Monthly Archives: June 2012

Natural Gas Vehicle Primer

At market close on June 19, 2012 oil sold at the Cushing, Texas hub (WTI) fetched a price of $83.99 per barrel, whereas natural gas sold at $2.59 per Mcf at Henry Hub in Erath, Louisiana.  On an energy equivalent basis, Six Mcf produces approximately the same amount of energy as one barrel of oil; therefore, all things equal (particularly with respect to supply in demand) we should expect $2.59 * 6 or $15.54 to equal the price of one barrel of oil.  Instead, we find that one barrel of oil prices at a 5.4x premium to six mcf of natural gas.  The premium paid for oil is caused by increased demand for the hydrocarbon from the developing world (China, India, etc) and its diminishing supply.  Consequentially, natural gas has become an attractive energy source, not only for its pricing advantage to oil but also because it burns cleaner:

Average Emission Rates in the United States

Natural Gas Emissions

Carbon Dioxide: 1,135 lbs/MWh

Sulfur Dioxide: 0.1 lbs/MWh

Nitrogen Oxide: 1.7 lbs/MWh

Oil Emissions

Carbon Dioxide: 1,672 lbs/MWh

Sulfur Dioxide: 12.0 lbs/MWh

Nitrogen Oxide: 4.0 lbs/MWh

Source: www.epa.gov

Note regarding natural gas vehicle emissions: According to the DOE, transit buses with natural gas engines produced 49% lower nitrogen oxide emissions and 84% lower particulate matter emissions.

Are we taking advantage of cheap natural gas prices? Aside from coal-to-natural gas switching by U.S. utilities, companies have been building natural gas fueling stations for cars and trucks and converting gasoline engines to natural gas engines.  Chesapeak Energy sponsored Clean Energy Fuels (NASDAQ: CLNE), a company who has T. Boone Pickens on its board, is currently working on a “natural gas highway” across the United States (see below).  The company sells compressed natural gas (CNG) to passenger vehicles and fleets and liquefied natural gas (LNG) to the trucking industry.  Per gallon prices (diesel gallon equivalent) for CNG and LNG at CLNE fueling stations averaged $2.28 and $2.88, respectively, during the week of June 18, 2012.

CLNE’s LNG Highway

Source: http://www.cleanenergyfuels.com

For information regarding CNG fueling stations in the U.S., click here.

Companies like CLNE, Westport Innovations (NASDAQ: WPRT / TSX: WPT) and World CNG (private) are currently focused on building infrastructure for natural gas vehicles (NGVs) and either converting cars/trucks to CNG/LNG or building new NGVs.  Their clients are primarily trucking companies and or vehicle fleets such as airport shuttles, delivery trucks, garbage trucks and taxis.  Given the relatively limited number of natural gas fueling stations, this makes sense because its easier for trucks and shuttles who have defined routes to operate on fueling schedules, versus passenger cars whose destinations change sporadically.  I would expect that as the infrastructure for fueling stations continues to be built out, it will make more sense for greater numbers of passenger vehicles to convert to natural gas.

CLNE has built more than 150 fueling stations and has capacity to fuel more than 25,000 vehicles per day.  Westport Innovations  and UPS have partnered to build more than 1,100 natural gas trucks for the UPS (NYSE: UPS) fleet.  WPRT is also working on development plans with General Motors (NYSE: GM / TSX: GMM) to develop new natural gas engine technologies and Caterpillar (NYSE: CAT) to co-develop engines for off-road equipment.  World CNG plans to have well over 200 natural gas taxis in Chicago by the second quarter of 2012.

The United States has a lot of natural gas, it’s cleaner than oil and it will help our country get off of foreign oil.  Even Obama is on the NGV train, proposing a tax-credit to encourage car owners to convert their vehicles from gasoline to natural gas (WPRT, World One and CLNE’s BAF Technologies all do after-market natural gas engine conversions).  Visit the DOE for information on converting your vehicle to natural gas or any other alternative fuel.

Cabot Sells an Interest in its Pearsall Shale Acreage for $14,286 per Acre

On June 22, 2012 Cabot Oil and Gas (NYSE: COG) announced it has reached a joint venture agreement with Osaka Gas Co.  (OTC: OSGSF) for the sale of a 35% non-operated working interest in 50,000 net acres (17,500 net to Osaka) for $250 million.  Osaka will pay the company $125 million in cash up front and carry it on 85% of its Pearsall Shale drilling costs up to an additional $125 million.  The acreage is prospective for all zones below the Buda Formation (see stratigraphic map below) and lies in Atascosa, Frio, LaSalle and Zavala Counties.  In COG’s presentation regarding the acreage, the company estimated production from its Pearsall acreage will contain approximately 37.5% natural gas, 27.5% condensate and 32.5% natural gas liquids (NGLs).

Pearsall Shale Strat Map

Source: Cabot Oil and Gas Pearsall Presentation

Add Osaka to the list of a growing number of East Asia companies that are buying into U.S. shale plays: 

1) Mitsui & Co. purchased 39,000 net acres in the Eagle Ford Shale in June of last year from SM Energy (NYSE: SM) for $735 million (purchase price includes midpoint of reimbursement cost estimate) or $18,846 per acre.

2) Marubeni purchased 18,200 net acres in the Eagle Ford Shale in January of this year from Hunt Oil (private) (acreage cost was not broken out in the press release).

3) Korean National Oil Corporation (KNOC) purchased 80,000 net acres in the Eagle Ford (also prospective for Pearsall Shale) and 16,000 net acres prospective for the Pearsall Shale (96,000 total) in March, 2011 from Anadarko Petroleum (NYSE: APC) for $1.60 billion (price includes 50 million reimbursement costs) or $16,667 per acre.

4) China National Offshore Oil Corporation (CNOOC) purchased 198,000 net acres in the Eagle Ford in October, 2010 from Chesapeak Energy (NYSE: CHK) for $2.16 billion or $10,909 per acre.  This acreage is primarily located in Webb, Dimmit, LaSalle, Zavala, Frio and McMullen Counties.

Other Notable Eagle Ford Transactions

1) In June, 2011, Marathon Oil Corporation (NYSE: MRO) purchased 141,000 net acres in the Eagle Ford (primarily in Atascosa, Karnes, Gonzales and DeWitt Counties) for $3.5 billion or $24,823 per acre.  Note: This transaction included 36 gross wells producing 17,000 gross barrels of oil per day BOEPD as of May 1, 2011 which enhanced the value of the acreage.

Cabot-Osaka Pearsall JV (JV acreage in yellow)

Source: Cabot Oil and Gas Pearsall Presentation

For Cabot this deal not only provides the company with liquidity to drill its oil and liquids rich Eagle Ford and Pearsall Shale wells but also gives the company an encouraging valuation of $14,286 per acre for its Pearsall Shale acreage.  The valuation is not only competitive with recent Eagle Ford transactions, but potentially doubles the acreage value of companies who own Eagle Ford acreage that is also prospective for the Pearsall (I would assume most companies who own Eagle Ford acreage own the Pearsall zone as well; however note that the Pearsall might not exist or might not be productive throughout all areas of the Eagle Ford).  COG’s stock price is up roughly 6% from its close on Thursday (deal was announced Friday), despite general market turmoil overall.

Natural Gas Liquids Primer

So you own a company whose production is weighted towards natural gas.  Because gas prices are low, the company has been talking about shifting  its production cut to “wet” gas or natural gas liquids (NGLs).  The natural questions you should be asking yourself are:

1) What is “wet” gas?

2) What is it used in?

3) How is it priced relative to natural gas/methane?

Answers:

1) When companies refer to natural gas liquids or NGLs, they are speaking of some sort of a mix of the following gases: ethane, propane, butane, iosbutane, and natural gasoline (note that natural gasoline is a different compound from natural gas).  The gases are called “wet” because in high pressure environments (ie: underground) they are in a liquid state.  The blend of gases extracted will vary from reservoir to reservoir, rock formation to rock formation, etc.  For instance, the production cut from a company such as Range Resources (NYSE: RRC) operating in the Marcellus Shale in Southwestern Pennsylvania may or may not contain more ethane than a company operating in the Granite Wash such as Panhandle Oil and Gas (NYSE: PHX).

When NGLs are extracted from the ground, they are in a gaseous form, most likely containing a component of methane as well.  At this point, the gas can be sold to market as a gas and the company will receive a price equivalent to its MMBtu content.  If the liquids component of the gas is high enough, or the frac spread is positive, it will be profitable for the different gas components to be separated or “fractionated” from each other and sold separately at market.  Frac spread (aka NGL margin) may be a term you’ve heard before and it’s equivalent to the price a marketer can receive for its liquids after the fractionation  process less the price received if the gas is sold as one component (prior to fractionation).

2) Ethane is used to create ethylene which is used in the production of plastics and as a petro-chemcial feedstock which basically means its a component of various petroleum based substances; propane we know as a fuel source for stoves, engines and other products; butane is used in gas lighters and as a component of synthetic tires; iso-butane is a refrigerant used in air conditioners; natural gasoline is used in the production of ethanol.

3) NGLs in the United States are processed, stored and sold at one of two main hubs: Mont Belvieu which is a hub in Texas, East of Houston and at the Conway hub in Kansas.  NGLs are typically priced in $/gallon, so if we want to find out how their price compares to that of a barrel of oil we simply multiply by 42 (there are approximately 42 gallons in a barrel of oil).

The graph below shows propane spot prices at Mt. Belvieu during the past year

Source: www.eia.gov

According to the Oil Price Information Service (OPIS), the average futures price for ethane, propane, isobutane, normal butane and natural gasoline for the month of July are $0.36,  $0.80, $1.46, $1.38, $1.80, respectively.  Before we get too ahead of ourselves thinking that natural gasoline is the most important component of NGLs due to its higher average futures price, consider that these components all come out of the ground in different quantities and the theory of supply and demand tells us that, all things equal, if there’s less supply of a product it probably costs more.  Like I noted in paragraph one, gas blends will vary from reservoir to reservoir; however I’ll use an average blend the sell-side energy investment bank Tudor, Pickering, Holt & Co used in a midstream primer it issued in November, 2008.

Typical NGL mix (midpoint of range)

Ethane: 42.5%

Propane: 27.5%

Isobutane: 10%

Normal Butane: 7.5%

Natural Gasoline: 12.5%

This NGL component mix shows us that ethane and propane are (on average) responsible for 70% of the value of NGLs, thus making them the most important component for pricing in the NGL mix.  Based on the Mt. Belvieu spot prices above, the following is an estimate of the expected price received for a barrel of natural gas liquids during the month of July versus the natural gas equivalent.

Commodity prices in July, 2012: NGLs versus Natural Gas

The analysis above shows us why natural gas weighted companies are shifting production towards liquids rich formations.  However, note that while NGLs currently price at a significant premium to natural gas, this premium has shrunk over the past year as propane (see how propane prices have slid in graph above) and ethane prices have decreased over the past year.  This should be expected because as production of NGLs increases, supply increases, and without a corresponding increase in demand, prices will decrease.  So while NGLs can certainly be a boon for “dry” gas weighted companies, they might not be a long-term solution.

Recent News

Oil and Gas News

“The Bazhenov” is a Siberian oil shale play that may be much bigger than the Bakken

Exxon deems Poland’s shale uneconomic, Chevron, ConocoPhillips and Marathon still exploring

Blackbrush OIl & Gas is using a water-less fracking technique in the Eagle Ford

Chesapeake agrees to release certain New York mineral owners from leases

Anadarko is constructing a natural gas liquids processing plant in the Eagle Ford; plans to ramp up production in the play this year

ZaZa Energy is looking for a JV partner in the Eagle Ford

New York Governor Andrew Cuomo proposes to limit fracking to several counties along the Pennsylvania border

Alternative Energy News

Vestas sells factory to Chinese company Titan Wind Energy

EPA allows gasoline containing 15% ethanol

Massachusetts businesses are taking advantage of solar subsidies

Purdue University believes it has created a biofuels production technique that can compete with $100 oil

Benefits of biofuels overblown?

Eagle Ford Oil & Gas Expands Portfolio through Purchase of Acreage in Frio County

On June 11, 2012 Eagle Ford Oil & Gas Corp. (OTC: ECCE) announced the purchase of 3,131 net acres in the Eagle Ford Shale for $6.26 million from an undisclosed seller.  The assets, located in Frio County which is in the Eagle Ford’s oil window (see map in Eagle Ford IP rates post for reference), were purchased for $1,999 per acre.  Cabot Oil and Gas (NYSE: COG) announced in its March, 2012 investor presentation that it recently completed three wells in the Southeastern portion of Frio County which had average initial production rates of 1,128, 830 and 1,060 barrels of oil equivalent per day (BOEPD).

ECCE is a non-operator with its core assets in the Eagle Ford Shale.  The company’s Eagle Ford assets, excluding those referenced in the paragraph above, consist of 930 net acres in Lee County (oil window) and a 1% working interest in 2,400 gross acres in Live Oak County (condensate/gas window).  The company also owns assets on the Louisiana Gulf Coast which it purchased from GFX Energy (private) in August, 2011.

The Lee County assets were purchased through ECCE’s acquisition of Sandstone Energy (private) in June, 2011 and includes several producing wells.  Production from these wells is experiencing significant declines and the operator is currently evaluating the results to see if it will continue to develop the acreage.  As noted in my Eagle Ford IP rate write-up, Clayton Williams (NASDAQ: CWEI) experienced similar declines in its Burleson County wells.  Both Lee and Burleson Counties are located in the Northeastern portion of the Eagle Ford play, which to this point doesn’t look economic.

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What am I taking away from this? We have an acreage comp in Frio County from which to compare future transactions and an Eagle Ford penny stock to keep an eye on.  Also, downgrade the acreage of any company who has Eagle Ford assets North of Gonzales County.  Magnum Hunter (NYSE: MHR) and EOG Resources (NYSE: EOG) have both had terrific results in Gonzales, so it I’m curious about Fayette County which is sandwiched in between Gonzales and Lee Counties.  I know MHR has acreage in Fayette and Lee Counties, so it will be interesting to see what happens with that acreage.

IP Rates in the Eagle Ford Shale (2011-2012)

The Eagle Ford Shale of South Texas is an emerging shale play with three resource windows (see map below).  An oil window on the Northern part of the play, a liquids window in the middle of the play and a gas window to the South of the play.  The formation is sandwiched in between the Austin Chalk and Buda Limestone (see strat map below), both of which represent additional upside to the Eagle Ford Shale play.  The Texas Railroad Commission credits Petrohawk, purchased by a mining company entering the E&P space in BHP Billiton (NYSE: BHP) in July, 2011, for discovering the well that galvanized interest in the Eagle Ford in 2008.  From 2004 to March, 2012, the formation produced approximately 92 MMBOE, disaggregated as follows: 59 million barrels of oil (64% of total), 480 million cubic feet of natural gas (0% of total) and 33 million barrels of condensate/liquids (36% of total).

Eagle Ford Shale Map

As you can see by the above map, most of the production in the Eagle Ford has come from the oil and condensate windows.  This makes sense as 90% of the production in the formation has come within the last three years, a time period where oil and liquids have been much more economic to extract than gas due to low gas prices.

Delineation (delineation wells are drilled to determine hydrocarbon characteristics of a formation)  in the Eagle Ford has been limited North of Gonzalez County.  Clayton Williams (NASDAQ: CWEI) drilled several wells in Burleson County (NE corner of Eagle Ford) during 2010.  The first well was Broesche Unit #1 which was drilled to a vertical depth of 7,580 feet with a 4,880 foot lateral (9 stage frack) and had an average initial production rate of 234 barrels of oil per day (BOPD); however the well quickly declied to 46 BOPD.  Its second well, Smalley-Robinson Unit #1, was drilled to a vertical depth of 7,020 feet with a 5,500 foot lateral (13 stag frack) and had average initial production of 492 BOPD; however the well quickly declined to 175 BOPD.  The steep declines of these wells indicate depressurization in the formation, which is likely the reason  the oily NE Eagle Ford hasn’t seen more development.

Eagle Ford Stratigraphic Map:

Recent 24-hour average initial production (IP) rates in the Eagle Ford are as follows:

As you can see from the scatter plot above, IP rates vary considerably in the Eagle Ford.  The lowest IP rate on the plot is 293 BOEPD which was drilled by Comstock Resources (NYSE: CRK), the highest IP rate of 3,792 which was drilled by EOG Resources (NYSE: EOG) and the average IP is 1,274.  It should be noted that the companies included in my Eagle Ford IP rate analysis were those who disclosed their well results by county.  I wanted to look at the Eagle Ford by county to get a sense of where activity is being concentrated and where the best well results are coming from.

2011 and 2012 Eagle Ford IP Rates by County

Operators:  Comstock Resources (NYSE: CRK), Cabot Oil & Gas (NYSE: COG)

Eagle Ford Window: Oil

Operators: Crimson Exploration (NASDAQ: CXPO), Chesapeake Energy (NYSE: CHK)

Eagle Ford Window: Oil/condensate

Oil/liquids Production Cut: >90%

Operator: Cabot Oil & Gas (NYSE: COG)

Eagle Ford Window: Oil

Operator: EOG Resources (NYSE: EOG)

Eagle Ford Window: Oil

Oil/liquids Production Cut: 89%

Operators: EOG Resources (NYSE: EOG), Crimson Exploration (NASDAQ: CXPO), Comstock Resources (NYSE: CRK)

Window: Condensate

Oil/liquids Production Cut: >90%

Operator: Comstock Resources (NYSE: CRK)

Window: Oil/Condensate

Operators: Penn Virginia (NYSE: PVA), Magnum Hunter Resources (NYSE: MHR)

Window: Oil/Condensate/Gas

Oil/liquids Production Cut: 90%

Additional Notes:

1) PVA provided longer average IP rates, which gives us a better idea of the overall performance of the well.

2) PVA’s Schacherl #1H was drilled with a 5,450 foot lateral (22-stage frack) and a restricted 14/64″ choke.

Note regarding chokes: Chokes are used to regulate the flow of hydrocarbons through the well-bore.  A company may use a restricted choke to protect against depressurization of the reservoir it’s drilling into.  All things equal, the more restricted the choke, the less initial flow-back that will be received from the well.

3) MHR’s Leopard Hunter #1H was drilled to a vertical depth of 10,228 feet with a 6,708 foot lateral (25-stage frack) and 18/64″ choke.

Operators: EOG Resources (NYSE: EOG), Comstock Resources (NYSE: CRK), Abraxas Petroleum (NASDAQ: AXAS) ,Chesapeake Energy (NYSE: CHK)

Window: Oil/Condensate/Gas

Oil/liquids Production Cut: >90%

Additional Notes:

1) PVA’s Hill #1H was drilled to a vertical depth of 11,264 feet with a 4,642 foot lateral

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The above results indicate that both EOG’s and MHR’s wells have had consistent completions with IPs towards the top of the companies in the analysis.  Frio, Gonzales, Lavaca and McMullen Counties were the strongest performers on a county basis, with LaSalle’s results looking weak with respect to the group.  However, I would caution that these rates are (with the exception of PVA’s) 24-hour IP rates, so decline of well performance is largely absent from the analysis.  As I noted above, CWEI’s Burleson County wells had steep declines which rendered them uneconomic.  CRK’s results might not have knocked you out of the park like EOG’s, but if you view their current corporate presentation, the declines from the 24-hour IP in their wells are very modest over a 3-month period.  Some of the company’s wells have even shown improvement from 30-day to 90-day average rates.

Unfortunately, not all companies disclose detailed production data and the production some do disclose is limited, so it’s often difficult to draw meaningful conclusions from well performance.  What we can do is track which companies are drilling and where, and based on the volume of wells they drill in a certain area and production data they do disclose, determine how confident companies feel about their acreage.

Unconventional Drilling is Increasing the Oil and Gas Industry’s Demand for Water

Unconventional drilling (ie: horizontal drilling and fracking) aims to extract hydrocarbons from rock formations that were not economic to extract using conventional methods (ie: vertical drilling).  Extraction is uneconomic because the hydrocarbons lie in tight rock formations, such as shale, which has low permeability and porosity.  In order to extract hydrocarbons from tight formations, high volumes of water and sand are pumped into wells to “frack” or break-apart the tight rock formations, allowing the hydrocarbons to move freely through the wellbore to the surface.  Because this process is expensive relative to conventional or vertical drilling, high oil prices are needed to make the process economic for companies.  Crude oil prices have risen considerably over the past decade, which has increased the use of unconventional drilling techniques; however it has created concern for not only the cleanliness of our water (see my fracking piece), but the quantity as well.

Water Usage by Energy Source

Source: Estimated Use of Water in the U.S. 2005 USGS (updated every five years)

While the above graph shows mining and oil & gas only represent 1% of total water usage in the U.S., it’s undoubtedly higher today as fracking was in its infancy when this data was last updated.  Additionally, we are beginning to reach a tipping point with water which has forced oil & gas companies to compete with the farming industry over water rights.  Last December, the Wall Street Journal ran a story on “Oil’s Growing Thirst for Water.”  In the story, Texas cattle rancher Darren Brownlow who has a PHD in geochemistry, said he recently leased his cattle ranch for oil exploration using the following rationale: we can use 407 million gallons of water to irrigate and grow $200,000 of corn on 640-acres or use a similar amount of water to drill unconventional oil & gas wells which will produce $2.5 billion worth of oil & gas.

Because oil and gas companies are much more profitable than farms, they are outbidding farms for water rights in Texas (see map below), and future conflicts between the two industries can be expected.  How can this be bad for the oil & gas industry? We are running out of available water to quench the thirst of oil companies.  If big oil continues to bump up against other industries who politicians deem vital to local and/or national economies, we could see regulations limiting the oil industry’s ability to use water.

Source: Bureau of Economic Geology, University of Texas

According to the International Energy Agency (IEA), fracking an individual well can consume anywhere between several thousand and twenty thousand cubic meters of water (this equates to a range of one to five million gallons of water).  To complicate matters, this water can’t simply be reused, leaving companies with millions of gallons of toxic water to dispose.  The traditional method for water disposal has been to drill disposal wells and inject the water back into the ground.  The industry’s shift from primarily conventional to unconventional extraction techniques has created several problems for this method:

1) As shown by the graph below, the industry has a lot more water to dispose of than previously.

2) Not only do disposal wells cost several million dollars to drill, the water must be transported to them from each well by truck which adds another cost on the company.

3) Disposal wells have been linked to earthquakes in several states, which has the potential to be another PR issue for the already controversial topic of unconventional drilling.

Water Usage by Well Type

Source: Lifecycle Analysis of Water Use and Intensity of Noble Energy Oil and Gas Recovery in the Wattenberg Field of Northern Colorado.

So how is the industry responding to the water usage issue? Some companies are using water recycling companies to recycle and/or reuse their waste water.  Fountain Quail Water Management, a subsidiary of Aqua-Pure Ventures (TSX: AQE), uses its mobile NOMAD water recycling center to travel to oil and gas fields where it uses an evaporation technique to separate water from the toxic chemicals.  Devon Energy (NYSE: DVN) is building a water recycling facility to service its wells in the Anadarko Basin of Western Oklahoma.  Sabre Energy Services (private) is using chlorine dioxide to treat frack water for reuse.

In Colorado, Noble Energy (NYSE: NBL) has formed a consortium with Colorado State University (CSU) to study the impact of shale drilling on the environment.  The consortium recently studied the life cycle of water in Colorado and found, among other things, that while unconventional recovery uses a lot of water, it’s an efficient process relative to other resource extraction techniques on a water intensity basis (gallons of water used/MMBtu of energy extracted):

Source: Lifecycle Analysis of Water Use and Intensity of Noble Energy Oil and Gas Recovery in the Wattenberg Field of Northern Colorado.

The key takeaway from this article is that, while relatively efficient, the fracking process uses a lot more water than conventional drilling methods.  Consequentially, companies are going to have to change the way they dispose of waste water.  If your stock portfolio consists of companies who operate in dry areas such as Texas or Colorado, pay attention to how your portfolio companies are handling the water issue.  You should question the aptitude of a company’s management if they aren’t at least discussing more economic and environmentally sustainable methods of waste water disposal.