Energy Sector to Finally Achieve Free Cash Flow

By
Keith Schaefer
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Free cash flow in the North American energy sector is about to soar, and that trend should continue for the next 5-10 years—even with declining oil and gas prices—says US brokerage firm Raymond James (RJ).

For investors, it could (should?) mean higher multiples as energy producers turn into more sustainable cash flow machines.

The heart of RJ’s argument is that the massive overspending by producers on new land plays is almost over, and production costs have stabilized.  At the same time, oil and gas production per well is increasing–sometimes dramatically.

Stable costs and higher production. The result?  A new era of positive, free cash flow that should last several years.

free cash flow

Some supporting evidence comes from a second research report–also issued on July 14—by the #2 Canadian brokerage firm, BMO Nesbitt Burns.  In a 26 page summary introduction report to their annual Global Cost Study for the energy sector, they showed costs for natural gas declining rapidly and even tight oil costs in the USA stabilizing.

First, let’s back up to 2006.  Between 2006 and 2012, US E&P companies spent $960 billion in capital expenditures generating only about $670 billion in operating cash flow.  That’s a whopping 40% deficit!

Part of this overspend can be blamed on the incredible land race the industry had during that time.  Once the Shale Revolution started—wow! It opened up billions of barrels in untapped shale fields.

Companies scrambled to stake as much land as possible—leasing millions of acres of land. It was a new gold rush!

Land was bid up to $25,000 per acre in some instances, multiples of the original investment.

Bloomberg reports that during the land grab frenzy of 2009-2012, energy companies spent more than $461 billion buying North American oil and gas properties.

These deals plunged 52% to $26 billion in the first 6 months of 2013 from $54 billion in 2012. The land grab was/is nearly over; most of the known plays have now been staked.

So that’s a huge part of the industry’s overspending now complete and out of the way.

E&Ps are now turning their attention to drilling their land, identifying sweet spots and improving their drilling efficiency (lowering their per unit costs).

And they’ve been very successful at that–thanks to horizontal drilling & fracking, the key technology behind the Shale Revolution.

Many Small Facts make a Big Picture:

  • a horizontal well can increase production by as much as 20 times more than that of its vertical counterpart as the well bore can be drilled sideways
  • the number of horizontal wells saw a steady increase in the past five years rising from 20% of all wells drilled to more than 70% in 2013
  • horizontal wells were drilled deeper and with longer legs to maximize contact with the tight/shale reservoir
  • frack intensity (the number of frac stages per well) also grew

Improving drilling efficiency means rising US production and falling costs per unit of production.  This chart from Raymond James shows just how much more efficient the drilling industry has become—we have seen a doubling in IP (Initial Production) rates the Bakken, a tripling in the Eagle Ford and an 8x increase in the Marcellus over the last few years:

production by rig
This rapid rise in production volumes eclipsed the slower rise in costs.

Rising production and falling costs per barrel means that the breakeven price for energy has also been trending lower.

That has been the most obvious in natural gas. The BMO report shows natural gas supply costs dropped below 4$/MCF in 2013 and is trending down to $5.10 on a three-year average basis.

tight oil supply
Per-unit-costs are also stabilizing with oil production.  BMO reports that US tight oil production is up from 1.1 million bbl/d in 2007 to more than 3.7 million bbl/d in 2013, and is expected to increase to over 5.4 million b/d by 2020.

That growth has allowed US E&Ps to achieve supply costs below the global oil average in three of the last four years.

For 2013 supply costs averaged $85/boe–$13/boe below the global average of $92.90/boe. With the exception of the Eagle Ford, it’s a major improvement over 2012.

nat gas supply costs
Raymond James says this a major paradigm shift for energy producers and investors. The industry should be a Free Cash Flow machine for the next 5-10 years, they say, even in the face of slightly declining oil and gas prices.

And since the industry can now deliver steady, solid returns and be less dependent on oil and gas prices, that more stable cash flow should result in higher multiples for energy stocks, they add.

RJ believes multiples for E&P companies can potentially rise from the mid-single digit range (5-7x for E&Ps, and 5-8x for service companies), to something approaching that of industrial companies (in the 8-10.5x range).  To be fair, the low-cost leaders in the industry have been hugging the upper end of that range for a couple years.

But on average, for both E&P and service stocks, this implies a 15-30% upside from current level if we assume a 1-2 turn improvement in multiples.

Conclusion: RJ posits that the habit of US energy producers massively overspending cash flow is ending. Rising production and falling supply costs position North American producers as sustainable, Free-Cash-Flow machines for the next 5-10 years—even if energy prices decline slightly.

If they’re right—and some recent evidence from BMO Nesbitt Burns supports their idea—then the energy sector should give buoyant returns to investors in the coming years.

+Keith Schaefer

The Debt Double Standard For Canadian vs American Energy Producers

By
Keith Schaefer
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0

The 49th parallel isn’t just a border between Canada and the United States. It also represents an important line for the amount of debt investors are willing to tolerate in their energy producers.

Investors and CEOs have both learned the hard way. Canadian producers with more than 2X debt to cash flow–sometimes even 1.5:1–get no love from the stock market.  Typical conservative Canadian investors–they have almost no tolerance for debt.

South of the border, energy producers can carry big debt relative to their cash flows and still get high valuations from stock investors.

Comparing the recently acquired North Dakota Bakken producer Kodiak Oil and Gas (KOG) with Canadian Bakken producer Lightstream Resources (LTS) shows the stark difference.

There’s lots of  similarities:

For 2014 Kodiak guided for production of 39,000 to 42,000 barrels per day. Lightstream’s 2014 guidance–updated for recent asset sales–is actually a little bit higher at 43,000 to 45,000 barrels per day.

Conclusion: Production levels are similar.

They’re both light oil producers, so they similar levels of cash flow. Lightstream’s first quarter annualized EBITA was $753 million while Kodiak’s first quarter 2014 annualized EBITDA level is $716 million.

Conclusion: EBITDA levels are similar.

Cash flow dictates debt capacity. With similar levels of production and cash flow/EBITA it’s no surprise that Lightstream and Kodiak carry similar levels of debt–$2 billion and $2.3 billion respectively.

The Debt to EBITDA ratio of each company using its first quarter 2014 run rate annualized therefore looks like this:

Lightstream – $2 billion / $753 million = 2.65 times

Kodiak – $2.3 billion / $716 million = 3.21 times

So it may surprise you to know the reputations of these stocks in the market; that is Lightstream having a weak balance sheet, and Kodiak doesn’t–despite Kodiak carrying more financial leverage than Lightstream.

This is the debt double standard and it shows up in how the market values these very similar companies.

Kodiak is about to be required by Whiting Petroleum (WLL) at a slight discount to where the stock has recently been trading.

The all-in (debt plus equity) price tag that Whiting is paying for Kodiak is $6 billion. That means that Whiting is paying roughly $150,000 per flowing barrel and 8.4 times EBITA.

Meanwhile the very similar Lightstream at its recent share price carries an enterprise value of $3.5 billion which means that it currently trades at $79,000 per flowing barrel and 4.6 times EBITA.

If Lightstream were to trade at the same multiples of production and EBITA as Kodiak its share price would be $22 or $23.  (To be fair, Canadian energy producers also trade at a small discount to US ones because of the Canadian “differentials”; our oil prices are lower because of pipeline constraints south, east and west of Alberta.)

Instead Lightstream’s shares languish between $7 and $8.

Now don’t take this to mean that I’m terribly bullish on Lightstream, because I’m not. I know the rules of the game and I play by them.

This management team is in the penalty box for past disappointments.  In late 2013 they cut in half a dividend that they had forever said was sustainable and then also subsequently reported a very disappointing 2013 reserve report.  Add to that capital spending that went over budget in 2013 resulting in very poor capital efficiency and you have a group that has a lot to prove.
I’ve used Lightstream because it was very similar to Kodiak in size, leverage and oil weighting.

Lightstream’s valuation predicament clearly shows how debt averse Canadian investors are relative to their American counterparts.

Other Canadian producers that carry much less leverage have valuations that are very similar to Kodiak’s. Companies like Crescent Point Energy or Raging River which have debt to EBITDA ratios at 1X or less regularly trade for $150,000 per flowing barrel or higher.

Take away the debt and the assets are valued similarly.

 

There Are Other Variables To Consider – A Big One Is Decline Rate

Kodiak and Lightstream are similar but there are differences.

Lightstream is diversified across a few oil plays while Kodiak is focused on the Bakken/Torquay. The profitability and payout times of the wells that each company is drilling is similar, but Kodiak’s wells are much more prolific and expensive to drill.

One big difference that should actually make Lightstream’s production more valuable than Kodiak is–Lightstream has a lower decline rate; i.e. the rate at which its production is declining naturally is lower than Kodiak’s.

Both companies are pure plays on horizontal oil production. In the first couple of years these horizontal wells have extremely high rates of decline. Production at the end of the first year of the life of a well can be down by more than 60%.
decline rates
By year three or four those decline rates settle in around 20% per year and get a little better from there.

Both Kodiak and Lightstream have close to 40,000 barrels per day of production, but because it has been growing so rapidly Kodiak’s production is much newer than Lightstream’s.

That means that it is declining much more rapidly and is going to require considerably more capital to just offset those declines in the coming year.

With two-thirds of its production less than two years old, Kodiak likely has a corporate decline rate that exceeds 40%. Lightstream which has more mature production has a decline rate that is around 27%.  Over 40% is bad, under 30% is really good for light, tight oil plays.
corporate decline rate

 

Fair Or Not–These Are The Rules of The Game

Like it or not (and I’m sure companies like Lightstream vote “not”) this debt double standard is the rule for investing in Canada.  A consequence of that is Canadians use more equity and have more shares outstanding than American producers.

If a CEO doesn’t want his company to suffer from a big valuation discount, he or she has to run with a clean balance sheet.

+Keith Schaefer

Ethanol vs. Natgas—the Summer 2014 Duel

By
Keith Schaefer
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0
How do you invest in the weather? When it comes to weather, what’s bad for natural gas is good for ethanol.  These two commodities are almost exactly opposite trades each summer.Hot weather–especially on the populated east coast–makes for lots of air conditioning demand in North America, which increases natural gas prices.A cool summer means low natural gas prices, but it means higher ethanol margins.  You see, cool summers make for a great growing season for corn—and this year looks like a record US crop.  The Market is now anticipating so much supply that pundits are now suggesting corn could drop to under $3/bushel this year.  Low corn prices and high gasoline prices make for high profits for ethanol producers.

Last week was the week the Market decided it was going to be a cool summer, and natural gas prices fell out of bed.  This week’s forecast is even colder:

global cooling
Source – http://bit.ly/globalcooling2014Eight weeks of natural gas injections above 100 billion cubic feet (bcf) plus last week’s number being only 3-5 bcf above expectations did it—combined with a very cool forecast for the Midwest US in the coming days.The Market is saying it now believes weekly natural gas storage injections in North America will get overall inventories to a high enough level by the time withdrawals start in late October or November–that it’s not worried.

The Market is also eyeing guesstimates by natgas industry experts Bentek and Genscape that production could jump by another 2-4 billion cubic feet per day (bcf/d) in 2015.  (The US now produces about 69 bcf/d.)

Natural gas price increases could now slide until Old Man Winter tells us how strong he is starting in November or December.  The only real question in my mind is…how shallow will the natural gas price dip be over the coming 4-5 months.

Now over to ethanol.  I expect retail gasoline prices to now drop with slightly lower oil prices, but the price of corn is likely to drop more, creating greater profit margins for ethanol producers through the summer.

As I said, the Market is expecting a record corn crop in 2014 in the US–mostly because of a very high yield (the amount of corn produced per acre).  As the chart below shows, corn yield have been trending up steadily for 50 years.  Because of the cool summer (corn yield start to take a hit over 86 degrees F), everyone is expecting the corn yield to be well above the trend line this year.

The trend line this year would put the yield somewhere between 159.5 bu/acre – 164 bu/acre.  But now I’m hearing 170 bu/acre or more for a potential record crop of 14.3 billion bushels (as context, drought stricken 2012 had a yield of 123.4 bu/acre).

For those of you wanting to go down this rabbit hole on your own, sign up for the ethanol updates athttp://farmdocdaily.illinois.edu/

corn yield

And….would you believe there is actually a statistical correlation between corn prices (and therefore yield) and the sunspot cycle?  I talked about this briefly in my Global Cooling trilogy.

The year 2014 is Year 7 in the current 11 year sunspot cycle.  Prices usually peak in Year 6, collapse in Year 7, and then slowly go back up thru Year 11 and up onto the next Year 6.

I am not making this up.  Why wouldn’t solar activity be the dominant factor in global temperatures, which by definition makes it impact agriculture in a huge way?

The cost of production for corn is around $2.60 a bushel for the really good low cost producers.  Give them a 10% rate of return suggests that corn could go to $2.85/bu before it bottoms—by then a lot of higher cost producers could/would not sell their corn.

Corn just slipped under $4/bu on Friday, closing at 399.6 cents according to the NASDAQ website, and then dropped to $3.81 on Monday.

corn (cbot)

Source: http://www.nasdaq.com/markets/corn.aspx?timeframe=1y

The global/macro picture for ethanol is strong, says US brokerage firm Credit Suisse.  In a July 11 report, they say global ethanol demand increased from 7.7 billion gallons in 2005 to 23 billion gallons in 2013, because of the Renewable Fuel Standard (RFS) in the US and also due to Brazil’s 20%-25% ethanol blending mandate.  They are projecting global use to rise to 32 billion gallons by 2022—only eight years away.  That’s positive.

BUT–the Big Risk for investors is domestic use of ethanol.  Ethanol in the US has now hit what is called the “Blend Wall”.  The gasoline industry must supply its product with 10% ethanol by law, and stats show the industry is there right now.  See this chart from a July 11 report by Credit Suisse on global ethanol demand:

ethanol blend ratio
And you better believe the oil industry is not going to give up one extra barrel to ethanol if they can at all avoid it—it’s a bitter fight, with both sides lobbying Washington fiercely.The US is finding export markets worth about 1 billion gallons a year now, in addition to the 13 billion gallon domestic market.  The US is now producing more ethanol than it can consume domestically, so it MUST continue to find export markets or ethanol prices will drop—and when that happens, it goes fast.  Production is increasing to take advantage of this stronger profitability:
ethanol production
SUMMARY–Overall the cool summer is benefitting ethanol more than natural gas. Cool weather is manifesting into much lower corn prices, due to anticipation of a record crop. The spread between corn prices and gasoline prices is the profit margin for ethanol producers.  Right now that spread looks to be going higher, and likely staying for longer than previously expected. (Last year was a great crop too.)Gasoline prices likely are coming down a bit, but not as much as the corn price so margins should expand for ethanol producers. Ethanol continues to trade at a steep 30% discount to gasoline, so there is a lot of room for price increases for ethanol if summer driving miles increases (ethanol often closes the gap on gasoline pricing in summer and can sometimes even trade at a small premium to gasoline).So how do you invest in weather?  Well, from a weather perspective, what’s bad for natgas is good for ethanol.  (That’s why I say there is ALWAYS a bull market somewhere in energy!) This cool summer almost certainly means lower natgas prices, and so I think natgas stocks have peaked.  I still hold some of the more compelling growth stories in natgas, but I have reduced positions dramatically.

I’m still holding all my remaining ethanol stocks. Profit margins for ethanol producers should remain strong for another full year, barring the mother-of-all-heat-waves in August 2014.   The three main pure play ethanol stocks are

Green Plains Renewable Energy                   GPRE-NASD
Pacific Ethanol                                                PEIX-NASD
Rex American                                                 REX-NYSE

I am long PEIX and GPRE.

+Keith Schaefer

Where This Fund Manager is Investing in the Energy Sector

By
Keith Schaefer
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0

What are The Pros doing in the Market? Each quarter I like to interview with a fund manager who I think has his pulse on what’s happening in the energy markets.

Today I’m sharing an interview with Martin Pelletier, one of the principals at TriVest Wealth Counsel in Calgary.  I only have to manage risk for one person; me.  They have to manage risk for a large number of clients which makes their take on the energy markets a bit different than mine.

Keith: Martin, you’re on the record recently as saying it’s time to take some profits on the energy sector—can you give us some colour on that?  Like, do you keep a disciplined selling strategy? Do you have certain numbers and metrics you go by to do that?

Martin: For sure. One thing I look at is what commodity price is being discounted in stocks and compare that to the forward curve. This tells me whether stocks are discounting higher or lower commodity prices than the future’s price.

Keith:  What’s that telling you right now?

Martin:  It’s telling you that the forward curve for gas and oil is too low and is going to have to move up OR investors in stocks could be wrong and stocks could go lower to match the curve. For example, a year ago it was the opposite as stocks were discounting lower oil and gas prices which is the type of value environment we like to invest in as we can hedge out some of the forward commodity risk.

We think energy should be a core component of any portfolio over the longer term given its inflation protection abilities. But there are periods where you want to have a greater exposure and periods you want to have a reduced exposure. This is where the exercise of comparing to forward commodity prices can be quite useful. It gets you thinking what kind of risks are being factored into the stocks?

Currently, we believe energy stocks have gotten a bid ahead of themselves especially among some of the juniors.  But we’re not in 2007 territory by any means. We do see more upside to the sector but there is no longer a table-pounding value proposition, that’s long gone.

Keith:  Where rising tides will lift all boats.

Martin:  Yeah. What concerns me is the high level of complacency in the sector among investors right now and especially among those buying junior E&Ps. People are overly confident since we’ve had a hell of a run with some juniors up 300% to 400%.

Keith:  Something crazy.

Martin: What’s crazy is that some of these companies are saying expect another double from here. They are compounding matters by returning to tactics of old with overly promotional press releases including such info as huge IP production rates on one or two days of testing.

Come on, even IP30s are pushing it in my opinion. The problem is that investors and analysts start extrapolating those production numbers and saying if they drill X amount of wells get the same results, and the wells don’t experience their usual hyperbolic decline then there will be massive growth going forward.
Proof is in the pudding and we know more often than not when you factor in risk into the equation the outcome will leave many disappointed especially since the bar has been set way to high from management.

Keith: So how do you manage risk in this environment now that most of the stocks worth owning have had such big runs?

Martin: A big focus for us is risk management. And there certainly is a lot of risk in the oil & gas sector. This means at times giving up some of the upside potential which typically retail investors and fund managers in the sector don’t like doing.

It tends to be more momentum based meaning more money comes in during market rallies and exits during corrections thereby compounding the moves to either direction. We’ll take it while the sun is currently shining but are keeping a close eye out for the first signs of a down turn.

That said, we’re starting to get a pick-up in volatility in the sector.

Keith: Yes, some days you think it’s going gangbusters and then 2 days later it’s party over.

Martin: This can be a problem in the energy fund management side as most managers are permabulls taking big swings and getting big payoffs – and it works when it comes to attracting new money.

Simply look at the inflow of those funds–up over 50% in the past year. Many forget that this style of management will often result in big draw downs during corrections often completely wiping out previous gains.

Martin: Investing in a really good management team who does good due diligence is important. They’ll investigate the risk of all the plays and allocate capital where they see the best risk returns. It’s almost like having a management team be your portfolio advisor on your energy portfolio.

The next question becomes how do you pick the better management teams? I think it comes down to consistency, humility and balance. A great management team will have consistent results that meets or surpasses expectations, humility in their forward assumptions and a balanced approach with a focus on risk-management.

Look at their assets, look at the production life and how diversified they are and their history of creating shareholder value. Then how are they managing the risk appropriately within their company? There are some really good teams in the patch that you’re going to have to pay a little bit of a premium for but they will protect that downside for you.

The same can be said when selecting an energy fund manager. Who do you want to invest with? You can invest with an energy fund manager that has the best 12 month returns right now but taking excessive risks not unlike some of the juniors. If there is a market correction how much will you lose? You’re coming in at a period of time where it’s had a nice run. If there is a broader market correction ask yourself how it that going to really relate into your energy portfolio?

Keith: That’s what separates the men from the boys at the end of the day.

Martin: All I’m saying is it’s been a great run and let’s not get ahead of ourselves. This is a time when you want to be humble and not after the fact. This is all 30,000 foot type stuff but there are ways you can protect yourself.

Number one, you want to pick the right management team; number two is you want liquidity so you can get out of your position if you had too.

Three is you want to employ some risk management and so if you’re overweight in energy at the moment maybe it’s a good time to rebalance. Take some profit off the table and not get caught up in the hype.

Finally, there are other strategies you can employ for hedging. For example, we’re pretty active in the option market as an overlay to our portfolios. We also can do other strategies in the energy fund such as going short which is useful when doing so against the underlying commodity.

What I’m generally saying is to be a little cautious here and not make a binary call just be very selective where you’re positioning.

Keith:  Where do you make money in this energy market right now?

Martin:  Services are the high torque play if you are bullish and believe the momentum is sustainable, however it does also have more downside risk if you are wrong with the call. Look at the moves in some of these pumpers (hydraulic fracturing companies–KS), for example, they can be quite volatile.

The midstream side would be the other end of the risk spectrum. While they’re not going to move to the same extent as the services, they have performed quite brilliantly. If you want to own oil or natural gas right now, own the commodity and not the stocks.

Keith:  What factors can take the market by surprise either up or down in the next 6 months?

Martin:  This feels different than the bull run we had in 2002 through 2007. It moved rather quickly and that’s not unusual but a couple of things to note.

First, energy typically rallies at the later stages of a broader bull equity market. The leaders are usually the consumers, discretionary and then it moves into industrials, transportation and then eventually works its way down to energy and finally materials.

When you have that happening in one of the longest running bull markets without a pull back since the 1960’s it causes some concern that if the broader equity market corrects, what’s going to happen to the energy sector? Probably more down side.

The other disconnect?  People aren’t picking up on emerging markets. We had a really good run in the 2002 cycle through to 2008 which corresponded with the rapid growth in China.

Many, including myself, were talking about peak oil and extrapolating and all kind of demand growth scenarios and saying we’re going to run out of oil, etc. Then we have unconventional development come out of nowhere which is a real game changer on the supply side.

On the demand side you now have China another emerging countries that are not in the same position that they were in back in 2005 or 2006 and so demand is somewhat muted or not as bullish as it was back then.

Therefore, you have a scenario where the demand growth is modest while supply has changed considerably due to unconventional development – a much different picture from 10 years ago. That said, the good news is that you still have the geo-political risk and actually it may be a little more escalated then it was back then and that’s the factor keeping pricing relatively high.

So if there is any mitigation on a geo-political side then we think there can be some downside risk to commodities. That’s what is being missed I think.

Keith:  That makes perfect sense.

Martin: It would be great to see China doing what it was in 2005 and 2006 and then I would be more bullish and recommend riding out this recent rally even more.…it was just the perfect situation back then. Now it’s not there anymore.

Keith:  So to get back to what I’m hearing, macro situation is a little weaker and production side is a bit stronger.

Martin: A lot stronger; the production side is a lot stronger. Look at the US and I don’t need to tell you you’ve done the work. Look at global unconventional resource development that’s a real game changer.

Keith: So the current oil price is taking a higher risk premium that you figured?

Martin:  Yeah.

Remember, it wasn’t that long ago every analyst was out there saying don’t touch Canada you want to go to the US.

Keith:  Right.

Martin: Now it’s the opposite. Its good times, all the money is supposedly coming back into Canada because of the “better value” up here. Forget about the transportation risk because we’ll deal with that via rail. Interesting that no one talks about these things anymore. It was clearly overdone a year ago, people were being too negative but now the gap has narrowed not to the point where these things are way ahead of themselves but the value proposition has gone away in my opinion.

Keith:  Right.

Martin: We’re not in that environment anymore. It doesn’t mean there isn’t further upside, it’s just wouldn’t be expecting huge gains for the next 12 months.

Keith:  I guess high grade the portfolio a little bit into the higher quality management teams, little bigger names?

Martin:  Yeah. If you do that don’t kick yourself if these things continue to run a bit higher. Be happy you made whatever the number is, 25% to 45% in the last year?

Keith: Anything else you think investors would be interested in hearing about? Any oddities in the market that you’re seeing?

Martin: I think I pretty much covered it. I mean I’m still bullish on the sector and still excited about the prospects but I think we’re due for a little breather here. I don’t like those companies who are over confident. I’ve been through so many cycles myself that I’ve learned that being humble during periods such as what we’re in right now can save you a lot of money.

I would like to remain very bullish like I was 12 months ago but it’s challenging when I don’t see some of the supporting factors in the market such as what we talked about with emerging markets. I think investors should keep a close eye on emerging markets because Canada is a 2nd derivative of it because of our resource exposure.

China, I don’t know if you’ve been following what’s happening there, it’s not necessarily in the best of shape with its corporate lending and financial system. If that turns and gets better then it’s really good news for Canadian energy.

Keith:  Martin, thank you for your time today.

You can learn more about Pelletier and his firm at www.trivestwealth.com

+Keith Schaefer

A Full OGIB Stock Report Part II

By
Keith Schaefer
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OGIB BULLETIN # 143  DECEMBER 3 2013PACIFIC ETHANOL – PEIX-NASD

COMPANY ANALYSIS – Part two

Below is Part II of my full OGIB Subscriber Report on Pacific Ethanol (PEIX-NASD).  Part 1 was published Saturday, which you can read HERE.  My goal is to help Free Alert Readers understand the level of research I put into my full reports.  This report appears exactly as it did on December 3; it has not been updated so you can get my thinking at the time.  I’m still longPEIX (though I have sold out my cost now).  Corn prices have been dropping hard recently as US crop estimates this year could produce a record yield—170 bushels per acre.  That’s very bullish for ethanol.

THE BUSINESS / COMPANY HISTORY

peix at a glance

Pacific Ethanol (PEIX) is the largest producer of ethanol in the Western U.S.   The company operates four ethanol production facilities; three are now active. The fourth should be re-activated in spring 2014.

The plants are located in California, Oregon and Idaho and have a combined production capacity of 200 million gallons per year.  The three operating plants have 160 million gallons, and they’re running at 95% capacity (because ethanol is so profitable right now!).

Here’s the breakdown:

  • Boardman, Oregon plan (40 million gallons)
  • Burley, Idaho (60 million gallons)
  • Stockton, California (60 million gallons)
  • Madera, California (40 million gallons / currently idle)

The Madera plant is likely to be restarted at some point in 2014.

PEIX management not only produce their own ethanol, they market ethanol for two other California producers—giving them a near monopoly on the product on the US west coast. They have a definite competitive edge there (They were actually an ethanol marketer first, and producer second).

Crush spreads, or gross profit margins, are roughly the same in the Pacific region as the Midwest, says CEO Neil Koehler.  They pay about 35 cents a gallon equivalent more for corn (rail costs from the corn belt in the US Midwest) but they get only about 21 cents a gallon more for ethanol than in the Midwest.  The same theory does happen for the secondary products of distillers grains—the premium pricing they get in the western states makes up for the transportation costs—so PEIX is essentially able to pass on higher transport costs directly to their customers.

While PEIX operates all four plants under a management contract, it owns only 85% of them.  Here’s why:

As I explained in the GPRE company report earlier this year, the United States ethanol industry in recent years has gone through a boom and then a bust, and is now booming again.

The bust was created as the industry built up too much production capacity—then corn prices soared in 2008/2009.   An oversupply of ethanol matched with a sharp increase in production (corn) costs was a sure recipe for trouble.

Pacific Ethanol was a victim of this bust—it was forced to declare bankruptcy in its subsidiary units (not the public company itself; it had non-recourse debt with its subs) with the company’s bondholders taking ownership of the four plants in May 2009.

Post-bankruptcy, PEIX the pubco has slowly repurchased an equity interest in the subsidiary that contains its four plants from its bondholders at different times.

But still bankruptcy is not a good thing for existing shareholders.  But in buying back 85% of all those plants, PEIXonly paid $0.32 per gallon of annual production capacity. The “new” estimated replacement cost of those plants today is $2.00 per gallon—so they negotiated a big discount. (But that’s only good news for new shareholders like me.)

PEIX shows in its corporate presentation (slide below) the prices it has paid to regain this ownership interest:

ownership interest

And the pain doesn’t end there.  CEO Neil Koehler and his team had to do SEVERAL dilutive financings to get those plant interests back—in both debt and equity.   There is now $119 million gross debt.  There are a lot of warrants at $7.78—there are some cheaper but the big tranche is $7.78—but that’s more than a double from my cost base!  I can sell out my cost at $7.77!

After raising all that equity, PEIX management—and it’s still the same team—had to roll the stock back—a reverse split—1:15 to continue to trade on the NASDAQ. OUCH!   Look at this stock chart below:

peix chart 4

The above chart shows a split adjusted share price of over $250 in 2010.  The stock bottomed out at $2.33 this fall.  That’s a 99% drop in share price.

So this team has A LOT to prove to the Market.  That is almost certainly why there are ZERO sell side analysts covering this stock right now.

FINANCIALS / VALUATION 

This summer PEIX was forced to address some problems with its balance sheet.

With $98 million of debt maturing in June 2013 PEIX was working against the clock.  In a complicated series of transactions the company was able to extend the duration of its debt through 2016 as well as reduce total debt outstanding by $13.5 million.

As part of this cleanup 13.4 million warrants with an average strike price of $7.78 per share were issued.  I have a list of all the warrants and strike prices here:

warrant summary

Shareholders were kept white-knuckled during this time as $4.1 million of debt that expired on June 25th was not repurchased until just days in advance of that date.   It’s tough playing chicken with your debtors…

It was a busy and likely stressful summer for PEIX management.

With all of its restructuring PEIX now has $120 million of long-term debt, $9 million of cash and about $14 million of unused capacity on its credit line.

That is the recent history.

One of my accountant friends told me that looking at financial statements is like looking in the rearview mirror.

Financial statements tell you about a company’s past, not where it is going.

When you look at the financial statements of PEIX there isn’t a whole lot to like.  Few profitable quarters, recent troubles with debt and a reverse share split.

But it isn’t the past that I’m interested in, it is the future.

I think Pacific Ethanol’s income statement is going to look a lot different in the next several quarters than it has in the recent past.

That change is due the huge ethanol margins that are available now for PEIX which is fully unhedged with plunging corn prices.

PEIX is going to make some hay in the next several quarters.

On top of the wide margins this company is going to enjoy there will also likely be a bump in revenue (and profits) from its currently idle Madera plant.

When I spoke with CEO Neil Koehler he indicated that for the $7 million it would cost to get the plant up and running PEIX could get $10 million in EBITA per year (and that’s assuming tighter margins than today).

I would expect this plant to come back on production for the spring 2014 driving season—which usually drives up gasoline prices, and profit margins for refineries. I think if they could afford to hedge in current margins of 55-60 cents a gallon they would restart is right away.  So the spring 2014 startup will still depend on profit margins at the time, but a couple of quarters of income from the current wide margins would add some cash to cover the startup costs.

Investors today either have never heard of PEIX (there is no sell-side coverage) or they hate it (suffered through the bankruptcy).

That is why few people have picked up on the fact that the with strong ethanol margins (not even as strong as today) this company could be trading at 2-3x 2014 earnings.

Talking with the one other newsletter writer who covers the story (institutional level; who did a very detailed financial model of PEIX) thinks that earnings could be as high as $1.16 per quarter.  That assumes ethanol margins of $0.50 per gallon—which is actually lower than the $0.65 per gallon where they currently are. And spot market margins have been as high as 80 cents/gallon in late 2013.

This math suggests that PEIX’s pro-forma earnings on $0.50 per gallon margins could be $4.64/share for 2014.

That puts the current share price of $3.76 at well under 1X 2014 earnings.  

Remember, that’s forward looking pro-forma math—we have no idea what WILL happen.  But GPRE is currently trading at more than 12X earnings, so you think PEIX could get some big multiple expansion if it strings together a few good quarters.

At these types of multiples it won’t take long for investors doing stock screens to pick up on a company trading at such a low multiple and revalue the company share price higher.

Earnings per share numbers would further increase if the Madera plant were to come back on production.

Another way to think about the valuation of PEIX is from the point of view of the replacement cost of its assets.

The company has 200 million gallons of production capacity at its four plants.  Since PEIX owns 85% of the plants that would be 170 million gallons net to it.

At a replacement cost of $2 per gallon that would suggest the plants are worth $340 million to PEIX.  Subtract the $129 million of debt outstanding and the company has an asset value of $211 million.

With the expected 16 million of shares outstanding by the end of 2014 we are talking about an asset value of $211 million / 16 million = $13.18.  On the fully, FULLY diluted 24.5 million shares it’s still $8.61

That makes the company look cheap on a per share basis both relative to likely earnings and the replacement cost of its assets.

WHAT THE ANALYSTS SAY

There are no analysts covering this story.  None.

STOCK CHART

stock chart turnaround

CONCLUSION

This is a turnaround story that is just starting to turn.

The bad news is behind this company and the hard work is done.  I’ve talked to CEO Neil Koehler.  He understands Job 1 is post a couple of solid quarters, pay down some debt and then the Market will see how cheap this stock is relative to earnings.   For the first time in 18-24 months he won’t be fighting liquidity issues; he and his team can now show the Market how well they can run the business.

There aren’t many opportunities to buy stocks at potentially less than 1X next year’s earnings.  This is one of them.  All Neil and his team have to do is not screw up and I think the stock gets re-rated to a 3-5x PE—which is a 300-500% gain for me!  At least, that’s the theory ;-)

There is certainly still risk involved as this company carries debt, is unhedged and management has yet to prove themselves to the Market.

But there is a chance to make three times my money here—from both better profitability and multiple expansion—without the company doing anything heroic.

I’m long 30,000 shares at $3.15.

+Keith Schaefer

A Full OGIB Stock Report

By
Keith Schaefer
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0
Free-Alert readers often ask me for an example of a full company report that I prepare for my subscribers onOGIB portfolio stocks.  So here is one that I did late last year on a stock that turned out to be my biggest win so far of 2014–Pacific Ethanol, symbol PEIX-NASD.Retail investors didn’t understand ethanol in early 2013 when I bought my first ethanol stock, Green Plains Renewable Energy (GPRE-NASD) at $8.70.  Few of my subscribers bought that stock, even as I added to my position at $10, $12 and $14.But after they saw the stock run to $30 in a year, they were very open to buying Pacific Ethanol when I introduced it to them at $3.15.  It’s a riskier stock than GPRE–smaller, and at the time not much cash and a lot of debt.  And frankly, I don’t like turnaround stories.  Turnarounds are usually 2-3 year timeframes, and retail investors don’t have the patience for that.But CEO Neil Koehler has made the best of a great situation; margins soared through Q1 2014 (much, much more than I anticipated at the time) and the company is now basically net debt free and a cash cow.You can debate the merits of ethanol all you want; I only care about the economics.  I continue to be long both GPRE and PEIX, and this report outlines why.  I have not updated the report at all–this is exactly as it went out initially to subscribers in December 2013.  This is Part 1 and Part II I’ll publish on Tuesday.

OGIB BULLETIN # 143  DECEMBER 3 2013

PACIFIC ETHANOL – PEIX-NASD

COMPANY ANALYSIS

I don’t like turnaround stocks.  But the compelling business case—and a potential valuation of 1x 2014 earnings, not cash flow—for Pacific Ethanol (PEIX-NASD) has me investing near the very bottom—30,000 shares at $3.15/share.This is the second ethanol stock for me in 2013—in February I bought Green Plains Renewable Energy (GPRE-NASD) at $8.70—it hit a high of $18 this year.  (Read that report in the Members Centre if you like this stock!) So I know the economics around this industry.  I currently own both.GPRE trades at 12-15X PE—PEIX trades at 1-3x forward PE, depending on how much money they make in 2014.  GPRE is the 4th largest ethanol producer in the US, and the largest pure play at 1 billion gallons a year; PEIX is about 200 million gallons.  GPRE has 36 million shares out; PEIX has 16 million. PEIX has lower valuation, lower share count, and more leverage.Think of PEIX as a refinery—because it is.  It refines corn into ethanol, instead of oil into gasoline.  And right now the price of corn is low, and the price of gasoline is rising—making for great profits for this company—likely through 2014.Ethanol is cheaper than gasoline right now, and big oil refineries have a lot of incentive to use as much ethanol as their conscience will allow.  Ethanol has no subsidies.  It is a market-driven commodity.  Even without the Renewable Fuel Standard (RFS) by the US government than mandates about 13 billion gallons a year be used—ethanol as a fuel would still have a robust customer base (from the very refineries who decry it!).

Of course, there is a good reason why PEIX has such a low valuation and such huge leverage—they’ve gone bankrupt once and management has to prove themselves to the Market.  I’ll get into a bit of detail on that.

But my investment is based on the idea that their troubles are behind them; the industry’s troubles are behind it, and Q4 2013-Q4 2014 has the potential to be profitable for PEIX it could easily get some multiple expansion to 5-8x PE, which would result in a multiple of the current stock price.

QUICK FACTS

Trading Symbols: PEIX-Nasdaq
Shares Issued: 16 million—FULLY DILUTED=24.5 million
Share Price: $3.76
2014 Projected EPS : $1.16-$4.64
Market Cap: $60.1 million
Net Debt: $109 million
Enterprise Value (EV): $169.1million

www.pacificethanol.net

POSITIVES

– four fully built and functional ethanol plants
– debt/liquidity issues resolved now
– ZERO analyst coverage by sell-side stockbroker firms
– underfollowed by institutions because of low market cap
– profit margins soaring now with huge 2013 corn crop
– trading at a tiny price to earnings ratio
– trading at a fraction of the replacement cost of ethanol plants

NEGATIVES

– leverage and exposure to corn prices works both ways
– previous bankruptcy filing will keep many investors away
– some remaining dilution from restructuring is still to come
– the company still carries a significant amount of debt

WHAT IS ETHANOL

Pacific Ethanol takes a feedstock (corn) and turns it into ethanol.  Two ethanol by-products—distillers grain and corn oil—can also be produced.

Ethanol plants use natural gas, chemicals and enzymes to turn corn into ethanol.

First, smash the corn and put it into a tank.  Mixed with water and enzymes and then heat—this turns the corn starch into a sugar.

The mixture is then moved into a fermentation tank and mixed with yeast and chemicals/antibiotics (to control bacteria).

This new gooey mess is fermented for half a week at a high temperature, and then distilled to separate out the ethanol.

The two major costs are corn (by far the biggest) and natural gas.  Some simple math shows just how much the price of corn affects the all-in cost for producing ethanol.

THE SIMPLE MATH

Each gallon of ethanol requires roughly .35 bushels of corn; conversely a bushel of corn makes 2.85 gallons of ethanol.  If corn was priced at $4.25 per bushel (roughly where it is today–) that would mean the cost of corn in each gallon of ethanol produced is $1.49.  Ethanol sells for $2.50/gallon now.

Natural gas is the second largest non-fixed cost. With $3.50-$4.00/mcf natural gas prices, each gallon of ethanol would have a natural gas input cost of something like $0.14 to $0.16 per gallon.

You can figure out the economics of ethanol quite easily too, using all the same math.  At $4.25/bushel corn—you can go to Bloomberg and get the daily corn price per bushel (here’s the link: http://www.bloomberg.com/markets/commodities/futures/agriculture/ )—

bloomberg

Then multiply it by 0.35 to get a gallon of ethanol cost ($1.49/g) and add 15 cents for natgas—we’re now at $1.64/g—and you get a pretty rough but accurate cost for ethanol.  The NASDAQ publishes a daily ethanol price per gallon—here’s the link: http://www.nasdaq.com/markets/ethanol.aspx, and the difference between the two is profit.

ethanol futures

That’s called the crush spread—just like in oil refineries you have the crack spread as a measure of profitability.  On the day I’m writing this, Dec 2 2013, corn is $4.25/bushel at Bloomberg, and ethanol is $2.20/gallon at NASDAQ.  So the basic corn crush spread today is $2.20-$1.64=56 cents a gallon.There’s actually a lot of regional difference around the US—so remember that’s a rough, general number that gives you a sense of where the profitability at the industry is.
custom blooberg

THE ETHANOL MARKET

I just explained the simple economics of ethanol.  The most important thing I want investors to understand is that ethanol is NOT subsidized; it is a real market with real economics—like I just showed.

Investors get confused when they hear that the US government mandates a certain amount of ethanol be mixed in with gasoline—it’s called the RFS, or Renewable Fuels Standard.

I’m agnostic on ethanol mandates; my job is to make money whatever the rules are.  It does raise some big emotions in the Excited States of America though.

The RFS says US refineries must use 13 billion gallons of ethanol next year, or use ethanol credits, called RINs, to make up the difference.  RINs are Renewable Identification Numbers—one for each gallon of ethanol ever made.

There was a lot of RINs around for years because ethanol was so economic to use, nobody used RINs.  Then when corn prices spiked in 2012 because of the drought, ethanol wasn’t economic, and everybody wanted to use RINs.  RINs went from 2 cents to $1.50 a gallon in 2013 as a result.   But now that ethanol is once again very economic, RIN prices have fallen back a lot, and the reduced RFS ethanol mandate for 2014 has made them fall back even more.

A funny thing happened on the way to a reduced ethanol mandate: ethanol prices and margins increased—which is not what the Market expected.  Because of the high pitched rhetoric between ethanol and oil producers over the RFS, investors can forget there is a real market for ethanol not based on subsidies.  Since the RFS has been reduced, corn prices have stayed at $4ish/bushel while gasoline and ethanol prices have gone up—taking PEIX and GPRE margins with them!

Contrary to what you read on the web, ethanol is not a political commodity.  It’s a market based commodity–and it makes economic sense for refiners to use it.

ethanol inventory
This chart shows ethanol inventories continuing to decline, even after the RFS reduced its mandate.  That’s very bullish.  A real ethanol shortage/supply crunch—led by demand, even after a reduced RFS mandate—is driving ethanol prices higher right now.  See the recent spike in west coast ethanol prices (it has happened all over the US—the New York harbour price has done the same thing on the east coast.
Los Angeles ethanol

A supporting factor for 2014 ethanol should be higher US net exports.  There’s a large ethanol market globally, and the US imported a lot of ethanol when corn prices spiked.  Now, in Q4 2013, the US is a big net exporter and I expect that to continue through 2014.  Corn is so cheap now that the US is the global low cost supplier—and net exports could rival 2011’s 1.1 billion gallon record.  You can see in the chart below how ethanol imports soared along with corn prices as the US mid-west drought hit in June 2012.

us ethanol import exports

In 2013 there was a record or near-record corn crop in the US—over 93 million acres planted and a yield of close to 155 bushels per acre—one of the highest ever.  That drove down corn prices, making ethanol a lot more profitable—and started a new wave of exports that should continue into 2014.

Here’s an ironic positive to the PEIX story—because they have just refinanced their debt and equity, they don’t have a lot of cash on hand.  They literally cannot afford to hedge their production.  That costs about 10% down for the amount you want to hedge.  PEIX doesn’t have it.

Not that they would want to—the spot market is where the Big Margins are now.  But they are running the business completely opposite to GPRE, who hedge out every gallon they produce usually, and only recently started doing more spot sales.  That is actually a lucky irony, and should make them buckets of extra money the next 2-3 quarters.

SECONDARY PRODUCTS BESIDES ETHANOL

Like GPRE, Pacific Ethanol also sells distillers grain and corn oil which are two add-ons / by-products from ethanol production.

Distiller’s grains are sold to cattle farmers (both dairy and beef) as a high protein feed supplement.  Using feed that has a 20-30% distiller grain content helps cattle put on weight and increase milk production.  It also reduces the cost of feeding the animals.

In order to sell corn oil an ethanol producer first needs to install corn oil extraction equipment.  That’s usually a $3 million cost, with payback in less than a year.

diversifying revenue

At this point PEIX has its Magic Valley Idaho plant equipped to extract corn oil. They have (or is about) to commence corn oil production at the Stockton plant as well.

The costs involved in adding corn oil separation are minimal so this is a very high margin by-product for ethanol producers like Pacific Ethanol.

The corn oil production won’t make or break the company, but it is a nice bit of incremental income. A typical ethanol plant would produce roughly .15 pounds of corn oil per gallon of ethanol that is produced. Pacific Ethanol estimates that corn oil sales at their Magic Valley plant will create up to $4.5 million of operating income annually.

The corn oil produced is not suitable for human consumption, so it is used as a soybean oil substitute.

PEIX also makes a little bit of money through its own marketing subsidiary.

Through Kinergy Marketing, PEIX markets (sells) ethanol, distillers’ grains and corn oil for other producers.

marketing business

Marketing third party ethanol and by-products is not a high margin business, but it keeps their fingers in a lot of pies, it helps solidify their market presence and it pays for the overhead.

Now, just quickly I’ll explain that the Magic Valley Idaho plant is increasing profits by an extra 10% because of a great deal cut by management. PEIX management was able to secure a huge supply of sugar—which can be a partial substitute for corn in the ethanol process—from the US government at crazy low prices—4 cents then 2 cents a pound, in two separate purchases.

They’re running 15% sugar now, and increasing profits by a full 10%! The reason they’re not running it 100% is because if you run ALL sugar with your corn in your ethanol process, you can’t make corn oil or grains—and they have customers in the feedstock business they are committed to.  And, CEO Koehler told me it that there’s no guarantee they could keep getting that ridiculously cheap sugar year after year.

PEIX has actually done an intriguing job of sourcing out-of-the-box sugar sources, like old wine from California.  It doesn’t really amount to much (except for the sugar!) but it shows they’re thinking.

in Part II on Tuesday, I’ll get into the nitty-gritty business, explaining to my subscribers at the time that the ethanol business has been unbelievably volatile, and it just about killed PEIX.  But of course, that was our opportunity….And I touch on some ideas around valuation and economics.

+Keith Schaefer

Iraq: Why It’s Worse Than You Think

By
Keith Schaefer
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0

Everyone knows that Iraq is an important oil producing country. But Iraq is more than just important, it is critical.

Iraq is so important that in October of 2012 the International Energy Agency (IEA) released a report called “World Energy Special Outlook On Iraq”.

In that report the IEA concluded that in 2035 oil prices would be $215 if Iraq could increase its oil production by 266% from 3 million barrels per day to 8 million barrels per day. (Could–not couldn’t)

iraqi oil production

Source of image: IEA – World Energy Special Outlook On Iraq

Drink that in for a moment.

$215 per barrel is the IEA’s scenario if everything goes swimmingly well in Iraq over the next 20 years. Given the long history of instability here, the IEA’s vision seems like a very optimistic one.

Last week’s violence in Iraq, the IEA scenario seems almost absurd. If oil is expected to be $215 per barrel in 2035 if Iraqthrives, what will the oil price be if Iraq falls apart or just keeps production steady?

It won’t be pretty, especially for poorer countries.

Now, I’m the first to say any prognostication that goes 20 years into the future is as useful as screen doors on a submarine.  But let’s look at the two main reasons why the IEA says the world needs a lot more oil production by 2035.

The first great call on new oil production comes from the relentless thirst for oil that belongs to the emerging middle class of the billions of people in emerging countries. China and India lead this group that also includes all of Africa, Southeast Asia and Latin/South America. The people in this part of the world use on a per capita basis a tiny fraction of the oil that Westerners do, and every day they are fighting to live a more Western lifestyle.

The second great call on new oil production is that currently producing oil fields across the globe produce less and less oil every month. All in, these fields decline in production at 6% per year, which means that the world will require an additional 40 million barrels of new production to just replace those declines by 2035. To put that in context, it means the world needs to bring on new oil production equal to four Saudi Arabia’s.

How important the IEA believes Iraq’s contribution towards meeting global oil demand needs to be is shocking. The Agency has earmarked Iraq to provide 45% of the global growth in oil production by 2035.

growth in oil production

Source of image: IEA – World Energy Special Outlook On Iraq

Yes, Iraq, a country that has been in a state of chaos for virtually its entire existence, is the key piece in the energy supply puzzle for the future of the entire globe.  Alice, pass me the gravol.

Historical Iraqi oil production won’t calm your stomach either. Recent Iraq oil production has been bouncing back and forth between 3.3 million and 3.5 million barrels per day. That level is the highest production has been in 30 years dating back to 1976.

production history

As you can see in the graph above that 3.5 million barrel per day figure has been approached a couple of times in the past 30 years–but never stays there for long. The world needs a lot more than for Iraq to just deliver 3.5 million barrels per day consistently. The world needs Iraq to more than double that all time high level of production and then grow some more from there.

There is nothing in the history of this country to lead us to believe that a long sustained run of big–unprecedented even–production growth is possible. And the news coming out of the country certainly provides no reason to believe the future would be any different.

The Good News – Most Of Iraq’s Oil Production is Not Currently In Harm’s Way

The IEA’s vision for Iraq production growth is certainly questionable. The good news is that the group calling themselves theIraq/Syria Islamic State (ISIS) is actually not likely to materially disrupt Iraq oil production in the near term.

ISIS is an extreme Sunni group that is small in number (Iraqi officials estimate the group has 6,000 soldiers) and that doesn’t have much popular support. The headlines the group has been making by gaining control of cities have been in regions divided by religion like Mosul and Tikrit that were extremely unstable to begin with.

These are not regions with significant oil production.

The great majority of Iraq’s production is found away from current hostilities either in the south of the country within the borders of the Shiite majority or in the Kurdish region in the north.

iraq oil fields

Source: Source of image: Securing America’s Energy Future

Iraq’s historical production has been dominated by just two super giant oil fields. There is the Rumaila field that has produced over 14 billion barrels since the 1950s in the Shiite south and the Kirkuk field which has produced a similar amount since the 1920s in the northern Kurdish region.

A third super-giant field called The West Qurna is also located in the Shiite south and with 44 billion barrels of recoverable oil is the second largest oil field in the world. West Qurna is targeted to be the primary driver of Iraq production growth.

iraq oil resource
Source of image: IEA – World Energy Special Outlook On Iraq

Iraqi oil production is now split roughly 75/25 between the Shiite south and the Kurdish north.

The fighting has however already impacted some of Iraq’s key oil infrastructure, most notably a pipeline that can deliver 600,000 barrels of oil per day from Kirkuk to the city of Ceyhan in Turkey which is damaged and offline.

What the fighting also does is make Western oil companies hesitant to invest capital in Iraq. The IEA estimates that more than $15 billion needs to be invested every year in Iraq in order to generate the anticipated level of production growth. Without at least the appearance of the country moving closer to stability, it seems hard to believe companies will be willing to risk that kind of money.

Reality May Be Setting In

The actual near term threat to oil production from ISIS is likely not as significant as the frightening headlines make it seem. What the headlines may be doing however is waking the world up to the fact that Iraq’s success as a growing oil producer is critical to the entire world and also to the fact that the country is in no better shape than it has been over the last 30 years when production has sputtered.

The Sad Truth is that one has to wonder if Iraq isn’t in worse shape than it has ever been. And that isn’t good considering what the IEA says its importance to global energy security.

 

by +Keith Schaefer

The Bakken Gets Bigger—Likely A LOT Bigger

By
Keith Schaefer
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0

Crescent Point’s Torquay Discovery Reignites Southeast Saskatchewan

Just when you thought The Bakken couldn’t get any better—it does.

Oil producers are now “cracking the code” on the Torquay, or Three Forks formation below the Bakken, and coming up with incredible economics—these wells are paying back in only seven months.

This news has completely re-invigorated the Canadian side of the Bakken. And on the US side, the Three Forks is causing industry to leap-frog estimates of the amount of recoverable oil available–by about 57%!

It’s hard to imagine that the #1 oil play in all of North America could have such a huge increase in size—usually this happens in increments. This map from the Province of Manitoba shows how much potential theTorquay/Three Forks has—it ranges from 1.5 – 7 x as thick as the Bakken!

basin variability

 

Results from Crescent Point Energy (CPG-TSX/NYSE) in Canada and Continental Resources (CLR-NYSE) onthe US side of the border are showing this could be an incredible discovery. The Torquay/Three Forks could prove to be another multi-billion barrel catch for the North American oilpatch.

Now when I say discovery; what I really mean is the industry has discovered how to produce from it profitably. Theindustry has known it’s potential for several years now.  But the Bakken source rock itself has been so prolific, there wasn’t much incentive to drill deeper and go through a new learning curve at the Three Forks.

On April 14 Crescent Point Energy (CPG-TSX) announced a Torquay discovery in its core Flat Lake area in southeast Saskatchewan, right along the US border. In just 12 months, the company grew production from 0 to over 5,000 boe/d by drilling 36 wells. These are low-decline, high-rate-of-return wells that payout in less than 7 months.

(A 7 month payback is incredible. It’s the simplest measurement for retail investors to know how good a play is. I like to see 12-15 month payouts, and don’t like to invest in plays that have more than 18 month payouts.)

CPG says each well costs $3.5 million all-in on a 1–mile horizontal. These well economics are fantastic:

1. More than $73/boe in operating netbacks (netback=profit per barrel)
2. A recycle ratio greater than 6–that’s profit divided by costs. That’s 6 times your money! 2 is good; 6 is great!
3 Generates an IRR > 300%. I like to invest in anything over 70% IRR.

CPG believes the Flat Lake Torquay discovery has the potential to match its core, Viewfield Bakken play in southeast Saskatchewan. The oil field is estimated to hold 4.6 billion bbls OOIP.

torquay

 

This eye catching news triggered an acquisition spree; Crescent Point was the first mover with the acquisition of privately held CanEra Energy with 10,000 boe/d and a large Torquay land position only 10 days after its discovery announcement.

viewfield

 

Crescent Point’s acquisition locked in more than 880 net sections of Torquay potential land with more than 280 net sections in its delineated core area. The largest Bakken producer in Canada is positioning itself to becomethe number one Torquay player.

Legacy oil and gas (LEG-TSX) and Vermillion Energy (VET-TSX) have also made acquisitions of their own buying up privately held companies with land in the emerging play at Flat Lake—all at high metrics of over $100,000 per flowing barrel.

Production out of the Torquay/Three Forks has a lot more history on the US side of the border.
GEOLOGY BACKGROUND

The Bakken formation is located within the Williston Basin encompassing 25,000 square miles across southern Saskatchewan, upper Montana, upper North Dakota and western Manitoba. Unlocking this formation propelled North Dakota from the 9th largest oil producer in 2006 to no 2 behind Texas with more than 900,000 barrels of oil per day.

stratigraphic column

The Bakken formation is actually three layers of rock—Upper, Middle and Lower–and is situated above theTorquay/Three Forks. The underlying Torquay actually has four layers of tight rock identified as TF1 (upper layer), TF2, TF3 and TF4 (deepest layer).

Last year, the US Geological Service (USGC) updated its assessment to include the upper part of the Torquay, about 50 feet in thickness. For the two formations, the US Geological Service USGS estimates mean recoverable oil resources of 7.38 billion barrels. Estimates for the Torquay account for 3.7 billion bbl.

These estimates seem very conservative to Continental Resources; the largest acreage holder in the Bakken is more optimistic about the total amount of oil that could ultimately be recovered.

In its own assessment, Continental believes that including the deeper parts of the Three Forks increases the total amount of oil originally in place (OOIP) from 577 billion barrels of oil to 903 billion, and the amount that is technically recoverable from 20 billion barrels to as much as 32 billion, 36 billion or even 45 billion.

tight oil plays

 

Only the upper layer (TF1) of the Torquay has been de-risked leaving the remaining 3 layers up for exploration. Continental has a pretty good reason to be optimistic. The company got impressive IP rates from drilling into thelower layers of the Torquay/Three Forks formation in McKenzie Country, North Dakota.

In its Q1 release, the company reported drilling eight new wells (two in each of the MB, TF1, TF2 and TF3) with a combined maximum 24-hour initial rate of 22,460 Boe per day or 2,810 Boe per day per well.

rollefstad

Continental also reported that seven newly completed TF2 and TF3 initially produced at approximately 285 Boe per day in its Tragsrud Unit in Divide County, ND. That’s right across the border from the Flat Lake area.

For Continental the play is simply getting bigger and better. But despite these successes, the Torquay remains largely unexplored. Continental barely scratched the surface of this play as more wells will be needed to test thedeeper layers of the formation.

For all this positive news, it’s important for investors to remember that the Torquay/Three Forks is still in its early stages and different areas and formations may respond differently. The Torquay is as much as 270 feet thick inthe central part of the basin.

In Canada, the formation is shallower but with similar thickness. This translates into lower drilling & completion costs per well than the other side of the border.

The Torquay is heating up with the potential for being the next big light oil resource play. The size of the prize is just too big to ignore and bodes well for other smaller players in southeast Saskatchewan like Painted Pony (PPY-TSX) Spartan Energy (SPE-TSX), Legacy Oil and Gas (LEG-TSX), TORC OIL & GAS (TOG-TSX), Surge Energy (SGY-TSX), Vermillion Energy (VET-TSX) and Lightstream Resources (LTS-TSX).

In the US, companies like American Eagle Energy (AMZG-OTCBB), Emerald Oil (EOX-NASD) and Triangle Petroleum (TPLM-NASD) stand to benefit from Torquay/Three Forks development.

To conclude, the Bakken was the hottest oil play in North America last decade. Investors made fortunes with theBakken in its early years and a similar investment scenario may now unfold as the Torquay/Three Forks zonegets increasingly tested in the coming months.

by +Keith Schaefer

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