North America’s Great Experiment: The Shale Revolution (Interview)

By
Keith Schaefer
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Editor’s Note:  Today’s OGIB is the transcript of my recent interview with Peter Byrne of The Energy Report (TER) on a growing debate in North America’s Great Experiment: the Shale Revolution, and I also talk about which junior producers I’m keeping close tabs on right now in the oil patch.

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The Energy Report: A number of experts say North American gas supply is peaking. Where do you weigh in?

Keith Schaefer: During the last three years, the mantra has been, “Drill, baby, drill,” for a number of reasons. The price of gas was never one of those reasons. Companies drilled because the technology kept improving. They drilled because they were able to get cheap foreign capital to partner in joint ventures. The market situation was not based upon economic “truth.” It was based on securing the land position and, “Economics be damned, let’s go!” But we are now returning to a real gas market based upon economic fundamentals. Where that’s going to shake out, nobody knows; the market is betting on higher prices.

The reality is, Peter, there is only one true gas formation in the U.S. that is increasing production, and that’s the Marcellus. Every other single shale gas play is now in decline. The industry is now much more disciplined in producing gas, as the rig count has gone way down. But I suggest that the price rise is a year or two away because there is so much gas drilling going on in the Marcellus and Eagle Ford. These two formations are making up the shortfall in other regions. At some point in time—nobody really knows when—the scales are going to tip: Gas production in North America will seriously decline. The gas bulls think it’s going to happen quickly, because the hydraulic fracking wells come in like gangbusters and then rapidly decline. An overall decline in supply could drive up the price.

The Energy Report: Are there undeveloped or undiscovered shale gas plays still out there?

Keith Schaefer: The short answer is that we do not know. Explorers are testing new areas. Just outside the Bakken, there is activity in Bowman County. There is play in the Heath Shale. It looks like the Utica will be mostly gas, not oil. But I don’t see any more Marcellus Shales out there.

The Energy Report: Is there a limit to exploration?

Keith Schaefer: All of the easy fruit has been picked. Remember, most of the shale plays were already well known geology, so everybody knew where the oil and gas was. We just did not have the technology to get the stuff out of the ground. As the technology has improved, bit by bit, and the politics has improved, bit by bit, the known shale plays are being developed to capacity. Is there another undiscovered giant like the Marcellus lurking somewhere? Realistically, I doubt it. The industry has very good tools for looking underground. A big monster shale play that would keep the gas glut going for another two or three years is a bit of a stretch.

The Energy Report: Will we go back to importing gas?

Keith Schaefer: I do not see the U.S. importing much gas for at least three years, and maybe longer, depending on existing wells’ decline rates. Right now, drillers are doing maybe four wells per square mile. With downspacing, they can get down to 8, 16 or even 32 wells per square mile. There is still a lot more domestic gas to be pumped before we need to import a lot of gas again.

The Energy Report: Let’s talk about the role of Canadian penny stocks in your portfolio. How is the shale experiment with the oil juniors going in Canada?

Keith Schaefer: All across North America and especially in Canada, the rush into shale oil has been a great experiment. But it really doesn’t work in a junior company. The place for juniors in an investor’s portfolio right now is getting smaller and smaller. The shale, or tight wells cost a lot of money to drill, and the juniors just do not possess the capital necessary to develop many of these plays. The wells will pay out in 12–24 months, and that is simply not fast enough for the junior companies to recycle the cash and drill another well. A junior might have a big land position, but it cannot develop it, particularly on the gas side, without continually raising equity. Many of these companies have stopped or dramatically reduced drilling. It’s a bad spiral: You drill less, you produce less and your declines are high. These smaller energy firms are in a really tough spot—for oil or gas.

The Energy Report: Is it reasonable for the management of these struggling companies to hope the price will go up and make staying the course worthwhile?

Keith Schaefer: Well, yes, they have no choice other than shutting down all of their production. It’s just a question of how long the wait is. I was talking with a producer the other day, and he indicated that there will be no new capital available for pure dry gas until it is hedged at $4.50/thousand cubic feet ($4.50/Mcf). Gas has to be at $5/Mcf for a couple of weeks for them to do that. So gas prices have to be $5/Mcf for the market to realistically think about putting more money into dry gas wells.

Could that happen this year? It could, but the Marcellus is still coming on strong. Next year is quite possible. The other thing is that the gas wells with lots of natural gas liquids (NGL) like condensate, propane, butane and ethane have better economics than simple dry gas wells. With NGLs, more production can come on-line at $3.50/Mcf. There is hope; prices are moving higher than most people expected at this time of year, thanks to a very cold early spring. But to say that prices will go much higher from here would be a bit of a stretch.

The Energy Report: Which junior names are doing well in Canada?

Keith Schaefer: In no particular order, NuVista Energy Ltd. (NVA:TSX), Advantage Oil and Gas Ltd. (AAV:NYSE; AAV:TSX) and Delphi Energy Corp. (DEE:TSX) are doing well. The market is watching these companies to see which has leverage to gas, and which can really show a huge improvement in its numbers if gas does go up. These companies are heavily gas weighted. So, if gas does turn and stay higher, they have the most torque.

[To read the rest of this interview, click here for the full version on The Energy Report’s web site.]

by +Keith Schaefer

The U.S. Dollar’s Impact on the Oil Price

By
1940bkg
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0

Many investors study supply and demand statistics to figure out where they think the oil price is going.

But by far, the biggest factor that determines the oil price is the US dollar, says Donald Dony, who pens The Technical Speculator investment newsletter.

“The US dollar is absolutely pivotal for commodity prices,” he says.  To pros in the investment game, that is a truism; obvious.  But most investors underestimate the background impact the U.S. greenback has on oil prices.

And Dony expects the US dollar to keep grinding higher.

“Our analysis  on the USD is looking bullish on the longer term basis—86-87 or even up to 90 cents on USD index.  The U.S. economy continues to improve thanks to the ongoing commitment of the Fed to its stimulus program.  As long as the Dollar keeps rising, we will definitely see a negative impact on oil prices.  The dollar needs to fall through $0.82 before a trend reversal occurs.  If it does, commodities should jump.”

dony1

He adds that the US dollar and the S&P 500 index appear to be back to their traditional—and positive—connection, that’s not good for commodities.

“I see another six more months of higher S&P.  All tops are big distribution pattern. Generally speaking, what happens is that for 6-8 months the market can’t move higher—but it doesn’t drop, either.

“If that’s the case, we have nothing like that in the S&P right now.  That alone gives us a bit of a picture. If the S&P stays at 1600 all through the summer, we may not see a downturn until the end of the year.  These distributions last for months—often 6 months or more, where the market tries to go higher but there just aren’t enough buyers.”

Dony also says the oil price also follows the stock market… but not like it did years ago.  He says that now, unlike 30 years ago, we have a real world economy; it’s not just the S&P based in the USA.  Oil is following what global markets are doing, not just the S&P—and he says global markets not really going anywhere; they’re up marginally but not strong.

dony2

Dony expects the world’s stock markets to continue advancing slowly as long as the U.S. stimulus program is in place.

“The charts show there is a rhythm to GDP (Gross Domestic Product) over the last 30-40 years that gives us a low every five years.  If that’s the case, we’ll likely see the next low sometime in 2014.  I don’t know how deep or how long the next correction will be.  And most of the world’s GDP has already declined for the last two years—even three. I expect another low next year.”

So what are a couple of his favourite stock charts in the Canadian oilpatch?

Enerplus—ERF-TSX/NYSE—in November 2012 it took a Mexican cliff dive, and has now been forming a wonderful base, and $13.50 was a big resistance level.  Then it broke through, and came back to $13.00-$13.50 which is now support—good time to be buying.

dony3

Freehold Royalties Ltd.—FRU-TSX; FRHLF-PINK—This is the pattern level I look for.  It has resistance level of a year or more.  When it breaks through it means something special, that’s a really strong sign and you see a fairly significant move.  The technical target is $31.50

dony5

PenGrowth Energy Corp—PGF-TSX; PGH-NYSE—it’s almost the same as ERF; it’s making a change in direction.  It pops up in March, good support at 4.80.  I like the ERF chart more but PGF shows a lot of promise.

 

dony6

Dony says the US dollar has ALWAYS been the driving force for commodity prices.  He says that in the 1960s-70s, the U.S. dollar was relatively weak, and commodity prices took off.  In the 1980s & 1990s the US dollar moved up in a gradual strengthening phase, and commodities went nowhere for 20 years.  When the dollar crested in 2002 because of crushing national debt, commodities roared.  Now the greenback has bottomed since 2008.  In fact, over the last two years, the Big dollar has been rising.

“It’s a simplification but it’s a fact—the dollar is way more important than all the supply and demand factors.  Copper should be taking off to the moon.  China is stockpiling the stuff and controls 50% of the world’s supply.  But copper is falling like a stone because the US dollar is up.

“It throws a blanket on the supply and demand stuff—except for natural gas, you have to look at the US dollar to get a real grip on commodity prices.”

Ah yes, natural gas—the best performing commodity over the last 12 months. In my next story, Dony gives us thoughts on where the charts are telling him the price is headed, and what some of his favourite stock charts are in that sector.

Neither Donald Dony nor Keith Schaefer own any stock mentioned in this article.

You can check out Donald Dony’s site at http://www.technicalspeculator.com/index.php

by +Keith Schaefer

Shipping Crude Oil by Rail: A Victim of its Own Success?

By
1940bkg
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0

Oil producers in Alberta have embraced the holy rail, shipping out by train car an estimated 120,000 barrels of oil per day (bopd) to refiners on the east coast and the U.S. Gulf.

Despite rail costs doubling pipeline tariffs, producers were able to get such a better price railing it past the mid-continent refineries all the way to the US East Coast and Gulf Coast–it made the logistics worth the time.

But just as Canadian rail use is set to soar again—you can boost that number to 200,000 bpd by the end of the year when several terminals are completed, say analysts—rail may no longer be economic.  Rail could be a victim of its own success.

“In May or June, producers that have traditional access to pipe may see better netbacks than rail,” one oil and gas marketer told me last week.  Netback is the industry word for profit per barrel.

Railing oil has been more profitable than transporting by pipe for a lot of Canadian producers since last summer–when the difference between US and Canadian oil prices widened.  It has also been necessary, as producers have had to find alternate routes to market—rising oil volumes competed for limited pipeline space.

And while pipeline tariffs might be cheaper than rail, the additional fees add up: producers often have to shell out trucking fees to a pipeline-connected battery, plus diluent fees (diluent makes heavy oil flow in the pipe better) and perhaps a fee to remove water from the oil to bring it up to pipeline spec.

“The netback has been greater by rail—usually more than 10% better than the pipeline-connected alternative,” says Chris Cooper, CEO of Aroway Energy, a 1000 bopd producer in southern Saskatchewan. “In some months it can exceed 20%.”

Smaller producers without access to the financing needed for long-term (10-20 years) contracts on pipelines, make every penny count when marketing their barrels. Cooper’s savings are diluent costs of $6/b and pipeline fee/tariffs of almost $1.50/barrel.

“The price paid for the crude shipped to the rail facility fluctuates on WCS prices,” Cooper says. “We were getting $45-$50 in Jan, we’re getting $66.72 today.”

Last year the rail rush was driven by limited pipeline capacity and the wide gap between the price for US oil and the price for Canadian oil.  The difference between the two (or the difference in oil price between any two places) is called the “differential.”

There was some BIG differentials at Christmas 2012—Canadian light oil traded as low as $68/barrel and heavy oil at $48/barrel.

At the same time, refiners on the U.S. Gulf Coast and northeast were paying overseas prices for their heavy oil feedstock, around $110/barrel.  That’s a big differential! So there was lots of room to spend $14-$18/barrel to rail it to a much higher priced market.

Fast forward to late April 2013.  Light oil only has $3/bbl discount to WTI, trading at $86.13/bbl and heavy oil (WCS, or Western Canada Select) gets $71.431.  Part of the reason for higher prices is seasonal; less oil gets produced in Canada in Q2 because of spring break up, so supply is less.  But another reason is that rail has created a bigger demand by making Canadian oil available to more US refineries.

When Canadian crude was selling $40 less than its U.S. counterpart, rail made sense; producers paid $14/bbl to hit northeast refineries or $14-$18 to the U.S. Gulf Coast, where refineries paid Brent prices of up to $119/barrel.

However, when the Canadian-US arb tightens to $12-$14/bbl, like it is now, it may not be worth it.

In addition to the narrow differential, the cost to ship crude by rail, from loading prices to rental fees, has jumped in a classical supply-demand imbalance response.

Shipping oil by rail used to be the answer to tight pipeline capacity and cheap Canadian crude.  But the question now is… has that train left the station?

WIDE DIFFERENTIALS MAKE RAIL SENSE

Analysts and producers say shipping crude by rail, usually an expensive choice, made sense when West Texas Intermediate (WTI) was $20 per barrel less than Brent priced crude, and Western Canada Select was about $15 under WTI.

Refiners on the U.S. Gulf Coast and the northeast U.S. and Canada pay higher international prices based on Brent, so when the difference between coastal and inland crude widens, the netback from rail is higher, especially if you can’t get pipeline capacity.

Last November, Southern Pacific was raking in $20-$30/bbl more by railing and barging its bitumen to Louisiana than it would have at the congested Cushing, Oklahoma hub. The junior oil sands producer paid $31/bbl to rail and barge its oil to a Louisiana refinery, compared to $8/bbl by pipeline. But a $20 differential from Brent and lower diluent costs made the move profitable.

Cooper says that typically, a company’s oil marketer negotiates and lines up rail loading space for crude trucking shipments out of the field. Even so, high demand has translated into waits of up to six months for rail loading space.
Once at the terminal the custody transfer is made and the producer gets paid a single price for its crude.

“If you’re bigger, doing like 10,000 barrels of oil per day, those operators probably have an ability to rent rail cars somewhere from somebody to get it to the right refinery; we’re too small to do that. Others have rail agreements and agreements to bring back diluent in the same cars.”

Approximately 19,000 tank cars were ordered by Canadian companies, according to Rail Theory Forecasts. The railcars are insulated to carry heavy crude but will not be delivered until 2014.

Most producers have opted to lease tank cars, for term contracts of up to five years on average, rather than build. They are taking advantage of the thousands of kilometres of railroad tracks which already exist, crisscrossing North America, connecting to industrial hubs, pipelines and waterways.

In Western Canada, transportation companies have been busy expanding and building new transload terminals to total about 16 facilities run by six major players – Canadian Pacific Railway, Altex Energy, Canadian National Railways, Torq Transload, Gibson Energy, Canexus Corp. and Keyera/Enbridge.

CP said in December it would be shipping 70,000 carloads of crude by the first quarter of 2013, out of Canada and the U.S. That’s up from 500 in 2009.

The company expects to transport 44.8 million barrels this year, based on about 640 barrels for each rail car, up from 8.3 million barrels of crude oil in 2011.

Three years ago rival Canadian National didn’t even ship oil. The railway firm moved some 3.2 million barrels of crude in 2011, an estimated 19.2 million barrels by the end of 2012, and could eventually handle 200,000 barrels a day or more.

The run for rail started in North Dakota when producers untapped tight oil reserves with horizontal drilling and multi-staged fracturing. Volumes exploded without enough pipeline capacity to move product to market.

By 2012 the number of U.S. trains moving oil soared to 233,811 carloads, up from 9,500 carloads just five years prior.

Keep in mind those numbers look to be derailed as the price of Canadian crude climbs and the netback to shipping by train drops.

by +Keith Schaefer

Author Bill Powers: Debunking the 100-year Natural Gas Supply Myth

By
1940bkg
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0

What’s the best-performing commodity over the last 12 months?

Natural gas.

I asked natural gas bull Bill Powers, whose new book is Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth, to give OGIB readers his thoughts on the gas market ahead.

Bill’s book is something very different than what you read in analyst reports from the stockbrokers. It is exhaustively researched and rigorously documented. Here’s what Bill shared with us…

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While natural gas has been the best performing commodity so far in 2013, I believe we are only at the beginning of what is likely to be a long bull market for the fuel.

Unlike most market analysts, I believe the natural gas market is structurally imbalanced as demand will continue to outstrip supply and lead to significantly higher prices.

But what about the 100-year supply of natural gas that sits in numerous shale plays across North America just waiting to be brought to market?

Won’t a pick up in drilling brought on by higher prices squash any price recovery?

First, we do not have anywhere close to a 100-year supply of natural gas in North America. There is a substantial and growing body of evidence to support my thesis that the importance of shale gas has been vastly overstated.

Second, due to high decline rates of shale wells, the advanced maturity of the Gulf of Mexico and most conventional U.S. natural gas fields and declining production in the Barnett, Haynesville and Fayetteville shales, it will be several years before U.S. natural gas production stabilizes at a much lower level.

While the Marcellus shale is likely to how further production growth in 2013, it will not be enough to offset declines elsewhere.

In my upcoming book titled Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth, I take an in-depth look at today’s conventional wisdom about natural gas supply and use hundreds of well cited sources to show that much of it is wrong.

Additionally, I show who is responsible for the creation of the 100-year supply myth and their motivations.

More importantly, instead of using wild guesses as to the size of the U.S. shale gas prize, I use the significant production history of several shale plays to provide a realistic estimation of future recoveries.

While America’s future shale gas production will undoubtedly be an important part of the country’s energy mix, it will have far less impact than many believe.

I will discuss the specifics behind the 100-year natural gas supply myth and discuss what it means for prices in both the near and long term in our upcoming Oil & Gas Investments Bulletin subscribers-only conference call.

– Guest Editor Bill Powers
Author, Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth

A New “National Interest” Idea for Getting Canada’s Oil to Market

By
Keith Schaefer
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0

The energy sector is such a typical American-Canadian contrast.  It’s like the Americans love to shoot guns, and the Canadians love to dodge bullets.


In the USA, the Shale Revolution has turned the American energy industry upside down with huge new supplies of natural gas and light oil. 
 


They have reversed a 40-year decline in oil production in a stunningly short four years.  Their entrepreneurial system made it happen; it couldn’t have happened anywhere else in the world.  Kudos to them.
 


The Yanks have built drill rigs, oil pipelines, water pipelines, and brought back billions of dollars of petrochemical plants; secured rail to transport their crude all over the country—the American industry has shown itself to be remarkably agile and responsive.
 


The world’s oil has been getting heavier for years—and so has the infrastructure to transport and refine it.  So the fact that US production increases are in light oil make theirs an even bigger transformation.


Now, look at Canada trying to get its heavy oil to market—but only if you want to laugh.



In Canada, investors have been able to predict our rising heavy oil production for years—think of the old joke where in Regina Saskatchewan, you can see your dog run away for three days, the land is so flat—investors have had that kind of visibility on this issue. 
 


And here we are still beholden to the same one customer, and now we can’t even get all of our product down to them!  Canada has actually gone backwards in that respect.  That’s why we’re price takers and they’re not, and why Canada is vulnerable to the low oil prices seen at Christmas 2012.


Now, despite all our bumbling, Canadian heavy oil discounts are now quite low, meaning the price of our heavy oil is quite high—it was $80.95 in early April, a big jump from the $48 it was getting last Christmas. 

This is a GREAT price, and makes this drama mere entertainment, not a national tragedy anymore.
 
This is because Canada has adapted at least one way, and found a way to rail oil down to the US refineries—but it’s still going to only US refineries.
 


But I can’t help thinking…the US has gone through a much greater upheaval, socially and economically, from the Shale Revolution than Canada has. 


They have adapted better, adapted more quickly, than Canada has…at every turn. 

And there has been a lot of turns! And they keep coming!  Horizontal drilling, hydraulic fracturing over 300 feet, then 1000 feet, then half a mile, one mile, now two miles. 

Suddenly full oil refineries, suddenly empty gas pipelines (it’s everywhere now, who needs gas pipelines?)—billions were spent on gas pipelines only a few years ago are now well under capacity.


In the US, business just moves on, recognizing the new business reality.  Canadians use the National Energy Board to decide the best way to keep everyone from losing money.  It’s like Americans love to brag about how much they spent and Canadians brag about how much they saved.


And almost all Canadian oil pricing problems would be solved by getting one, just one, 1200 mile pipeline from the Alberta oilsands to the British Columbia west coast; from Fort McMurray to Prince Rupert.

But it has created a family feud in Canada that has dominated news headlines for well over a year.
 
Opposition against this west coast pipeline has drawn protests from environmentalists and First Nations, and even left-wing Canadian politicians.

In the US, build it, and they will come.  In Canada, build it, and they will protest.
 
Of course Uncle Sam agitating the locals under the guise of environmentalism doesn’t help, either. 

And don’t kid yourself, they are actively trying to keep Canadian oil for themselves; it’s well documented (stand by for a full feature story or three on that in the coming weeks).
 


But oil is a global product, and it flows from areas of low price to areas of high price. 

That’s the whole point of pipelines—to get it to higher-priced markets. If the differentials remain wide enough for long enough, that oil WILL find its way to market—even if it has to be pulled by wagon.
 


I don’t think Canada is going to get backed out of the market, because somehow somewhere somebody is going to find a way to get that cheap oil. 

For example, I think we will get Canadian oil to Asia—but it will likely go through the Gulf Coast to get there, and get exported from there.   When I look at a map, I don’t know whether to laugh or cry. 
 


But it’s interesting that a “national interest” seems to be building around the idea of—instead of doing a simple 1200 mile pipeline west—reverse an existing gas line that crosses two thirds of the continent to get western Canadian heavy oil to eastern Canada and refine it there.
 


Hey, that could work, and make more of Canada feel part of the oil wealth that has such a huge impact on our country.  Quebec and New Brunswick refineries would finally get western Canadian crude, instead of from Venezuela. 


The refineries would have to be expanded to handle our growing crude supply, as would port facilities.  It would involve huge infrastructure spending and create thousands of jobs in Atlantic Canada.
 


It’s already well known that many of the oilsands workers are Maritimers, but it’s also true that the jobs in “Fort Mac” have saved rural areas across ALL of western Canada from big unemployment. 


But that pipeline reversal won’t be ready until 2017 at the earliest—four years from now. 2017 is the best case scenario.


America’s gun culture is famous for the phrase, “Shoot first, ask questions later.” Canadians are more prone to the phrase, “Ask questions first. Shoot, we’re too late.”


How typical.

by +Keith Schaefer

Iraq – Kurdistan’s Billion-Barrel Oil Investment

By
1940bkg
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0

 

The diplomatic war of independence between Iraq and its northern region Kurdistan is escalating rapidly, with the flashpoint for armed conflict being the Kirkuk oilfield on the boundary between the two sides.

While both sides have pulled back some of their troops poised for conflict recently, 2014 could be decisive as Iraqi Kurdistan plans to ramp up exports directly to Turkey, bypassing Baghdad. Neither side wants an armed conflict, but the momentum may be irreversible.

Which makes it surprising that junior Kurdistan explorer WesternZagros, (WZR-TSXv) hasn’t seen their stock impacted at all—in fact, they just raised over $100 million at a premium to develop their oil assets only kilometers away from Kirkuk.

The question moving forward is whether small companies like WesternZagros will be able to survive a potential war with their frontline assets intact, or whether they will look to cash in on some impressive exploration success and let the majors take the heat.

The Prize is huge—WesternZagros has 1 billion barrels in reserves already, but step-out drilling on their Kurdamir asset could prove the field up to between 10-20 billion barrels.

That trumps the increasing political risk—even when that risk could be an all-out armed conflict over Kurdish independence.

The biggest confirmation of this is the $123 million investment WZR secured earlier this month from Houston-based Crest Energy International.

The deal gives Crest 51,000,000 common shares in WZR, or about 19.8% of the company. For another 10% of outstanding shares in a secured loan agreement, Crest will also loan WZR $57.5 million to further exploration and development activities in Kurdistan.

Exactly what has spurred this massive investment optimism? It’s a combination of drilling success and geopolitical forecasting.

Iraqi Kurdistan Oil - Area Map
In terms of drilling success, two major discoveries at Sarqala and Kurdamir in southern Kurdistan late last year have quadrupled WesternZagros’ reserves to 1 billion barrels. Now it’s got the capital to fast-track the delineation of these discoveries. That’s already happening:

  • In late February, WZR spudded its Kurdamir-3 appraisal well.
  • 3 more wells will be drilled this year in the Garmian block.
  • High-impact exploration is about to get underway in the Baram and Hasira prospects.
  • Baram-1 could prove to extend Kurdamir discovery into the Garmian block—making it one of the world’s largest.
In terms of geopolitics, a bit of digging around into Crest paints an interesting picture. The US supermajors maintain a strong interest in Iraq’s non-Kurdish oil holdings, so Washington isn’t keen to prop up the Kurds against Baghdad and ignite an armed conflict for Kurdish independence. But private actors see things differently.

Crest is run by a Syrian Christian who has Republican backing and a keen interest in seeing WesternZagros make good on its finds. Like all the other players on the Iraqi Kurdistan scene, Crest is hedging its bets that the Kurds have the upper hand here.

Europe and Turkey agree, and they are homing in on Kurdish oil and gas—as Europe is desperate for supplies and Turkey aspires to become a major energy hub that bridges the Middle East and Europe.

The Latest Escalation–Budgetary Warfare

Baghdad has refused to pay outstanding debt for exports of KRG-produced oil through pipelines controlled by the central government since May 2011.

Baghdad is refusing to pay up because the KRG has been cutting unilateral deals with foreign oil companies (ExxonMobil, Total, Chevron) and attempting to export oil and gas directly to Turkey, bypassing the central government.

The Kurds are cutting Baghdad out of the equation because they need refined oil products; but the move also inches them towards independence. The KRG and Turkey initiated direct crude swaps in return for refined oil products when they were cut off from Iraqi funding.

It’s a tit-for-tat game that has seen Baghdad threaten to revoke the licenses of the supermajors who have had the bravado to strike unilateral deals with KRG and the KRG cut off exports to Baghdad.

Baghdad’s latest maneuver was to nearly cut the Kurds out of the federal budget. The $119 million budget for 2013 was passed on 7 March. The Kurds only got $646 million of the $3.5 billion they requested.

Not only does Baghdad still owe some $3.5 billion to foreign companies operating in the KRG for PAST exports, the new budget means the Kurds can only cover about two months of new crude payments to foreign companies.

So even if production is ramped up in Iraqi Kurdistan, the only way to pay for it will be to ensure direct access to Turkey.

For WesternZagros it’s not an issue—for now. The Company has not declared commerciality, and when it has produced, it has been on the basis of extended well testing.

WZR Investor Relations Manager Lisa Harriman told OGIB that the Iraqi budget was “very anti-Kurd”.

“The budget is one of the most anti-KRG documents to be produced by the Iraqi government – a clear result of the exclusion of the Kurds from the final deal-making. Though 17% of federal revenue is still allocated for monthly block transfers to the KRG, there are a number of punitive measures for the Kurds. Federal strategic expenses, including the military, keep getting larger every budget and, as the 17% monthly payments are calculated after these are deducted, Erbil’s share continues to shrink,” Harriman said.

That’s why the Kurds and the Turks are cautiously experimenting with trucked exports from Kurdistan to Turkey, independent of Baghdad.

From the Kurds point of view, they are in full compliance with the constitution. Certainly Baghdad has backed itself into a corner. By law, the Kurds are to receive 17% of ALL Iraqi oil export revenues. That’s a massive amount of money—much more than it would get by exporting to Turkey.

By refusing to pay up, and then largely cutting the Kurds out the budget, Baghdad has essentially removed one of the last carrots keeping Erbil in line. It’s easier to give up 17% when you’re not getting it anyway.

But there is one more thing keeping the Kurds from that game-changing move: They need to bring the strategically important city of Kirkuk under their control. Kirkuk is home to Iraq’s largest oil field and precariously nestled in the disputed territories right on the KRG’s border.

In this political melee, WesternZagros has one potential bulwark against Baghdad: Russia’s Gazprom Neft owns a 40% interest in WZR’s Garmian block, and Russia seems to privy to the favor of Baghdad of late. Gazprom’s involvement in Kurdistan is a strategic one for Russia, and could be leverage for Kurdistan in dealing with Baghdad.

Pipeline Warfare

Right now Kurdistan is racing to cut as many production deals as possible to ensure it has enough oil to supply a 200,000 bopd pipeline to Turkey that should be completed by 2014.

For now, this is where things stand:

In June 2012, the Kurds began trucking crude oil directly to Turkish refineries, with the refined product trucked back into the KRG. Turkish companies are also discussing energy swaps with the KRG that could see natural gas pumped from the KRG to Turkish power plants and electricity produced in Turkey channeled back to Iraqi Kurdistan.

Turkey’s Genel Energy is reportedly exporting around 20-30,000 bopd from Kurdistan’s TaqTaq field via truck directly to Mersin.

And there’s more of that to come: Genel is planning another pipeline to ramp up exports to Turkey by 2014.

This pipeline will link Iraqi Kurd oilfields directly to Turkey, but it could also tie in to the Baghdad-controlled Kirkuk-Ceyhan pipeline.

And there is also a plan in the works for a parallel pipeline that would supply several hundred million cubic feet of natural gas per day to Turkey annually by 2014. Turkey’s national oil company (TPAO) would be involved in this deal, under which it would acquire the rights to five exploration blocks in Iraqi Kurdistan.

(Late last year, Baghdad tried to “persuade” Turkey not to go down this road by kicking TPAO out of an oil contract with the Iraqi central government and handing it over to Kuwaiti Energy).

This deal hasn’t been finalized yet. The Turks are stalling a bit, and Iraqi officials are alleging that Ankara has promised not to go through with the deal. But again, Baghdad’s budget warfare will likely be the straw that breaks this camel’s back.

There is a northern gas pipeline currently under construction that leads directly to Turkey, and the KRG’s Minister of Natural Resources has said it could be converted to handle oil. The Kurds are actively seeking pumps to convert this now and this pipeline could handle 200,000 bopd and potentially be operational by mid-2013.

Bottom Line? This is the Definitive Year

With the game-changing pipeline set to come on line by 2014, Kurdistan is forcing Iraq to decide—and decide NOW—if diplomacy or war is the answer. These pipelines could represent the point of no return, giving Kurdistan its own royalties and the capital to be truly independent if it chooses that option.

As the definitive moment nears, WZR shareholders must decide—should they stay or should they go now? And how big is the window of opportunity.

– Jen Alic
Guest editor

2 Trends Making Investors Money in the Canadian Energy Patch

By
Keith Schaefer
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0

Dear OGIB Reader,

There are two trends in the Canadian energy patch in the last three weeks that have been making money for investors – but the question is, do they have legs? Can the uptrends continue?

The first and most obvious is natural gas. After doubling in price between April 2012 and November, it dipped down to $3.20/mcf (thousand cubic feet) in early winter. The winter just wasn’t as cold as normal… though colder than last year.

But fast forward to March 2013 and colder weather has gripped much of the high population areas of the US east coast and the Chicago area. US natural gas storage levels reflect this chill: overall US storage levels are now below 2 tcf, and the year-over-year deficit is 440 bcf.

As a result, gas jumped back up to over $4/mcf, and taken the chart of many natural gas producers with it. The futures strip shows the market anticipates gas prices above $4.00 from July forward.

Can it last? The pros I talk to in Calgary dismiss this bump, saying shoulder season is coming in April/May and the North American gas price, along with all the good looking Canadian stock charts it has created, will droop then.

The Canadian arm of brokerage firm Raymond James has a slightly more bullish interpretation.

“For the last 3 weeks, we’ve seen some of the largest withdrawals from US gas storage in the last 10 years.

Yesterday’s withdrawal was 145 bcf (billion cubic feet) – the 5-year average was 89 bcf and the previous record was 115 bcf in 2007.

Last week’s withdrawal was 146 bcf – the 5-yr. average was 104 bcf – 146 bcf is the highest since 2003.

Week before was 171 bcf – 5-yr. average was 117 bcf.

You get the idea…

And it is more than just cold weather doing this. Focusing on the last 4 weeks, 2008, 2007, and 2010 were all colder than 2013 – yet 2013 is seeing bigger withdrawals.”

(I love such simple, clear writing!)

They see the gas price that balances the market for the rest of 2013 being in the $3.85-4.15 range. I think if the market really had a comfort level that price could hold, the rally in stocks could continue (even though almost no one is making full cycle profits at that price).

Certainly gas drilling has fallen off dramatically (the US rig count is now 431 rigs, down 232 rigs from last year!) – yet North American production stays constant to slightly rising. The giant Marcellus Shale in the northeast US is THE perfect example… it just took over from the Haynesville Shale in Louisiana as the largest producer of natural gas in North America at over 7 bcf/d-while the rig count in the play dropped by a third. A third!

Another brokerage firm, Canada’s National Bank Financial, points out that in the US, “Residential/Commercial demand has been up about 17 Bcf/d (+50%) over the same period last year, with cold weather expected to persist through the week ahead to provide near-term support.”

Denver-based Bentek, one of the best natural gas forecasters, is projecting storage levels exiting the winter season (end of March) at 1.7 Tcf, which is 25% below the same period last year and in line with the five-year average.

Canada’s FirstEnergy says anything below 2 Tcf at the end of March is a good sign.

Canada continues to have lower production than last year – a 6-year trend now.

But of course, US residential demand will drop as the warmer spring shoulder season arrives – in my mind, that continues to leave US power generation demand as the swing vote. Natural gas pricing, and most of Canadian junior/intermediate stock charts, will live or die on that one metric. Period.

THE OTHER BIG TREND: oil-weighted yield plays in Canada have made a fast and hard 15% jump since 3rd week of February. Enerplus (ERF-TSX), Petrobakken (PBN-TSX), Pennwest (PWT-TSX) and Penngrowth (PGF-TSX) are included here. These companies do have some gas, so that could be the reason.

But light oil differentials in Canada – the discount Canadian light oil is to WTI – is now at a very low $3-$5 (synthetic oil, produced by the majors, is actually a $5 premium to WTI now). This is a great price for Canadian producers.

But all these companies have stretched balance sheets (lots of debt… i.e. dividends sustainable?) and could just be having a dead cat bounce off their lows for being oversold.

Most, if not all, are still paying out more in capex (capital expenditures, the industry lingo for drilling costs, etc) and dividends than the cash flow they’re taking in. As the market has moved away from rewarding growth to wanting more sustainability – where companies grow within their cash flow and not dilute by issuing more shares to fund their cash flow gap – it doesn’t make sense for these companies to run up in share price.

This current jump could be due to the rise in gas price – their jump co-incided with the larger than average storage withdrawals. It could be the chase for yield; the yield bubble. My suspicion is gas price is the main reason, with yield second.

As the shoulder season for gas approaches, the market will find out the truth soon enough.

by +Keith Schaefer

A New Way To Look at Buyouts for Oil and Gas Investors

By
1940bkg
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0

Last week I described how tax pools are a near-unknown—but increasingly critical—metric for junior oil and gas investors.

Tax pools shelter cash flow. E&Ps need them in order to retain cash for expansion—or to keep the coffers fat for paying dividends to investors, the way more and more companies are planning.

In the new, dividend-focused E&P sector, tax pools will determine success or failure for many firms.

Another important side to this story is that tax pools will increasingly drive M&A activity. Companies with shrinking tax credits will be looking for acquisition targets with deep tax pools.

Who might get bought and for how much? Let’s take a look.

Attractive Losses

We looked last time at two charts to understand tax pool dynamics across the Canadian E&P sector.

The first shows tax pools plotted against cash flow for a universe of E&Ps. The further right a company plots, the larger its pools.

Tax-Pool-Universe-Chart

The second chart shows the “cover ratio.” A measure of how many years of cash flow a company’s current tax pools can shelter. A bigger ratio means a longer time without having to pay tax.

taxpoolstocashflow

A company like Southern Pacific (TSX:STP) has a high ratio of 27.5. But that’s partly because it has low cash flow—$26.4 million annualized.

If a company like this can’t ramp up its output and cash flow, it’s left with large tax pools that will never be used.

Those pools could, however, become an asset for somebody else… like a company with good cash flows running low on its own tax pools.

Let’s do the math. If ARC Resources (TSX:ARX)—for example—acquired Southern Pacific, the company would pay around $660 million, at STP’s current market valuation plus debt.

ARC would get all of STP’s assets, plus $725 million in tax pools. Pools not currently being used to shield asset income to any great degree. Pools that could then be applied against ARC’s cash flow from its other assets.

STP’s tax pools would cover about three quarters worth of ARC’s annualized cash flow. Assuming a 22.5% tax rate, that equates to tax savings of $163 million.

Subtract that cash in ARC’s pocket from the purchase price for STP, and the effective payout for the acquisition is only $560 million. The acquirer has picked up those assets at a significant discount to market.

Banking Assets

Sure, there are hitches. Using up STP’s tax pools would leave cash flow from the acquired assets unprotected if and when they see increased production.

But ARC could equally choose to simply “bank” those assets. Collecting a majority interest in 402 sections of oil sands leases. It’s possible that an asset like this could be shelved for future consideration, and still be accretive to overall net asset value.

The acquirer could even turn around and re-sell the assets. As long as the sale price was more than 77.5% of the original purchase price, ARC makes a profit on the transaction.

This “tax-driven” M&A could particularly target companies with technology-intensive operations like oil sands—operations where big up-front costs generate large tax pools without initial commensurate cash flow.

Athabasca Oil (TSX:ATH) is another example. The company holds $1.7 billion in tax pools, but is not yet making positive cash flow.

If valuations for such companies continue to fall (STP is down nearly 50% over the last year), it may hasten acquirers to look at these firms as tax targets.

The Right Combination

Companies targeting acquisitions may also look at the potential for assets to generate new tax pools.

As we’ve discussed, there are different types of tax pools… some more high-octane than others in terms of shielding income.

The two major types are Canadian Exploration Expenses—generated by drilling on new, unproven targets—and Canadian Development Expenses, created by drilling on mature, established fields.

Exploration Expense credits provide bigger savings. They can be written off 100% against cash flow in the year they’re incurred.

Only 30% of development expenses can be used in the year of drilling. Companies have to carry over the remaining credits to future years, waiting for the tax savings.

Companies considering M&A will be looking at how acquired assets can generate tax pools… particularly high-value Exploration Expenses.

Firms like Twin Butte Energy (TSX:TBE) and Zargon Oil and Gas (TSX:ZAR) make good acquisition targets this way.

These companies hold large acreage positions in proven oil plays in central Alberta and Saskatchewan. They have a lot of land, and lots of spots to drill exploration wells looking for new pools. At relatively lower risk, given their experience in these fairways.

Such projects could work well for companies like ARC and Peyto (TSX:PEY). Companies that need additional tax pools.

By acquiring a Twin Butte or a Zargon, the larger firms get acreage where they could launch exploration drill campaigns. At a size that generates meaningful tax pools. But with an acceptable risk-reward profile.

This is a win-win. Smaller companies with large exploration grounds are going to be hard-pressed to fully explore these projects. They can’t afford to commit a lot of dollars for exploration in the current, tightening financial climate.

But bigger firms with a balanced portfolio of development and exploration projects can spend exploration dollars. Squeezing more value from their exploration bucks by using the high-powered tax pools from exploration drilling to shelter income from their mature assets.

Investors should look for smaller companies with large acreage positions in proven plays. Such projects will become increasingly valuable places for E&Ps to scale out the drilling they need to create their future tax shelters.

– Dave Forest, guest editor

Part 1 here
Part 2 here

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