Tag Archives: eagle ford

The Well Map Update (12-3-13)

Testing is finished with The Well Map and we’re going to go live next week. Here’s what you need to know:

*There’s roughly 13k wells on the map and we’ll be adding more each week.
*The 13k wells include areas such as the Bakken, Eagle Ford, Miss Lime, Powder River Basin, DJ Basin, Piceance Basin, Permian Basin, Granite Wash, Marcelllus and Utica.
*We’ll be updating existing data and adding new data all the time. Wells from the San Juan Basin, SCOOP and Marmaton are coming soon.
*For quick analysis of the data we’ve installed several filters including operator, well name, formation, wellbore, spud date, state/county and production ranges.
*Once data is filtered, the filter summary averages the data filtered which allows the user to pull data points such as average production by operator, formation or state quickly.
*The map will be free, all you have to do is sign-up.
*If you want to stay up to date on the new wells we add each week and crunch raw data, we’ll be offering several newsletters containing just that, these start at $50/month.
*To stay up to date on new features and launch information, like us on Facebook and follow us on Twitter.

Thanks for your support,

The Well Map Team

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GeoSouthern’s Production and Proppant Use are Down in the Eagle Ford

GeoSouthern (private) is one of the companies that pioneered the development of the Eagle Ford Shale. Its primary acreage is in De Witt County’s Black Hawk field (see map below) which is an Eagle Ford sweet spot. To date, the company has drilled and completed (D&C) more than 100 wells in the formation which have produced more than 15 million barrels of oil (MMBO) and 98 billion cubic feet of natural gas (Bcf). That’s $1.7 billion worth of hydrocarbons at $90 oil and $4 natural gas.

Note: Petrohawk’s type curve for the Blawk Hawk field has the following hydrocarbon breakdown: 51% oil, 28% natural gas and 21% natural gas liquids (NGLs). The economic analysis in this piece was conducted using data provided by the Texas Railroad Commission which does not break-out NGLs and shows approximately 50% of the production from GeoSouthern’s wells is oil. To be on the conservative side, I didn’t account for NGLs but know they represent upside to the natural gas price.

GeoSouthern’s De Witt County Wells
GeoSouthern_The-Well-MapSource: The Well Map / The Energy Harbinger.

While GeoSouthern has produced a lot of hydrocarbons from De Witt County, the formation is deep with depths ranging from 12k’ to 14k’ and total depths from 16k’ to 20k’ feet meaning some wells are nearly four miles long. Needless to say, they aren’t cheap to drill and the early wells drilled in this field probably cost in the neighborhood of $10 million.

A well that wouldn’t fall into the $10 million category is Geo’s first well drilled in the Eagle Ford, Migura 1. This well was completed on April 22, 2009 with a 2,780′ lateral and frac’d with 626 thousand pounds of proppant, a very small frac compared to the standards the company would employ shortly thereafter. The well has produced roughly 19k BO and 126 MMcf to date, making it far and away the smallest well the company has completed to date.

Geo D&C 64 wells in De Witt County prior to 2012. These wells were (on average) completed with 4,840′ laterals and 4.5 million pounds of proppant, meaning the company didn’t waste much time ramping up its frac cocktails. These wells have produced an average of 182k barrels of oil (BO) and 1.1 billion cubic feet of natural gas (Bcf). If we assume a price deck of $90 oil and $4 natural gas, they’ve grossed an estimated $20.8 million a piece to date.

Post 2012, Geo has D&C 39 wells which haven’t performed as well as the earlier wells. Peak month oil production is down 38% and these wells produced at a rate of 218 BOPD during their first year, 34% less than the 332 BOPD rate the pre-2012 wells produced at.

While It’s possible the company drilled its best areas first, it’s worth noting the post 2012 wells used an average of 3.8 million pounds of proppant, 14% less than the 4.5 million pounds the earlier wells used. Laterals also decreased 8% to an average of 4,433′ per well from 4,840′ per well. While this undoubtedly decreased well costs, the graph below shows proppant use has a significant impact on production.

Oil Production and Proppant Used per Well
geosouthern_proppant-scatter-plot
Source: Texas Railroad Commission / The Energy Harbinger.

The scatterplot above contains completion data from 82 wells D&C by GeoSouthern in De Witt County. The data shows pounds of proppant used in a well can explain approximately 36% of the variation in its production during the first year. Knowing this, it’s reasonable to assume at least some of the company’s decrease in production can be attributed to a change in completion designs.

Admittedly, bigger isn’t always better. Companies should aim to produce the most economic wells and if that can be accomplished by using lower amounts of proppant, then it’s a good move by the company. I would warn that production  from the later wells fell off 34% during year-one, implying costs would have to fall by a similar proportion for the move to make sense. I highly doubt Geo’s well costs have fallen by $3.4 million during that time frame as companies are reporting costs North of $8.0 million in that area.

The Well Map Beta Testers: We apologize for the delay in the beta but we plan on sending out emails with login credentials for the test early next week. We want the beta to be the best experience possible so we decided to postpone testing until the site was running to our expectations.

-The Well Map Team.

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.

Seeing the Forest through the Debt

Forest Oil (FST) hails from the lineage of noble companies who attempted to increase shareholder value by using financial leverage to increase natural gas reserves during the bull gas market that was 2005 to 2008.  Unfortunately for this lineage, the prolonged period of low natural gas prices that ensued has companies like itself, along with Chesapeake Energy (CHK), Quicksilver Resources (KWK) and GMX Resources (GMXR), et al selling off assets to finance debt like they’re Nicholas Cage.  As an analyst and investor, these are the stories I find exciting because of their potential as a value stock.  I’m not looking for the best run company with the best assets, I’m looking for the best run company with the best assets at the best price.  With that said, screw a sexy company like EOG Resources (EOG), let’s delve into the world that is *cough* Forest Oil.

My research for this piece began with FST’s third quarter 2012 earnings call, which was held on Tuesday October 30, 2012.  I don’t think I’ve listened to a more melancholy earnings call during my admittedly brief analyst career.  Debt aside, at least on paper, I think there’s a lot to be excited about with this story.  The company has 40k net of solid Eagle Ford acreage, 109k net in the Texas Panhandle where it has drilled eight monster Hogshooter wells and an East Texas gas asset that provides its portfolio with plenty of natural gas upside.  I do understand Forest’s attitude, a debt-to-market cap of nearly 200% will keep even the most optimistic financial teams up at night.  So, what are they doing to manage their debt levels?

If you aren’t familiar with Forest’s debt levels, it had total debt of $2.1 billion as of September 30, 2012.  The company is taking a common sense approach to lowering its debt, the first step of which was to refinance half of the six-hundred million it owes in 2014 by issuing lower rate notes which will mature in 2020.  This frees up some near-term liquidity for FST, whose next principal payment isn’t due until 2019 (the company is on the hook for $1.5 billion during 2019 and 2020).  FST will also net approximately $270 million from non-core asset sales which it expects to close on in November and use to lower its debt.  After the refinancing and asset sales, the company will have approximately $1.8 billion in debt outstanding which translates to a debt-to-market cap of 190%.

The remaining $300 million the company will pay in principal in 2014 should be covered through the divestiture of its 114,500 net acres in the Delaware and Midland Basins of West Texas/SE New Mexico.  As shown by the table below, the average acreage value for assets in this area is $4,316 which values FST’s acreage at $494 million.  Even if FST receives a valuation near the lower bound of the sample size, it will still cover its expected principal payments in 2014.  It’s my view that this company should be soluble through the end of fiscal year 2018, but surviving beyond that will require the type of fiscal austerity that would impress even the Greeks.

Recent Permian Transactions

Forest seems to have finally figured out that it doesn’t have daddy’s credit card anymore and needs to start showing some financial constraint.  Its Q4’12 capital budget is approximately $84 million, down 50% from Q3.  For fiscal year 2012, spending will be an estimated $624 million, $59 million less than in 2011.  Next year, spending figures to decrease significantly as the company attempts to spend within cash flow.  It only generated $286 million in cash flow during the nine months ended September 30, 2012 and  if cash flow is flat year-over-year (conservatively speaking), the company will have $381 million to spend next year.  While that’s not the type of spending trajectory we want to see for a potential investment, at least Forest is taking its medicine.

The company’s survival beyond 2018 will be dependent upon its ability to develop its existing asset base while spending within cash-flow.  On paper, it has a great asset in the Eagle Ford with 40k net in Gonzales County, but its results there have been disappointing to date.  Based on the data I saw from the Texas Railroad Commission, the company has one good well in Holmes 1H which has produced more than 100k barrels of oil in just under a year, a handful of economic wells and just as many poor wells.  It’s not unusual for a company to have inconsistent results at the beginning of a drilling program, but I would have liked to see a few more good wells from its Eagle Ford program.  I still think this acreage will turn out to be productive for the company, but FST’s struggles there to date are something to monitor.

The company has had much more success in the mid-continent, where according to its Q3’12 earnings call it has recovered nearly one million barrels of oil equivalent (~70% oil) from eight hogshooter wells during the past year.  This acreage is the company’s prized asset, but it’s going to need its Eagle Ford acreage to be economic for it to survive.

The company’s reserves are currently trading at an EV/Mcfe of $1.46, which is quite a bargain considering its assets.  However, I’m not sold on its ability to develop its existing assets at this point and to be honest I don’t need to be as this company’s stock doesn’t look to be moving up anytime soon.  Also, management seems to be comfortable with maintaining a debt level circa $1.5 billion, which would still put its debt-to-cap North of 150%, a little too high for me.  If you already own the stock, there’s probably no reason to sell as it’s already trading near its bottom.  I’m not touching Forest, but if the debt doesn’t bother you it might be a stock to keep an eye on down the road.