Saturday, August 31, 2013

Death Valley

I was asked a question Friday that I've never been asked before.  
"Is Tiger Stadium within the boundaries of the TMS Play?".  No it is not, but this year is going to be a great one for Tiger football and the TMS. 
Geaux Tigers. Geaux TMS.

Tuesday, August 27, 2013

Goodrich Provides A TMS Update

Goodrich Petroleum just released this announcement:

Goodrich Petroleum Corporation Announces Closing Of TMS Acquisition And Operational Update

HOUSTON, Aug. 27, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced it has closed on the previously announced acquisition of a 66.7% working interest in 277,000 gross acres and 750 barrels of oil per day effective March 1, 2013. The closing price after purchase price adjustments was $23.7 million, which was funded with available cash. At closing the Company's borrowing base increased to $243 million, with nothing currently drawn.  The Company intends to spud its initial well on the acquired acreage in October 2013.

The Company also announced the completion of the non-operated Anderson 17-3 (7% WI) well at a maximum 24-hour average rate of 915 barrels of oil equivalent ("BOE", 94% oil) per day. Both the non-operated Anderson 17-2 (7% WI) well, which was previously reported at 1,540 BOE per day, and the Anderson 17-3 well have been on an accelerated choke schedule in preparation of the installation of downhole pumps which have the potential of moving high fluid volumes.

The Company also announced updated production for its Company-operated Smith 5-29-1 (98% WI) well, which has averaged 850 BOE (94% oil) per day over 25 days.

The Company has drilled and cased its CMR/Foster Creek 20-7-1 (98.5% WI) well, a 6,200 foot lateral with 23 planned frac stages and a scheduled frac date of September 1st.  The Company is expected to spud its Huff 18-7-1 (97% WI) well this week.

Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange.

SOURCE Goodrich Petroleum Corporation

Friday, August 23, 2013

TMS Transaction History

An energy research firm recently published a report on the Tuscaloosa Marine Shale transactions.  The report noted the wide variation in prices.  A chronological review of the transactions reveals an interesting trend of late.  The "backside" of the storm might be upon us with values rapidly accelerating.

Source:,,, personal communication
Note that the Devon/Sinopec value in 2011 was based on an average across all five projects involved in the joint venture.  The Sanchez/Sanchez valuation includes the value of the carried interest at $13M per well.  Additional details not displayed on the chart are confidential.


Wednesday, August 21, 2013

TMS in The Big Apple

Just back from New York City and Wall Street.  Two days of pitching the incredible upside of the TMS.  I ran into CNBC celeb, Peter Costa, in front of the New York Stock Exchange.  I was hoping to see GDP cross $25 per share "live", but it looks like a little profit taking is occurring.  The TMS momentum continues to climb.


Monday, August 12, 2013

Summer NAPE

Stop by our booth at Summer NAPE and get an update on the progress of the TMS along with reviewing the best remaining acreage available in the play.

Friday, August 9, 2013

Goodrich Earnings Call

Goodrich Petroleum presented their quarterly results on Wednesday with some very good news regarding the TMS.  Here are some of the highlights:

  • will close the Devon transaction in a few weeks
  • Sinopec, Devon's former partner, has elected to stay in the project
  • the Goodrich CMR/Foster Creek 20-7H-1 is almost to total depth
  • now planning to reallocate approximately $15 million of capital expenditures in the fourth quarter of this year from the Eagle Ford Shale play to the TMS
  • With continued success, we expect further acceleration of our TMS development activities in 2014
  • we can't help but be optimistic about the play at this point, as we see continuing improvement and repeatability of well results
  • costs are trending down, thereby establishing very attractive economics
  • The Smith well, which is approximately 5,400 feet of usable lateral with 20 successful frac stages, has averaged approximately 1,000 BOE per day of our 12/64-inch choke over the recent 8 days after reporting a 24-hour average rate of 1,045 BOE per day
  • The EnCana-operated Anderson 17H-2, which as Gil stated earlier, had the record IP to date of 1,540 BOE per day, had a similar frac design to the Crosby and a similar lateral links to the Smith well. Both of these wells had 95% to 96% oil cuts. The Anderson 17H-3 is in early flowback, and we expect that result to be good as well.
  • our Crosby well has produced in excess of 100,000 barrels equivalent in 5 months, with an approximate 92% oil cut, and is still producing approximately 375 BOE per day currently, as we near the end of the 6 months of normalized production
  • If you spot 375 BOE per day on our 800,000-barrel equivalent type curve at 6 months, you will see the decline has been flatter than expected, and we continue to trend above the curve. If you plot 100,000 BOE on our accumulative production curve at 5 months, you will see that Crosby is well above any other well in the fields and reached 100,000 BOE in half the time as compared to the better Bakken wells.
  • Our current plans are to spud 3 additional operating wells by the end of the year
  • seeing well costs come down in the TMS, as our Smith well was drilled and completed for approximately $13 million. We continue to believe we can drive our costs down over time to the $10 million range through better drilling efficiencies, pad drilling, zipper fracs and a more competitive service company environment.
  • even at current well costs, the economics are compelling in the play and very similar, if not superior, to what we see in the Eagle Ford. Our 800,000 BOE curve at $90 WTI produces a 56% internal rate of return, with 15% to 20% incremental IRR for every million dollars of savings or $10 movement in oil prices.
  • The economics are driven off of very attractive production rates, as well as certain inherent advantages of our other oil plays, such as our production stream is 90% to 96% black sweet oil, priced at approximately $2 off of LLS, and we continue to receive north of $100 per barrel; our gas has a high BTU content, with approximately 80 to 100 barrels of NGLs per million cubic feet produced; we have 24 to 30 months of severance tax relief in both states of Louisiana and Mississippi; our royalty burdens averaged approximately 19% across our combined acreage block versus much higher in other plays; and we are dealing with cooperative landowners and efficient state agencies for regulatory purposes.
  • our near-term focus is, as we think it should be on the TMS, as recent results in our pending acquisition provide a tremendous catalyst for production reserve and NAV growth. Given the current state of the play, we fully expect further acceleration of TMS activity as we move forward and into 2014
  • what's important to look at on the Anderson 17H-2 is just with a very slight change in choke, you can see the potential impact of volumes going forward
  • I think our first order of business with our new partner (Sinopec) is to get out and drill some wells jointly and to hopefully demonstrate our operational capabilities and certainly, hopefully, some successful wells together. And at that point, if they have some interest in expanding that position, we certainly would be all ears and willing to listen to them.
  • Obviously, one of the objectives is to try our wells, design our recipe on that acreage and see if we can turn that around. And having Sinopec hopefully participate with us, as we expect for a third interest, helps share some of the burden of that. And so we're going to move. And I would say, the move in the fourth quarter and the majority of our TMS activity in the fourth quarter will be on formally Devon acreage.
  • One of the benefits that we have gained from the Devon transactions, we did pick up core data on all of the Devon wells in which they took course, which materially added to our knowledge base from a geologic perspective. We're not saying -- and we've said this publicly, we're not seeing anything more than what we would call very nuanced differences in geology and mineralogy and rock properties including clay percentages and types of clay. So we don't see anything -- and I guess we should back up and resistivity, the high resistivity  we do think is an important feature. A number of different things contributing to that. We probably see the highest resistivity  quite frankly, across the southern part of the play in Louisiana, right along the southern part of the Mississippi-Louisiana border there. So we're optimistic, we need to get down there and demonstrate what we think it is capable of. But we're not seeing anything, at this point, that rules out any particular part of the acreage. The geologic changes or some nuance is small. And in fact, if you look at the Crosby, it's probably got the highest -- one of, if not the highest, clay content of any of the course we've seen across the play. So everything is open and on the table in our mind.
  • Severance tax reduction: It's 30 months or until the well pays out. And we believe that's on the order of $750,000 to $800,000 of benefit to the well. So very important and very meaningful.
  • No question the hybrid frac, in our opinion, work a lot better than slick water. And as Gil said, the clay stabilization fluid that we pump, you cannot argue is working extremely well. The first one to pump that particular type was the Crosby well. And when you look at lateral links and profit amount pumped and how those wells were completed compared to others, that well is certainly superior to the other ones. So we think that's an important ingredient to put in the recipe.
  • When asked about how much acreage you, potentially, if you were having to handicap it, to maintain, I think the comment was at least 75% of that was either shallow, above 14,000 feet through vertical depth, so your well costs would be lower, or in -- what we view could be core and less on the fringe of the outskirts. So that was basically just an attempt to handicap it if we could. We don't see anything but subtle differences when you look at core data, not only from the Crosby all the way into the Devon acreage package. We think it's all in the completion recipe. So no, nothing has changed. Certainly, once we got into the data room and we were able to review the data, we became more positive about the Devon acreage. But no, we were just trying to handicap at that point in time. But as Gil said, we can't rule out any of the acreage at this point.
  • the Crosby has higher clay content that almost any well out there, and you look at how that well has performed versus the other wells, knowing that we pumped this particular type of stabilizer and it's just the fluid that you include in your frac fluid, you can't rule out the fact that that well has performed exceptionally well. And it's just basically a pump to keep the expendable clay portion of the overall clay from swelling. And if you can keep it from swelling, it becomes less sponge-like, you get a more effective frac, you get your fractures propagated and held open, it doesn't want to close up on you. So it's a fairly simple, I would say, process. And we had quite a bit of lab work done and analysis done, and we felt like this potentially could be as much as 75% more effective -- at least that's what some of the lab work had indicated. So yes, we're pleased with it. And of course, the not going in was whether the clay would impact these -- the production, and we're not seeing the impact of clay on any of the wells. But certainly, the Crosby, and these last 2 wells, are performing exceptionally well with the pump.
  • the Crosby is outperforming our 800,000-barrel curve. The oil cut is about 92% there, and that's been fairly consistent
  • I would say that not that many of the people view the play the same way we do. And when the price got down into our strike range, we went after it. And I will let everybody else comment for themselves about why they didn't pursue it.

The entire transcript:

TMS Gas Oil Ratio

The map below represents an updated GOR map for the "new era" TMS wells.  These GOR values represent the cumulative production to date available from the regulatory agencies.  The Crosby 12H-1 and the Joe Jackson 4H-2 both have higher GOR's than other wells on structural strike.  The overall trend, as expected, exhibits an increasing GOR with depth.  As more wells are added in the future, the map will become more refined.


Thursday, August 8, 2013

TMS Acreage Valuations Skyrocket

Today Sanchez Energy announced an agreement where they will be acquiring 40,000 net acres in the TMS play.  It appears that the private equity partner in affiliated company, SR Acquisition I, LLC, has been bought out.  This represents a market transaction between a private equity entity and a public company.  In contrast to Devon's "distressed sale", this metric presents significant validation to the value of the TMS play.  Some estimated calculations of the value are:
-40,000 net acres
-$78,000,000 in cash and stock
-a 50% carried interest in 6 wells (use $13M per well based on the Goodrich Smith 5-29) equals $39,000,000
-this totals $117 million for the total valuation and $2925 per net mineral acre
At $2925, this is slightly higher than the valuation that MCX paid to enter the joint venture with EOG in 2012.

Sanchez Energy Announces Agreements To Acquire Approximately 40,000 Net Acres In The Core Of The Rapidly Developing Tuscaloosa Marine Shale Trend
HOUSTONAug. 8, 2013 /PRNewswire/ -- Sanchez Energy Corporation (NYSE: SN), a rapidly growing independent oil and gas company targeting onshore U.S. Gulf Coast oil resource plays with a current focus on the Eagle Ford Shale, today announced it has entered into agreements pursuant to which and upon closing Sanchez Energy would acquire approximately 40,000 net undeveloped acres in the core of the Tuscaloosa Marine Shale ("TMS") trend for cash and shares of its common stock plus an initial 3 well drilling carry.
Pursuant to the terms of the agreements, Sanchez Energy established an Area of Mutual Interest ("AMI") with its affiliate SR Acquisition I, LLC ("SR") in the Tuscaloosa Marine Shale.  As part of the transaction, Sanchez Energy will acquire all of the working interests in the AMI owned by an unaffiliated private equity firm plus a portion of SR's working interests, resulting in Sanchez Energy owning an undivided 50% working interest across the AMI through the TMS formation. The AMI holds rights to approximately 115,000 gross acres and 80,000 net acres.
  • Total consideration for the transactions will be approximately $78 million consisting of $70 million of cash and 342,760 shares of common stock (valued at approximately $8.2 million based on the closing price per share as of August 7).  SR will receive approximately $13.5 million in cash for the sale of its interest and the balance of the common stock and cash will be paid to unaffiliated third parties, including the previously mentioned private equity firm which made its initial investment in 2010.
  • Sanchez Energy has further committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI and at Sanchez Energy's election it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI. 
Tony Sanchez, III, President and Chief Executive Officer said, "For almost three years, we have been watching the evolution of the TMS and assessing the technical and economic development of the play.  We now believe it is an appropriate time for Sanchez Energy to enter the play and we have the opportunity to do so by leveraging the groundwork undertaken by Sanchez Resources over the past several years.  With the closing of this acquisition we believe we have secured a solid acreage position in the core of this rapidly developing trend.  Recent well results by other operators in the area are encouraging with respect to both strong well performance and decreasing drilling and completion costs.  We expect to commence our operated TMS drilling program in early 2014 and also anticipate participating in several non-operated wells given our proximity to other active operators in the area.  We are excited to bring our development skills and expertise to such a dynamic basin, and believe the strategic diversification to the TMS will continue our track record of building shareholder value."

Wednesday, August 7, 2013

Encana's Proposed Units

With 317,000 net acres leased across the play, one might question how Encana has zero rigs currently active in the play.  Unit applications over the past few months might indicate that their rig count could be increasing in the near future.  Close-ology and repeatability appear to be the strategy.  Rig activity will be the "proof in the pudding".

Source: LA Office of Conservation, MSOGB

Tuesday, August 6, 2013

Record Setting IP Announced in the TMS

Today Goodrich Petroleum announced that the Encana Anderson 17-2 has flowed at a peak 24-hour average rate of 1,540 BOE (95% oil) on a 17/64 inch choke.  This represents a new record for peak flow rate in the play.  The well landed very low in the shale and completed approximately 5200' of lateral.  That is a significant result especially relative to the lateral length.

With known results from 24 TMS completions, an evaluation can be performed to assess the drilling and completion approaches.  The table below presents five wells that meet the following criteria:
-Lateral length > 5000'
-Landing zone: bottom 70' of the TMS
-Feet of pay > 75'
-Proppant per stage = 400,000-600,000#/stage

When all of these criteria are met, initial potentials range from 928-1540 boepd (90-96% oil).  

Source: SONRIS, MSOGB, Amelia Resources LLC

Friday, August 2, 2013

Halcon Earnings Call

The TMS was discussed briefly on Halcon's earnings call.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division
And then just moving over to the TMS. There's been some momentum in the play, with a few good results albeit to the east of your acreage. I'm just wondering how you guys are thinking about that play kind of going forward.
Floyd C. Wilson - Chairman and Chief Executive Officer
We have not lost interest whatsoever. As we reported early on, our Broadway well had the thickness and the organic content and all the basic reservoir characteristics we like to see in the shale well, very similar to what they're getting east of there. So we had some completion problems there, lost the well essentially. We're not planning on anything there this year. We have plenty of lease term. But we're very interested and hopeful that the play is going to turn into a moneymaker for the industry and including ourselves.
Kyle Rhodes - RBC Capital Markets, LLC, Research Division
And did you guys look at the Devon acreage at all?
Floyd C. Wilson - Chairman and Chief Executive Officer
We look at everything in any area, but we didn't really pursue it. We've got quite a bit of acreage over there now.
Kyle Rhodes - RBC Capital Markets, LLC, Research Division
To the east?
Floyd C. Wilson - Chairman and Chief Executive Officer
Pardon me?
Kyle Rhodes - RBC Capital Markets, LLC, Research Division
To the east, you said? You have acreage over there to the east?
Floyd C. Wilson - Chairman and Chief Executive Officer
Well, our acreage block is expansive in the area. I think we have close to 100,000 acres in leases and options, some number about like that, 90,000 or 100,000, I don't know.


Thursday, August 1, 2013

TMS Reserves and Economics

With additional production history from the existing wells in the play, it is now possible to update economic and reserve analysis.  Decline curves and recent well results with the "Crosby 12H frac design" are providing very strong support for the economic viability of the play.  Within the week, we should have an announcement of a new record setting initial test in the play.

The graphics below summarize an up-to-date assessment of the the economics of the play and the potential recoverable reserves.  The well cost of $12 million is based on the development cost for an offset to the recent Goodrich Smith 5-29H well that cost $13 million.  AFE's based on EOG's drilling times are $10-11 million.

The decline curve variables are based on current and historic producers.  The Encore TMS producers provide 4-5 years of production life to assess the B-factor.  Estimates of 350 bbl/ac-ft and a 6% recovery factor were used.  EOG has recently raised the recovery factor in the Eagle Ford from 6% to 8%.  With a recent initial test exceeding the Crosby 12H, IP30 ranges were increased.  The Crosby 12H continues to track on an EUR curve of 800-900 MBOE.

An IRR of 20%, as an economic cutoff for the play, equates to an EUR of 410 MBOE. On average, that would equate to 62' of pay (dashed line on map below).  That boundary encompasses 2.66 million acres and, by our current estimate, represents 9.175 billion barrels of reserves.

TMS play boundary and active wells and units (Source: SONRIS and MSOGB)
Estimated play reserves

Economic input variables

Economic cases

Estimated estimated ultimate recoverables and IP30's