Monthly Archives: July 2012

A Few Notes on Biofuels

The use of biofuels is a controversial subject these days due the combination of food inflation and growing energy needs.   The 2008 Farm Bill, which expires in June, 2013, contains subsidies for the ethanol industry as the U.S. government looks to decrease carbon dioxide emissions and encourage the use of renewable energy in light of rising fuel costs.  Due to rising food prices, caused in part by the use of corn-based ethanol, the 2008 Farm Bill emphasized the use of “advanced ethanol” or ethanol created from non-corn based feedstocks, while de-emphasizing/reducing subsidies for corn based feedstocks.

Cellulosic ethanol, or ethanol which doesn’t use the food portion of plants, was popular in the 2008 Farm Bill, because it doesn’t have as large of an effect on food prices, it has shown the ability to grow on sub-standard farm land, and it needs very little maintenance (water/fertilizer/pesticide).  I would assume its main effect on food prices is that it will take up a certain amount of land that would otherwise be used to grow food.  Cellulosic ethanol is derived from prairie grasses (switchgrass), hybride poplar and willow trees, and biomass waste.

A House Committee recently passed a $500 billion farm and nutrition bill, but the House appears to have little desire to take this bill up anytime soon.  The Energy Policy Act of 2005 created the Renewable Fuels Standard, which capped production of corn-based ethanol feedstocks at 15 billion gallons per year, with advanced biofuels expected to fuel the balance of a 36 billion gallon biofuels mandate by 2022.  It will be interesting to see how the finalized bill supports the different types of ethanol feedstocks, as advanced and cellulosic ethanol production has failed to meet expectations after the 2008 bill due to issues with commerciality.  What does this mean? In order for the government’s biofuels goals to be reached, we are going to need to use more corn which will increase food prices.

The U.S., who is the global leader in biofuels production, is clearly pushing to make them a significant component of its future energy needs.  Biofuels production has increased 7.5x during the past decade to 207 million barrels (8.7 billion gallons) in 2011 (see graph below).  The U.S. Navy is onboard with the idea, with plans to allocate $170 million of the $420 million government budget to build refineries capable of producing ten million gallons of biofuel annually to fuel navy jets and ships.  Continental Airlines became the first U.S. passenger plane company to use biofuels in November, 2011, when it flew a flight powered by a jet fuel blend of conventional fuel and biofuels (algae and plant waste).  Air Canada is currently testing biofuels in flights (that’s how some of its Olympic athletes got to the London games), claiming its blend will reduce emissions by 40%.

Source: BP Statistical Review of World Energy 2012

The next step with my blog with respect to biofuels is a price per gallon comparison with gasoline.  That piece will hopefully give us a little more perspective on the cost differences between not only biofuels and gasoline, but corn-based ethanol versus say cellulosic-based ethanol.  The government doesn’t want to use corn, and for good reason, but that appears to be the only source of biofuel that is commercially viable at this point.


Do biofuels really decrease carbon dioxide emissions? Several scientists think we may be double counting certain emissions reductions.  There is also belief that ethanol is corrosive by nature which could hurt engine durability.


The summer Olympics has quite the advantage over winter with respect to number of sports categories.  We got table tennis for the summer, why no air hockey for winter?


Global Energy Consumption Trends

Top 10 Energy Consumers by Country

Source: BP Statistical Review of World Energy June 2012

From 2001 to 2011, annual global energy use increased 30% to 487 quadrillion British thermal units (BTUs).  China started the 21st century consuming less than half the energy the U.S. consumed, but surpassed the world’s previous leading energy chomper before the decade ended.  Other countries that contributed to the global energy consumption increase are China’s fellow BRIC members, India and Brazil, who saw increases of 88% and 46%, respectively.  Canada aside, the leading Western energy consumption states saw either stagnation (U.S.) or contraction (Germany, France).  This isn’t all that surprising, as the developing world should be leading the way in energy consumption growth, which tells budding entrepreneurs and investors where to start thinking about putting their capital.

Global Energy Consumption by Region

Source: BP Statistical Review of World Energy June 2012

The above graph gives us a macro perspective on who’s consuming energy on this planet.  Energy hogs China, Japan, India and South Korea have Asia Pacific leading the way, responsible for 39% of global energy consumption in 2011.  Europe and North America are next in line; however you can tell by looking at consumption changes over the period studied that those regions are not the growth stories in this analysis.  Iran, Qatar and Saudi Arabia are driving growth in the Middle East, while Israel is beginning to stagnate.  Argentina, Brazil and Peru lead the way in Central and South America; energy consumption in most of Africa is on the move, with Algeria, Egypt and South Africa spearheading growth.

Which of the Top Energy Consumers are Using Renewables?

Most would be surprised to learn that Brazil and Canada are two of the top renewable energy countries in the world, with renewables responsible for 39% and 27% of their total energy consumption, respectively.  Hydroelectricity is responsible for most of their renewables, and while most people think of wind/solar/biofuels when they think of renewables, hydro shouldn’t be forgotten as a renewable energy source.  Germany, China and the U.S. produce more of what we all think of when we think renewables, but renewables still represent a small, yet growing, portion of energy use.

Noble Nets $320 Million in Sale of Non-core Assets in the Permian

On July 24, 2012 Noble Energy (NBL) agreed to sell certain producing properties in the Permian Basin to Sheridan Holding Company (private) for $320 million.  The properties were producing 1,500 barrrels of oil equivalent per day (BOEPD) which implies a daily per barrel value of $213,333.

Per Basin Multiples (TTM Production Data as of 3/31/2012)

Kodiak (KOG) and Sanchez (SN) are pulling up the average production values in this analysis, so ignoring those two valuations we can clearly see that NBL received good value for their properties.  Even though the properties were producing 90% oil and liquids, a much higher cut than the Permian Basin companies looked at in the above analysis, the valuation is still 20% and 36% higher than Bakken pure-plays (who have similar oil/liquids cuts) Northern Oil & Gas (NOG) and Oasis Petroleum (OAS), respectively.

Check my post on Concho’s (CXO) purchase of Three Rivers Operating (private) on May 13, 2012 for further acreage comparables in the Permian.

I should note that while NBL received good value, its acreage was quite a bit more developed than the acreage of my comparables.  The acreage sold contained 250 wells on 11,000 acres, which equates to 44-acre spacing per well.

CNOOC Buys Nexen for $15.1 Billion; Expands North American Shale Holdings

On July 23, 2012 China National Offshore Oil Corporation or CNOOC Limited (NYSE: CEO) reached an agreement with Canadian E&P company and former Occidental Petroleum subsidiary, Nexen Inc. (TSX: NXY, NYSE: NXY), to acquire Nexen for $15.1 billion.  This deal marks CNOOC’s second foray into North American shale, as the company purchased 199,800 net acres in the Eagle Ford Shale from Chesapeake Energy in October, 2010 for $2.16 billion or $10,811 per acre.  The deal does still have one more hurdle: approval by the Canadian government.

The Assets

Nexen’s assets are spread out between Canada, UK’s North Sea, deep-water Gulf of Mexico and offshore West Africa.  Its core assets are in the Canadian oil sands at Long Lake and Athabasca (joint venture with Syncrude), which contribute 577 million or 64% of NXY’s total proved reserves.  These assets complement CNOOC’s existing assets at Long Lake which it received through the purchase of OPTI Canada last year.

NXY’s offshore assets in the North Sea and at Usan (offshore Nigeria) are attractive because they receive Brent crude pricing, which priced at a $15.17 premium to WTI during the three months ended June 30, 2012.  The Usan asset is currently producing 100k BOEPD gross (NXY has 20% working interest) with facility capacity at 180k BOEPD gross.  The company has several additional exploration targets in offshore Nigeria which represent additional upside.

What I like most about this deal for CNOOC is the shale gas potential it’s buying in Northeast British Columbia (see map below), where the company is purchasing 300 net acres in the Liard, Horn River and Cordova Basins.  Reservoir engineering firm Degolyer & MacNaughton estimate contingent resources in the Horn River and Cordova Basins of approximately 15 trillion cubic feet (Tcf) and prospective resources in the Liard Basin of an estimated 22.5 Tcf.  While CNOOC has a ways to go to develop and prove these plays, they have the potential to be significant resources for the company.

Additionally, TransCanada was recently selected to build a pipeline from Northeast BC to the Pacific coast, where companies like Shell, Apache and BG Group have LNG terminals which could one day export 1.3 Tcf annually to Asia where companies currently receive much higher prices for natural gas than they do in the U.S.  Note: During 2011, companies received $14.73 per MMBtu from Japanese hubs (Source: BP SRWE June, 2012) .

Valuation (based on $15.1 billion purchase price and $17.9 billion enterprise value)

CNOOC purchased all of Nexen’s outstanding common shares for $27.50, a 61% premium over NXY’s Friday closing price of $17.06.  NXY’s stock price has been under pressure during the past year, closing as low as $14.10 on December 14, 2011, 17% less than its Friday closing price and 49% less than the price paid per share by CNOOC.

EV/Production ($/BOEPD): $86,696 per BOEPD

EV/Reserves ($/Proved Reserve): $19.94 per proved reserve

How do these metrics compare to companies operating in U.S. basins?

On both a reserve and production basis, Nexen’s assets are being valued low for a company whose oil cut is 92%.  Part of the problem with NXY is its exposure to low margin oil sands production which account for 64% of its reserves.  Additionally, the company has $4.4 billion in debt and a debt-to-market cap of approximately 49%.  That isn’t a terribly high debt load for a company of NXY’s size, but if oil prices trended low for an extended period of time, it could have issues paying its debt.

I view this as a solid deal for CNOOC, because in spite of its reserves being weighted towards oil sands, 52% of its current production comes from the North Sea where it receives Brent crude prices.  During the three months ended June 30, 2012, Brent traded at $108.66 per barrel, a $15.17 premium to WTI.  This premium helped NXY earn an average realized price of $88.65 per BOE, only a $4.84 discount to WTI.  This discount is competitive with the differential Bakken producers are receiving in the Bakken, and maybe even a little better.

Global Oil and Gas Proved Reserve, Production Trends

Oil: Proved Reserves and Production Levels by Country in 2011

Source: BP Statistical Review of World Energy June 2012

Note: Proved reserves include condensate and natural gas liquids

The most interesting observation regarding the above graph is that Venezuela has surpassed Saudi Arabia in total proved reserves.  When most people talk about oil powers, Venezuela isn’t going to be the first country that rolls off their tongue, and for good reason as company’s have to deal with the potential of nationalization to operate in the country.  This fact is highlighted by relatively low production numbers for the country despite its robust reserves.  The country has a lot of potential, but it’s potential that is difficult to realize and no company knows this better than Harvest Natural Resources (NYSE: HNR) who recently pulled out of Venezuela.

Canada’s oil sands keep it towards the top of the list, while the United States barely edges out Kazakhstan (who had proved reserves of 30 billion barrels of oil) to hold up the rear of the list.  Continental Resources (NYSE: CLR) believes North Dakota’s Bakken Shale alone holds proved reserves of 20 billion barrels of recoverable oil, but organizations such as the USGS are still grappling with shale play reserve estimates.  Either way, looking at the disparity of reserves on this list makes one realize the need for Western Countries to develop alternative energy or they will eventually be importing a lot of oil (and gas) from the developing world.

Natural Gas: Proved Reserves and Production Levels by Country in 2011


Source: BP Statistical Review of World Energy June 2012

Note: Production excludes flared gas

I know I’ve heard several times that the United States is the Saudi Arabia of natural gas, but this graph shows that’s not entirely true.  With the exception of Russia, the U.S dominates from a production standpoint; but it’s reserve levels aren’t even half as high as Turkmenistan’s who is fourth on the list.  I would expect global natural gas prices, which are still much higher than U.S. prices, to moderate once infrastructure is established in the developing world.

Where is Reserve Growth Growing (2001 to 2011)?


Source: BP Statistical Review of World Energy June 2012

Where’s global oil reserve growth coming from? The developing world.  This shouldn’t be a huge surprise, as Western countries had a head start exploring for and developing its hydrocarbons during the past century.  The graph below, depicting countries whose oil reserve growth has slowed, has four Western countries (Norway, U.S., Canada, Australia).  The U.S. and Canada are really the only two Western countries with significant hydrocarbon reserves.

Where is Reserve Growth Slowing?


Source: BP Statistical Review of World Energy June 2012

(Old Story) Crescent Point Acquires Viking Producer for $425 Million

On May 3, 12012 Crescent Point Energy (TSX: CPG), whose assets are primarily in the Saskatchewan Bakken and Shaunavon resource play, purchased Cutpick Energy (private) for $425 million.  I know this transaction is a bit dated, as I don’t keep up with M&A North of the border like I should.  Cutpick’s assets are primarily in the Viking oil play (Provost–Alberta side), so this gives us a good comparable and opportunity to introduce the play.


Production: CPG purchased 5,600 BOEPD (65% oil) at an implied valuation of $75,893 per flowing barrel

Reserve:  CPG purchased $12.2 MMBOE at an implied valuation of $34.84 per BOE.

If we compare these valuations to the trading multiples I posted yesterday for companies operating in various U.S. basins (see below), you see that CPG valued the Viking more than U.S. investors are valuing the DJ or Permian Basins on a reserve basis, but less for production.  It’s worth noting that CPG operates on the U.S. side of the border in the Williston Basin, so it’s probably familiar with U.S. plays and valuations.  Reading between the lines here, I would assume Cutpick’s production is older, conventional production so it was valued less by CPG.  Additionally, CPG mentions in the acquisition press release that it believes the purchased assets have “waterflood upside,” meaning the company plans to recomplete existing wells (probably conventional production) by flooding them with water to break-up rock and repressurise the well.

CPG stated in the acquisition press release that it plans to develop these assets through the aforementioned waterflooding, in addition to horizontal infill drilling and fracking.  Pro-forma to the acquisition, the Viking will be CPG’s third largest asset, behind the Saskatchewan Bakken and Shaunavon resource play.

About the Viking Play

The Viking oil play of Eastern Alberta and Western Saskatchewan (see map below) was discovered in the 1950s and has been developed using conventional methods (vertical drilling) until recently with the advent of unconventional drilling techniques.  In the U.S., this play could be likened to the DJ and Permian Basins in the sense that it’s an old producing play that is now being revisited using unconventional drilling methods.  In 2011, The National Energy Board (of Cananda) estimated the play contained 2P reserves (proved + probable) of 58 MMBOE.

Source: WestFire Energy

The economics of the Viking play are solid due in part to it being a younger, thus shallower formation lying 700 to 725 meters (~2,300 feet) deep.  Viking producer Baytex Energy Corp. (NYSE: BTE) estimates Viking-Alberta well cost at C$2.0 million per well and Viking-Saskatchewan at C$1.1 million per well.  Economics of the plays appear to be similar in both regions, as the company estimates EURs of 100 MBOE and 50 MBOE for Viking-Alberta and Viking-Saskatchewan, respectively.  The Viking is certainly not a sexy play with eye-popping EURs, but it makes money so it’s worth paying attention to.

Viking Strat Map

How is the Market Valuing Different Oil and Gas Plays?

When I analyze stocks I look for two things: an industry that I believe will thrive over the long-term and value.  I don’t have models to predict the future prices of oil and natural gas, and even if I did, I doubt they would be very accurate; however, I do believe in the long-term viability of the industry or I wouldn’t have bothered starting this blog nearly three months ago.  When looking for value in oil and gas stocks, I first look at how investors are valuing each play.  The easiest way to do this is to look at reserve and production multiples.

The trouble with valuing an individual play is that there aren’t a lot of “pure-play” companies in the oil & gas industry.   Most companies have operations in various plays across the U.S. and abroad, so their reserves and production valuations have several different plays factored in.  Companies like Kodiak (KOG) in the Bakken and Concho (CXO) in the Permian are great examples of pure-plays that make analysis easy.  A play like the Eagle Ford is more difficult to value, not only because it’s so new, but because it has attracted companies from all over the globe, most of which had existing production and were looking for oil and liquids rich assets.

At first glance, Sanchez Energy (SN) is the perfect Eagle Ford comparable.  It’s an Eagle Ford pure-play, but it’s an early stage company that the market is expecting significant reserve and production growth from over the next several years.  Because of these expectations, its multiples are high which throws off my Eagle Ford valuation.  I did consider throwing SN out of the analysis, but I had a tough time justifying this because their core acreage is in Gonzales County where two Bakken companies, EOG Resources (EOG) and Magnum Hunter (MHR), have been drilling gushers and I want to get a sense for the valuation of that acreage.

While SN may bloat my Eagle Ford valuations some, keep in mind that Marathon (MRO) spent $3.5 billion purchasing 141k net acres (~25k/acre) from Hilcorp a little over a year ago.  By year-end 2011, the acreage was expected to have 46 wells on it producing 12,000 net BOEPD (80% oil and liquids) giving us a valuation of $291,667 per flowing BOEPD, 22% less than the $355,234 per flowing I calculated based on my peer group.

See valuations by basin/play below to get sense for how the market is valuing each play:

The first point to make here is the “well duh” observation: the gassier the basin, the lower the valuation.  It should be no surprise that the North Dakota Bakken is receiving the industry’s best reserve valuations, because the play is in more advanced stages (thus less risky) than the Eagle Ford, DJ and Permian, and more oily than the Marcellus.  While the Eagle Ford is more gassy than the Bakken, it’s downspacing potential has led EOG to nearly double its reserve estimates.  In addition, the play has several resource windows and the potential for stacked pay zones which is undoubtedly driving up valuations.  The DJ and Permian Basins also have stacked pay zones, which has led to a revival of both Basins in recent years.

Companies are now going back into these Basins using updated completion techniques (horizontal drilling, fracking, etc) to exploit the previously unrecoverable resources.  Large cap E&Ps Noble Energy (NBL) and Anadarko (APC) aren’t spending billions in the Niobrara over the next several years for no reason.  With valuations in the Bakken and Eagle Ford extremely high, I think it’s worth looking at these other plays for value.  Below are the peer groups I used in my valuations by play above.

1: SYRG reserves based on 8/31/2011 year-end

The companies used in the analysis above are either pure-plays in a specific basin/play or have current operations focused in a certain play.  Aside from SN, KOG is another company whose valuations are outliers.  KOG is an early stage company that has several years on SN.  KOG’s production has done what SN’s investors are hoping its production will do: explode.  And when I say explode, I mean increase nearly 5-fold from May 31, 2011 to May 31, 2012.

SM is an established operator, producing in a premier shale play, but with a low production valuation.  Why might this be?  Its reserve life (reserves divided by annual production) is only 5.5 years versus the peer group average of 17.39.  The market isn’t buying that SM will be able to replace its reserves quickly enough to maintain production.  The company is in the process of shifting assets from the Cotton Valley and Wyoming gas Basins to invest nearly a billion dollars in 2012 drilling in the Eagle Ford and Bakken-Three Forks.   The company has over 200k net acres in each of these plays, so if you believe in the acreage, the present could represent an opportunity to buy SM on the cheap.

Based on pure value, we should all be buying Marcellus companies right?  EQT’s stock price has increased 20% from its lows this spring when natural gas prices dropped below $2 per Mcf.  EQT has the largest reserve base in this analysis, located in one of the most economic plays on the planet.  The economics of the Marcellus are so good that the company boasts 25% IRRs at $3.00 gas and 50% at $4.00 gas.  On an energy equivalent basis, those numbers blow the Bakken out of the water.