a handful of companies have the capital and expertise to do this. While this is THE leading edge in the natural gas space, I’m not expecting serious FNLG volumes until the end of this decade.

Shell’s General Manager for FLNG, Neil Gilmour, told the Financial Times he thought FLNG could follow the same growth path of floating oil production ships, which were introduced in 1977. There are now over 150 around the world.

And the growth curve is already starting. In addition to Shell, other companies like Brazil’s Petrobras, BG Group in the UK, Repsol in Spain and Portugal’s Galp Energia are placing orders for ships, albeit with smaller projects offshore Brazil.

Shell itself has other FLNG vessels on the drawing board for projects in East Timor, South America, Indonesia and East Africa. Shell has specifically stated the smaller environmental footprint is a big selling point in geopolitically sensitive areas like East Timor.

Forecasts from most energy analysts are that by 2015, the liquefaction capacity of FLNG projects around the world will be 6.7 million tons per year or about one-tenth of global capacity. If Prelude is successful, FLNG usage will expand even faster.

I’ve written several times on how the global market for LNG is growing quickly. LNG is forecast to be the world’s fastest growing fuel market (growing twice as fast as regular natural gas) through 2030, says BP’s chief economist Christof Ruhl. He adds that LNG is already 25%-30% of internationally traded gas and makes up 9% of global gas demand.

——————————————-

Have You Heard of the “Other” Bakken Oil Play?

It’s not on most investors’ radar screens.

But a very special situation is quickly taking shape in the play. Not only are drilling results getting better with each new set of results… but the next set could validate a huge new area of production — and turn it into one of the top plays in Canada.

And for my # 1 junior company in the play, the best news may be just ahead.

That’s why insiders have been scooping up shares lately… and why this junior could be the break-out oil trade for the rest of 2012.

Learn all about this opportunity here in my full research.

——————————————-

The International Energy Agency forecasts that within a few years, LNG imports will meet about a fifth of the total incremental demand in the world for gas. In 2010, LNG accounted for about 10% of the total global demand for natural gas. This implies a double-digit growth rate for LNG over the next few years and possibly even longer with most of the demand growth coming from Asia and the Middle East.

FLNG ships like Prelude reduce both the project costs and environmental footprint of LNG development. Despite their massive size, they’re still only one quarter the area of an onshore LNG plant.

(But it will still be longer than four soccer fields put together, and will hold 175 Olympic swimming pools of LNG.)

But there is no need for long pipelines to shore, no compression platforms to push the gas to shore, no nearshore works such as dredging and jetty construction, and no other buildings and roads. Shell expects Prelude will produce 15% less carbon dioxide than an onshore LNG facility.

For $10-$12 billion, Prelude will, according to Shell’s estimates, produce 110,000 boe (barrels of oil equivalent) per day (my math comes out with slightly different numbers), which is roughly broken down like this:

  1. 1.3 million tons per year—or 35,000 bopd—of condensates
  2. 400,000 tons—or 12,700 bopd—of liquefied petroleum gas (propane)
  3. 3.6 million tons per year of LNG. (1 million tons of LNG = 48.7 billion cubic feet of natural gas, so 3.6 MM x 48.7/365=480.3 mmcf/d, or just under 0.5 bcf/d, or 86,454 boe/d)

Despite the initial cost, some industry experts are suggesting LNG costs will be in the $550 to $700 per metric ton range versus the $1,200 to $1,500 per metric ton range for onshore LNG projects.

There are obviously huge risks with a project this size—huge storms, long-term economics, capital costs, etc.

But if Prelude works, FLNG has the potential to do for stranded gas offshore what fracking has done for trapped natural gas onshore.

by +Keith Schaefer

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