Monthly Archives: November 2012

First-Year Declines in the Eagle Ford

Several people who follow this blog have asked me about Eagle Ford declines, and for good reason, as declines help determine the amount of oil the average well will recover.  Companies rarely provide this data and investors typically only get granular information from small independent E&Ps (Comstock Resources (CRK) gives great decline information in its presentations).  One of the purposes of this blog is to “fill in the gaps” for investors so that when they read that the 30-day rate on an Eagle Ford well in Lavaca County was 700 BOEPD, they know just how good that result is and how it will perform in the future.

With that said, the Eagle Ford is still a new play, so there’s not a large sample size of data to look at because there’s not many wells that have produced more than a year and much fewer that have produced more than two years.  Luckily, there are some, and I’ve provided data on 70 of those wells below for you to view.  I believe the data I have gives you a macro view of how the Eagle Ford is declining during the first year, but I would hesitate to draw many conclusions from any of the counties (excluding Karnes) because there’s not enough wells from each county that have been drilled by multiple operators.

Methodology Disclaimer
1) The Texas Railroad Commission (TRC) only provides monthly production data and doesn’t state how many days a well (it technically only provides production by lease for oil wells, but production by well can be inferred on most leases) produced  during a month.  I assumed each well produced 30 days per month and 360 days per year.  The reality is, I don’t have any way of knowing how many days these wells produced, but know that most probably produced somewhere between 300 and 360.  For this reason, the 30-day and 360-day production rates are understated in many cases.
2) The percent declines for oil and natural gas show how the 360-day rate declines compared to the 30-day rate declines, so it’s not a true annual decline rate but it’s probably pretty close.
3) The TRC reports production as oil or gas and at this point I’m not positive which bucket it’s lumping natural gas liquids into (if any), which is a significant component in many of these counties.

Eagle Ford Declines
(click to enlarge)

Based on the above data, a well drilled into the oil/condensate window of the Eagle Ford will have an average 30-day production rate of 544 barrels of oil per day (BOPD) and 681 thousand cubic feet of natural gas today (Mcfpd) or 658 barrels of oil equivalent per day (BOEPD) (83% oil).  The average 360-day rate was 269 BOPD and 381 Mcfpd or 333 BOEPD (81% oil).  Again, I’m not really sure how liquids factors into this and I don’t want to make any assumptions until I find out from the TRC.

Karnes County: ConocoPhillips (COP), Marathon, (MRO) and Murphy (MUR) all have strong 360 day rates in Karnes, with EOG (EOG) surprisingly having steeper declines.  I will caution to say that EOG has drilled a lot of wells on some of its leases and I was only able to gather data for them from the leases which had one well on it for the most part.  Point being, I may have missed some of their better wells.  Either way, Karnes County is looking very strong.

Other than Karnes, I didn’t want to draw too many conclusions from this data.  The wells I have 360-day data for are the early wells these companies drilled, so one would expect completions to get better in some of the counties with fewer results.  This post is meant to be a data piece for you guys and one that should give you some color on some of the results you’re hearing about.

While I don’t want you to read too much into the results by county, I prepared a table below detailing just that.  It should give you somewhat of a compass for when you hear about results moving forward.  De Witt and Lavaca were excluded from this table due to lack of data.

Eagle Ford Results by County

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Value Stock Search in the Eagle Ford

Comstock Resources (CRK), Goodrich Petroleum (GDP) and Penn Virginia (PVA) are three former Haynesville/Cotton Valley operators who’ve been buying up acreage in the Eagle Ford to compensate for low natural gas prices.  All three of these companies have market caps below one billion and have the potential to be a small/micro-cap growth story for your portfolio.  These companies also have debt-to-market caps North of 150% and are trading well off their 52-week highs, meaning they hold potential value if they can navigate their debt issues in the wake of low gas prices.  A common strategy among this segment of oil and gas companies has been to roll back their debt maturities to later this decade due to the expectation that natural gas prices will recover.  The graph below shows why these companies have been loathe to finance their respective transitions to oil with equity.

Source: Yahoo Finance.

As of market close November 13, 2012, Comstock was trading at $16.19 per share or 81% lower than when it peaked at $86.70 in July, 2008.  The company rolled the dice in December, 2011, when it spent $332 million or $7,543 per acre on a 44,000 net acre position in the Southern Delaware Basin.  This acquisition certainly made the company oilier by augmenting its 28,000 net acre position in the Eagle Ford (it has subsequently added an additional 13k net in the Delaware); but it also forced the company to issue more debt and CRK more than doubled its debt load to $1.2 billion from $0.5 billion at year-end 2010.  Comstock doesn’t like to issue equity and hasn’t in more than eight years, so the debt issuances show the company is sticking to its guns which is bold given its weight to natural gas (16% of Q3’12 production was natural gas/NGLs).

The company is probably done with any major acquisitions/divestitures and is now in full on execution mode.  To that end, it has been successful with 30-day IP rates in the Eagle Ford averaging 517 BOEPD (80% oil) and declining at a shallow rate over a 90-day period to 448 BOEPD.  Its acreage is primarily in Atascosa, McMullen and La Salle Counties, with McMullen primarily responsible for its results to date.  The Atascosa results aren’t as strong to date but the acreage is good, just not as consistent as McMullen.  The Atascosa block to the East is offset by EOG whose 30-day rates in the area are above 450 BOEPD.

Comstock is still working on its efficiency in the Delaware Basin where well costs have run higher than offset operators.  The company is confident that the costs will come down as it continues to delineate its acreage.  CRK will develop this acreage primarily with vertical wells (company believes 20% is prospective for horizontals) on small spacing units which will give the company more than 900 net well locations.  This will be a good oily cash flow piece for Comstock that should provide consistent results and diversification from the Eagle Ford.  Moving forward, it plans to spend within cash flow for 2013 with nearly all of its capex devoted to the Eagle Ford and the Delaware Basin.

As of market close November 13, 2012, Goodrich was trading at $8.94 per share or 89% lower than when it peaked at $82.92 in June, 2008.  With 38,200 net acres in the Eagle Ford, the company has a larger position than CRK (28,000 net), but the acreage is primarily in Frio and Northern La Salle which hasn’t been developed as much as other areas in the Eagle Ford, thus holds more risk.  The company’s early Frio wells have been mediocre to date, but its Burns Ranch lease in La Salle County has already produced 1.7 million barrels of oil on 22 wells.

While GDP has the lowest grade Eagle Ford acreage of these three companies, its 134,000 net acre asset in the Tuscaloosa Marine Shale (TMS) could be a game changer.  It’s still very early in the TMS, but it’s a good sign for GDP that the big boys are already in the play, with Devon (DVN), Encana (ECA), EOG (EOG) and Sinopec all having substantial acreage positions.  The TMS is deeper than the Eagle Ford which implies higher well costs, so GDP expects to find a JV partner for its acreage to help with financing and take some risk off its plate.  The company hopes to get well costs down to the $10 to $12 million range in the play and the thinking is EURs could be in the 500 to 600 MBOE range.  Goodrich is optimistic that the play will be economic, particularly when LLS pricing is considered.

As of market close November 13, 2012, Penn Virginia was trading at $4.61 per share or 94% lower than when it peaked at $71.63 in July, 2008.  PVA has the best acreage position in the Eagle Ford of the three companies, with 30,000 net acres in Gonzales and Lavaca Counties.  The company has shut-down its East Texas drilling until gas prices recover and will now exclusively develop its Eagle Ford acreage.  The early returns look promising as the company’s 30-day IP rates are averaging 525 BOEPD (85% oil) per well, results that have grown its oil cut to 38% of total production during Q3’12.  PVA believes it will be able to grow its Eagle Ford position in small chunks as it develops its acreage.  For 2013, the company plans to drill 22 wells and 18 wells in Gonzales and Lavaca Counties, respectively.

Financial Metrics

After looking at the stock price graph above, it’s easy to see how all of these companies look over-levered on a debt-to-market cap basis, as each has lost more than 80% of its market cap during the last few years.  If we look at Interest expense per BOE, which may be a more applicable metric to these companies, GDP and PVA still look over-levered as they’re paying $1.58 and $1.47 per Mcfe, respectively, which is high considering realized prices for natural gas.  CRK is paying $0.60 per Mcfe, much lower than the other companies in the peer group and certainly looks like the superior company from a metrics standpoint.

Based on acreage and metrics, I would have expected Comstock to be valued much higher than both GDP and PVA.  It’s my opinion that CRK is clearly the best value of this group and a solid small cap for your portfolio.  The company plans to spend within cash flow for 2013 (generated $226 million during the first nine-months of 2012) and has $200 million available in its revolver to plug any funding gaps.  PVA would be my second choice from this group as its reserves and production are significantly undervalued with respect to GDP despite its ability to generate $190 million in cash flow during the first nine-months of 2012 while GDP only generated $98 million.  Cash flow will be important for all of these companies as they don’t have much room to run debt wise and fear the consequences of an equity sale which would be very dilutive at current stock prices.

If you’re an investor in one of these companies the strategy is clear: transition to oil over the near-term to stabilize the company until natural gas prices recover.  In the meantime, roll back debt to later this decade at which point natural gas prices have (hopefully) recovered which will imply significant market cap growth.  At higher share prices levels, the companies can then issue equity to pay off their debt maturities.  I’ve said CRK is my number one pick from this group and probably the only one I’m buying at current valuations.  The other two have potential, but I think they’re too risky to add until they get production up to a point where their interest is more manageable.

Eagle Ford Production Rates by County

I apologize for not getting more information to you guys on a consistent basis.  By nature, I like to be thorough with everything I post, which leads to fewer posts but better information.  Moving forward, I’ll try to post data points such as the graph below which can be useful to you during times when I’m not writing as much.

Source: Texas Railroad Commission.
*BOPD number includes oil and condensate.

The above graph was prepared using information provided by the Texas Railroad Commission (TRC).  Based on the data I’ve looked at, Lavaca County has been the source of the highest production rates in the Eagle Ford to date.  Note that the sample size for Lavaca isn’t as large as some of the other Counties due to lack of drilling, but I would expect it to be an active County moving forward.  Also note that while Lavaca saw the highest rates, it’s also the deepest of the above counties (see table below) on average with depth to the top of pay at around 11,471′.  This implies that Lavaca is also the most expensive county to drill in.  While Webb is the most prolific Eagle Ford County on a BOE basis, its production is mostly gas and condensate.  The TRC classifies all of Webb’s production as either gas or condensate and at this point I’m assuming any oil produced from Webb is being lumped into condensate (my inquiries to clarify this issue with the TRC haven’t been successful to date).

Below is an Eagle Ford map which you can use to reference county locations.

The Eagle Ford gets oilier towards the North as shown by the red gas wells and green oil wells.  Chesapeake (CHK) drilled a number of wells in Webb County (SW Eagle Ford) between 2008 and 2010 and has since (along with the rest of the industry) focused the majority of its drilling in the formation’s oilier counties.  The best counties in the Eagle Ford appear to be Gonzales, Karnes and Lavaca, which are towards the Northeast of the play (the highlighted counties North of Fayette are an extension area which hasn’t seen much development to date).  I know EOG Resources (EOG) and Halcon Resources (HK) both have acreage in Leon County so results there will be something to pay attention to.

The table below shows depths by County as well as the operators I looked at in each county for this analysis.  The far right column shows the wells by county used in the graph above.

Drilling costs in the Eagle Ford are ranging from $6 to $9 million depending on the operator.  EOG and HK are the lowest cost producers I’ve seen in the play, with most companies spending between $7 and $9 million.  Compared to the Bakken, the wells are less expensive but also contain lower oil content.  The Eagle Ford does have several advantages over the Bakken, including smaller spacing units (EOG is experimenting with 60 to 90 acre spacing) which lead to more well locations (thus a higher recovery factor of oil in place) and close proximity to trading hubs including the St. James terminal in Louisiana where companies are currently receiving a $10+ premium to WTI.

One thing to caution with the Eagle Ford is the best acreage is probably being drilled first, much like the Parshall field in North Dakota’s Bakken.  Either way, its a monster play with a number of counties that are producing very consistent results.

The Well Map (11-01-12 Update)

I’ve been steadily adding well locations to The Well Map, The Energy Harbinger’s current side project.  The map currently has more than 600 well locations, half of which are in the North Dakota Bakken.  Concerning the Rockies, I also have locations in Wyoming and Colorado and will eventually get into Utah and Montana.  I added about 50 Chesapeake Eagle Ford wells today and plan to hit the Eagle Ford hard during the next several weeks.  Eventually this map will allow for filtering by operator, well performance, etc to make it more usable, but for now you’ll have to check each well location individually.

I’ll try to put up some polls regarding companies/basins you would like me to add, but feel free to email me or respond to this post for now.

If you’ve been confused by any of the data in the dialogue box that pops up when you click on a well location, here’s an explanation: The box contains the following information: operator, well name, location, county, spud date, IP Days, BOPD, BNGLPD, Mcfpd and oil cut.  The following is a definition for each category:

Operator: Owns a majority interest in the well and is in charge of drilling, completing and maintaining the well.
Well Name: Pretty self explanatory.
Location:  Tells which Township-Range-Section a well is in.  Texas doesn’t follow the T-R-S format, so for now I’ve been putting the “field name” as designated by the Texas Railroad Commission (TRC).  I may eventually start using Texas’ land survey method, but for now you’re stuck with the field name.
County: Pretty self explanatory.
Spud Date: Date drilling commenced on well.  Regarding Texas: The TRC doesn’t provide spud dates, so I’ve been substituting first month of production for spud date.
IP Days: Initial production days is the amount of days I used to compute the average production rates (BOPD, BNGLPD and Mcfpd).  I am targeting a 30-day rate, but because of limited data provided by the state (they usually provide days a well produced in a given month), these rates fluctuate.  The TRC only provides monthly production, so I assumed each well produced for 30 days during its peak month of production.
BOPD: Barrels of oil per day.  This number is the average number of barrels produced during the IP Days.  So if a well produced 600 BOPD and its IP days was 30, then on average the well produced 600 barrels of oil per day for 30 days.  This number doesn’t necessarily represent the first 30 or so days the well produced oil, but the peak 30-day rate.
BNGLPD: Barrels of natural gas liquids per day.  See BOPD description.
Mcfpd: Thousand cubic feet per day (of natural gas).  See BOPD description.
Oil cut: Percentage of initial production that was oil.
Footnotes: *Certain wells have a * after the well name because the production rates I have computed may not reflect the actual rates of the well.  This instance occurs in states like Texas where companies report production by lease.  When several wells are drilled on a single lease, per well production can be difficult to determine.  In certain cases I omitted the wells from the map, in others I inferred production rates based on the production profile of the lease and well completion dates.  Efforts will be made to improve this data moving forward.