Wednesday, February 26, 2014

Halcon Resources Announces A Significant Acreage Position in the TMS East

Today Halcon Resources announced that they now have 307,000 net acres in the TMS play with 77% falling in the TMS-East. This makes them the largest acreage holder in the play.  The company's management and technical team have a significant tract record in the industry.  I expect them to make a large contribution to the play.

"Halcón has established the TMS as a third core area. In aggregate, the Company currently has approximately 307,000 net acres leased or under contract in the play. Approximately 77% of the acreage is located in Southwest Mississippi and the Louisiana Florida Parishes, also known as the "Eastern TMS."
The proceeds from the pending sale of non-core assets are expected to provide Halcón the ability to internally fund the TMS program. However, the Company is evaluating joint venture options for its entire TMS position and is engaged in ongoing discussions with several potential partners.  
Halcón employs an experienced exploration staff that has been working the TMS for more than a year with access to hundreds of well logs and core data from a number of wells. As a result, geologic mapping from these efforts have allowed for the acquisition of land within a well-defined area believed to be the geologic core.
The Company plans to operate an average of 2 rigs for the remainder of 2014 and spud 10 to 12 gross operated wells in the TMS. Halcón also expects to participate in several non-operated wells in 2014. Expectations are to spud the next operated well in March of 2014 near producing TMS wells inWilkinson County, Mississippi. No changes to guidance are being made as a result of this announcement as TMS drilling activity was incorporated into the Company's 2014 business plan and budget. Halcón plans to spend approximately 10% of its drilling and completions budget in the play in 2014, subject to reduction dependent upon ongoing negotiations with potential joint venture partners.
Charles E. Cusack III, Chief Operating Officer, stated, 'We have been working the Tuscaloosa Marine Shale from a geologic standpoint and monitoring industry activity in the play for quite some time. Our strategy is to identify scalable and repeatable resources plays where we feel we can meaningfully improve the economics by applying our extensive technical experience. We believe the TMS fits that strategy, and we are excited about our position in the play.'"

Source:
http://investors.halconresources.com/releasedetail.cfm?ReleaseID=828607

Source: www.halconresources.com

Source: www.halconresources.com



Tuesday, February 25, 2014

Goodrich Petroleum Management Discusses Q4 2013 Results

I've received numerous calls, emails, and text messages the last two weeks regarding the results from Goodrich's latest two wells.  Due to the significant volatility of trading in Goodrich's stock, I chose to postpone making any comments until things quieted down a bit.  To confirm, this blog is not a source of information to be used for trading equities or for making any type of investment.  Since March, 2011, it's sole purpose has been to provide free and accurate information in a timely fashion to all interested parties with the goal of facilitating the success of exploration plays across Central Louisiana and Southern Mississippi.

Without question, the results from both the Huff and Weyerhaeuser wells are disappointing.  Goodrich did an excellent job of providing details of the current challenges along with potential resolutions. With 32 completions, the play is still in its infancy and more challenges lie ahead.  With several operators and committed budgets, I believe that this play will break through this year.

Stay tuned for Halcon's earnings call on Thursday.  If rumors and recent articles are accurate, there could be some really good news ahead.  I'm the most confident that I've ever been in the play. Remember, the Eagle Ford wasn't built in a day.

I will provide some detailed Q&A later this week.  The Goodrich transcript is below.


Transcript (Source: Seeking Alpha)
Operator
Good day, and thank you, ladies and gentlemen, and welcome to the Q4 2013 Goodrich Petroleum Corporation Earnings Conference Call. [Operator Instructions] As a reminder, this call is being recorded. I would now like to turn the conference over to Mr. Daniel Jenkins, Director of Corporate Planning and Investors Relations. Please proceed, sir.
Daniel Jenkins
Good morning, everyone, and welcome to our fourth quarter and full year 2013 earnings call. I would like to begin with the introduction of the management team on this call with us this morning: Mr. Pat Malloy, Chairman of the Board; Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer; Mr. Robert Turnham, President and Chief Operating Officer; Mr. Mark Ferchau, Executive Vice President, Engineering and Operations; and Ms. Jan Schott, Senior Vice President and Chief Financial Officer.
As is our practice, we would like to make everyone aware that comments and answers to questions made during this teleconference may be considered forward-looking statements, which involve risks and uncertainties, as have been detailed in our SEC filings.
We will begin with our prepared remarks, and then conduct a question-and-answer session. I would now like to turn the call over to our Vice Chairman and Chief Executive Officer, Gil Goodrich.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Thank you, Daniel. Good morning, everyone. Rob will provide you with more details in just a minute, but we are very pleased with the increase in proved reserves at year-end 2013, which is the result of our focus on oil development drilling during the past year and the overall improvement in natural gas prices from the prior year.
Since year-end, the continued strengthening in the natural gas market is very encouraging, and has the potential to meaningfully add to the value of our portfolio of natural gas opportunities, where we have several Tcf in inventory. However, our near-term focus remains on building a large, balanced portfolio of both oil and natural gas reserves.
Jan's going to provide you with more detail in a few minutes. But before I move to the TMS, a couple of brief comments on our balance sheet and liquidity. We ended the year with just under $50 million of cash on hand and another $51 million of cash in an escrow account, which is earmarked for the redemption of the remaining 2029 5% convertible notes, where we retain the flexibility to potentially negotiate the conversion of the remaining notes into 2032 5% notes and add the additional $51 million to unrestricted cash.
As we have 0 borrowings under our senior credit facility and a current borrowing base of $270 million, our current liquidity, before any potential conversion of the existing 2029 notes, is $320 million.
In addition, our preliminary CapEx budget for 2014 is back-end weighted, and we will remain very cautious and prudent with our capital plan, as we always do, based on results and success across our portfolio.
I would now like to turn to the Tuscaloosa Marine Shale play, as Rob and Jan will provide more details on the fourth quarter and full year 2013 financial report in just a minute.
First, we understand and share the shareholder frustration with the recent operational issues we have encountered in the TMS, and we can assure you our entire team is focused on mitigating and resolving these issues going forward. During the past 2 years, we and our partners in the play have made tremendous progress in de-risking and delineating the TMS and demonstrating, we believe, the tremendous potential of the play. However, like all emerging plays, we have experienced a number of challenging, unique issues with this play, some of which we have been able to successfully mitigate, yet other challenges remain as we continue to work towards best practice to both drilling and completion operations. Therefore, I would like to spend a few minutes highlighting some of the challenges and resolution efforts we have experienced and give you as much detail as possible.
In the earliest days of the play, the higher clay content present in the overall TMS section was considered the greatest risk to successful development. Our development thus far has, in our view, significantly mitigated, if not eliminated, the concern of the clay content, which would inhibit the ability to successfully frac the TMS or the ability to produce acceptable recoveries of oil or EURs. In fact, we are as confident today in and very positive on the resource potential of the TMS as we have ever been.
We now have wells that have tested oil rates in excess of 1,000 barrels per day. And we believe we'll generate EURs within a range of tight curves, which we have published for you, over a broad area, and similar performance from wells almost 40 miles apart.
As I mentioned, we and others in the play have encountered several operational challenges. The first unique challenge we experienced relative to the TMS drilling operations was maintaining wellbore stability in the lateral section of the horizontal wells. As many of you are aware, there are sections within the TMS, which are highly naturally fractured, or as we have described them, rubblized zones. Our efforts to mitigate the problems and enhance wellbore stability have been numerous and are yielding positive results.
Mitigation efforts have included: Increasing mudways through the lateral section, enhancing and improving mud rheology, increasing the vertical angle of doing prior to landing in the horizontal section of the well, so as to reduce the build angle, contact with and exposure to the rubblized section, and moving the horizontal landing target somewhat higher in the TMS section, so as to create greater stability. Each of these efforts has produced positive results in recent wells, and we are increasingly confident that we have not only made great progress, but largely overcome this challenge.
One of the options, which has net successfully mitigated wellbore stability issues, have been to move the landing target up by 40 to 50 feet, or higher in the TMS section and closer to the center of the TMS. This change in landing target has produced positive drilling results in the 3 wells we have drilled, and in approximately 8 wells across the industry in the upper target.
However, in each of these 3 wells that we have drilled, we have experienced problems drilling out the frac plugs after completion in frac operations. As we have not experienced any difficulty or problems moving frac plugs down hole, and out along the lateral in sequence during frac operations, we believe the issues are occurring contemporaneous with, or immediately following the pumping of an individual frac stage. Further, we believe the issues are being caused by or exacerbated by the higher clay content present in the upper part of the TMS, compared to the lower section.
In essence, what we believe has occurred in these upper target wells is the higher clay content has increased the elasticity of the formation itself, which during the pumping of an individual frac stage, is creating a slight amount of deformation, but not rupturing of the casing stream, which is leading to the difficulties drilling out frac plugs. In fact, to date, there have been approximately 30 modern era horizontal wells drilled into the high resistivity TMS.
Of those, 22, or approximately 73%, have been drilled into the lower landing target, where there is generally less clay and more quartz present, and experienced little difficulty drilling out the frac plugs, while 5 of the 8 wells, which have been drilled into the upper landing target, have experienced significant problems drilling out the frac plugs.
Following our Foster Creek well, which was a high target well and where we encountered our first significant problems drilling out frac plugs, we made this decision to use a permanent style frac plug, with a 2-inch interior diameter, or ID, which would provide sufficient flow diameter without wellbore draw down and eliminate the need to drill out plugs. The permanent style plugs have the potential to be an elegant solution as they could eliminate the risk associated with drilling out plugs, as well as reduce overall well cost by approximately $500,000.
The first well we used the permanent style plugs on was our Huff 10-7H #1 well, which is an upper target well, and we have subsequently used those same plugs on the Weyerhaeuser 51, which is a lower target well. As is our standard practice, we include a unique chemical tracer in each stage of the well so that we can analyze the fluid recovery and get an indication of which stage or stages are contributing during the flowback.
On the Huff well, early flowback was consistent with expected pressures, frac waters, oil rates. When an event occurred, which caused rates to fall immediately. Upon review of the tracer data, it became apparent we had an event which plugged off a significant portion of the lateral. The tracer's data suggest the event or plugging occurred between a frac plug approximately 500 feet out the lateral. Rob will give you more details on the Huff in just a minute.
Following the issues encountered on the Huff well, we change our landing target and drilled and completed our Weyerhaeuser 51 well with a 6,200 foot lateral at 23 frac stages in the lower TMS target, where no previous wells had encountered significant problems drilling out the plugs.
Knowing the permanent style plugs can be drilled out if required, we completed the wells with the permanent plugs. And following completion, initiated flowbacking very high frac fluid rates initially. Over time, however, the well's fluid rates, pressure and chemical tracer data again suggest that we have plugging taking place in the lateral. As a result, the decision has been made to drill out the plugs in an effort to resolve this issue, and we are currently drilling out plugs in the well.
In summary, while challenges remain, we are making significant progress in resolving issues and problems as they occur. By drilling through the upper portion of the TMS and rubblized section at a steeper angle, as well as the improved bit selection and mud properties, we have made excellent progress on the drilling side and eliminating wellbore instability. To mitigate the recent completion issues, we plan to drill lower target wells, as is the case with the CMR, Blades and Lewis wells, which we are currently drilling, and the CMR, we're currently completing. And a near-term plan to use composite plugs, which we will drill out after frac operations, as we wait for the market to continue to refine the technology and optimum solution for the permanent style plugs, which we believe still hold great potential for the play.
With that, I'd like to turn the call over to Rob Turnham.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Thanks. As Gil has laid out for you, the TMS is still in early stage development, and reminds me of what we and other operators experienced in the Haynesville, a prolific resource and an overpressured reservoir with unique drilling and completion issues.
Just like the Haynesville, where we took our drilling days down from 13 from the start to finish, by 13 from start to finish, where well costs went from over $10 million to approximately $7 million, and where we ultimately figured out the optimum drilling and completion methods, and got to repeatable consistent results, we feel the same will hold true over time in the TMS.
We feel you cannot deny the resource potential of the TMS when you look at recent well results. Of our operated wells in which we now have some history, our Crosby has produced 160,000 barrels equivalent in approximately 11 months. Our Smith well is at or slightly above our 600,000-barrel curve, even though 2/3 of the 1-inch ID frac plugs are still in the hole. And our Foster Creek has had a very stable production profile and is producing more per 1,000 feet of lateral than any of the other wells in the play.
Many of our non-operator wells are also trending around or at our 600,000 to 800,000-barrel curves as well. In addition, we have recently reworked several of the previously drilled and producing TMS wells we acquired last summer. On each of these wells, we have installed artificial lift or if already on lifts, lowered the pump and tubing depths, and significantly increased the pump capacity with new Rotaflex pumps.
While still fairly early, we are very pleased and encouraged by the production responses in these wells, which we believe has increased most of the wells' performance within the range of our TMS type curves, which at current commodity prices will basically taper our acquisition of the wells and the acreage.
We also see the potential for upside on production and reserves on our non-operated wells, with optimization of artificial lift. We reported completion results on our Huff well and upper target well at 530 BOE per day on a 13/64 choke, which was approximately 95% oil. We are unable to get down to the obstruction in the frac plug in the lateral at approximately 500 feet, and we think it is likely due to the tight spot in the casing. However, it appears we may be getting some contribution from the lateral at the reported rate, as 500 barrels of oil per day from 500 feet is too prolific versus past results and expectations.
A good analog in the field to production from the Huff is the Foster Creek well, which is also an upper target well. The Foster Creek has 2,100 feet of lateral at the same initial production rate, and has had a very flat production curve, which we will be showing in future slides.
Gil mentioned the status of the Weyerhaeuser 51 well, which was drilled successively in the lower target, so I will not spend any additional time in my prepared remarks on that well. We are currently fracing our CMR 8-5 well in Amite County, Mississippi, which is a 5,300 foot lateral with a planned 20 stage frac. We're drilling the lateral on our Blades Well in Tangipahoa Parish, Louisiana and just getting started in the C.H. Lewis well in Amite County, Mississippi. All 3 of these wells are or will be lower target wells, as the last 4 to 5 wells we and others have drilled in the lower target have not had the same wellbore stability issues as previously experienced.
On the cost side in the TMS, we've locked in lower frac cost per well for 2014, and continue to see more competitive bids across the board, which we expect to continue with higher activity levels in the play from multiple operators.
We now are aware of at least 5 companies with plans to drill in our area in 2014, which with continued success can allow for as many as 45 to 60 wells for the year or more, up from approximately 10 in 2013. 2014 will be a very big year for the TMS, obviously, if plans materialize as expected.
Capital expenditures for the quarter totaled $50.8 million, of which $38.3 million was spent on drilling and completion of wells, $9 million on leasehold acquisition and extensions, and $3.5 million on facilities, capital workovers and other miscellaneous expenses. Capital expenditures for the year totaled $255 million, which was spot on our budget, comprised of $212.4 million on drilling and completion, $38.4 million on leasehold acquisitions and extensions, and $4.2 million on facilities, capital workovers and other miscellaneous expenses.
We have established a preliminary capital expenditure budget for 2014 of $375 million. We have allocated $300 million to the TMS, but are currently running at a much slower pace than that, with 2 rigs running currently and a third arising in March. Our $300 million preliminary estimate in the TMS is subject to continued success, and predicated on drilling or participating in 32 gross, 23 net wells for the year, which would have us reaching 5 rigs by the end of the year.
We expect to minimize and hopefully eliminate the remaining drilling and completion issues prior to contracting for the fourth and fifth rigs.
In the Eagle Ford, we have allocated $45 million to drill 9 gross, 6 net wells, with 1 rig currently running. We've allocated $15 million to our Angelina River Trend, down from $30 million originally budgeted, as we executed some lease extensions and are estimating $15 million for leasehold and infrastructure.
We have staggered our rig contracts to give us flexibility on timing and capabilities across our portfolio of opportunities. CapEx guidance for first quarter '14 is $45 million to $60 million, which is obviously at a much reduced run rate than our preliminary 2014 budget, as we had back-end loaded at the budget to allow for developing best practices prior to running at full speed. We have also gone to quarterly guidance on CapEx in production as we need to get a little further down the road on timing of rigs.
We reported year-end reserves of 452.2 Bcf equivalent, a 36% increase over the prior year period. Reserves were 73% natural gas, 27% oil and NGLs and 39% developed. We had 90.9 Bcf of positive reserve revisions, primarily due to Haynesville proved undeveloped reserves coming back on the books using average prices for 2013 of $3.67 per gas and $96.94 for oil.
As a reminder, we have close to a Tcf of 3P unrisk resource potential on 80 acres spacing in the core of the Haynesville in North Louisiana that is held by production, an additional 2 to 3.4 Tcf of unrisk resource potential in the Angelina River Trend.
Future net cash flow of the proved reserves at year-end under that pricing was $1.1 billion with PV-10 of $472.3 million. Total refining and development cost was $21.07 per BOE, and proved developed timing and development cost was $32.89 per BOE, when calculating off a 2013 drilling and completion cost, including pipe conversions.
Production for the quarter totaled 7.4 Bcf equivalent, or an average of approximately 81 million cubic feet equivalent per day, with oil comprising 29% of the total and 67% of revenues. Oil production for the quarter as outlined in the press release was negatively impacted by production delays in the TMS.
Now I'm going to turn it over to Jan to walk you through the financials.
Jan L. Schott - Chief Financial Officer, Principal Accounting Officer and Senior Vice President
Thank you, Rob. Good morning, everyone. I will cover a few items on the financial side. Adjusted EBITDAX for the quarter was $32.3 million and includes $0.4 million in realized loss on derivatives not designated as hedges. Prior year quarter adjusted EBITDAX of $50.5 million, included $17.1 million in realized gains on derivatives, mostly natural gas swap contracts that expired at the end of 2012. Revenue for the quarter totaled $50.6 million, an increase of $2.3 million or 5% over revenue for the comparable period last year, with oil representing, as Rob mentioned, about 67% of oil and gas revenues for the quarter. Our fourth quarter average realized prices were $93.66 per barrel for oil, and $3.15 per MCF for natural gas. Our average realized price was $6.81 per Mcfe for the quarter.
On December 31, certain oil swaptions expired. That same day, we entered into oil swaps on 1,300 barrels of oil per day at an LLS price of $94.55 for 2014 and 2015. For calendar 2014, we have a total of 3,800 barrels of oil per day, hedged at a blended price of $93.65, and 30,000 MMBtu per day of natural gas hedged at a blended price of $4.76. Please see our website for more detail on our current derivative position.
Moving on to expenses. LOE this quarter was $7.1 million, or $0.96 per Mcfe, up $2.5 million from prior year quarter and consistent with last quarter. The fourth quarter includes about $1.6 million or $0.22 for workovers, primarily in the Eagle Ford Shale.
DD&A per Mcfe was $4.38 for the quarter, compared to $4.33 last quarter and $5.62 for the prior year quarter. Improved EURs and lower average well cost in the Eagle Ford Shale trend drove the rate improvement compared to last year. Going forward, while field level DD&A rates for Eagle Ford Shale and TMS improved, we would expect the overall company DD&A rates to trend slightly higher in the first half of 2014, as oil production continues to increase as a percent of total production.
Exploration costs for the quarter of $5.8 million, or $0.78 per Mcfe, includes $4.1 million in dry hole cost related to the Denkmann 33-28 H1. We drove the well in 2012 but opted not to drill any well utilizing the existing wellbore, and expense the remaining well cost in the fourth quarter.
G&A costs came in at $8.7 million, or $1.18 per Mcfe this quarter, compared to $1.09 per Mcfe in the prior year quarter and $1.08 per Mcfe last quarter. The fourth quarter included about $0.6 million associated with the closing of our Shreveport land office. Also, about $0.33, or 28% of the fourth quarter rate, represents noncash stock-based compensation.
In the fourth quarter, we recorded a noncash $2.3 million loss on extinguishment of debt. As you recall, in August of last year, we exchanged half or $109.25 million of our outstanding 5% convertible notes for new notes with an initial call date of October 2016, and an initial put date of October 2017. In the fourth quarter, we exchanged another $57.4 million of original 5% notes for $57 million in new notes. The loss represents the unamortized debt issuance cost and debt discount associated with the original 5% note. We are projecting a 0 tax rate for the full year of 2014.
Our primary finance initiatives for 2013 were to improve liquidity, shore up the balance sheet and position the company for a ramp-up in the TMS in 2014. There are 2 preferred stock offering and common stock offering last year. We raised over $400 million in capital. We ended the year with $49.2 million in cash, and $51.8 million in restricted cash, which extended the maturity on our credit facility to February 25, 2016. Our borrowing rate is currently $270 million with 0 borrowings under our revolver. The next redetermination of our borrowing base will occur in April 2014, based on our year-end reserve report. As Gil mentioned previously, we ended 2013 liquidity of about $320 million, with $51.8 million in restricted cash for a total of $372 million.
We have included reconciliations on the last pages of our press release for all non-GAAP measures to the closest GAAP measure. Please refer to these reconciliations for more detail.
We plan to file our 2013 annual report on Form 10-K with the SEC tomorrow. Please see our 10-K for a more detailed financial discussion. With that, I will now turn it back to Gil for some closing comments.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Thank you, Jan. While some operational challenges remain, we are working very hard and continuing to make progress designing best practices in the TMS for drilling and completion operations. We are adding a third rig to the TMS at the end of the month, and we'll have a number of additional well results coming over the next couple of months.
In addition, we believe increased industry activity and additional wells drilled will be very important to the play. And we remain very constructive about the play overall, and our development over the next few months. That concludes our prepared remarks. And I will now turn it back over to Salu for the questions and answers.
Question-and-Answer Session
Operator
[Operator Instructions] Standby for your first question, and that is from the line of Leo Mariani of RBC Capital Markets.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
In terms of the TMS wells, could you share any reserve bookings you had at year-end '13 in the play? Just trying to get a sense of what your third-party engineers have credited those wells.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, Leo, this is Gil. We don't give individual well reserves. What I will say is that the Crosby Wells outside reserve fit pretty much right in between the 600,000 and 800,000 barrel curve. The other one's obviously a little bit less because of the additional -- the obstructions that we've talked about. Smith was up there pretty good. I don't have the exact number on my head. But I would say, in terms of early days, we saw reserves across the board. They were pretty consistent with our expectations.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, and I guess, a couple of those wells, do you guys have like current production rates on the Smith, Crosby and Foster Creek, in terms of what they're producing today?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Leo, we update our measure presentations pretty regularly. We update -- upgrading those curves at least monthly. Rob, yes, we did it last week. Rob made a presentation earlier this week. So those are pretty current numbers.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, and I guess, could you just speak a little bit more to well cost in the TMS? Obviously, it sounds like you're going to target the lower zone, lower part of the zone at this point. What type of well cost do you guys anticipate by targeting that area and kind of any thoughts on the Weyerhaeuser well cost, can you share that with us?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Well, I'll tell you, Leo, this is Rob. We're maintaining our $13 million AF fee for now, even though completion costs are less right now, just due a to a better frac bid. We're not only paying less on the equipment, but we're buying the sand directly, and all of that saving us, on a 20-stage frac, as much as $500,000 to $700,000. I think the lower target well takes a couple of extra days. Obviously, if you're being a little more prudent or going a little bit slower, but we've certainly seen better wells that had landed in the lower target. So I think going forward, until we can routinely show well cost routinely below the $13 million, we're going to just use that going forward. As to the Weyerhaeuser well, we're going to have to get through the drilling out the plugs before we know that. We were probably, I would say, 10% over, as of not too long ago. But we're just going to have to see where that winds up.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, and I guess just with respect to CapEx for the year, you talked about being more cautious with the additions of the fourth and fifth rig. I guess, just presuming that those don't show up til maybe closer than year-end, I mean, do you guys have any thoughts on what CapEx might be? I know you've got the $375 million budget, might that come down or might you reallocate and spend more money in the Eagle Ford? Can you just kind of walk us through that dynamic for the year?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Sure. With the current plan, if you just stayed at the 3 rigs, and you didn't do anything other than that, obviously, not scaling up to 5 is going to cut quite a bit of capital in the TMS. Now we do -- we haven't run those numbers. It all depends on where you put the rigs as to whether we do it on the joint acreage with Sinopec, or whether we do it on our 100% acreage. But we'll come up with those numbers. But it's a significant savings, I think. In fact, Daniel Jenkins is looking right now just to see if we have that number, before I get off your question. Yes, we also have that flexibility. These rigs are capable of drilling in other areas if you wanted to redirect the capital. But way too early, we -- we're still positive about what we're seeing and fully expect to resolve the completion issues. The drilling, as Gil suggested, is going much better. And the last several wells just have not had the rubble zone issues. So that part feels much better, and it's really basically piercing the rubble zone at 70 degrees instead of lying down in it when going horizontal. So I think we're going to hold off on what that revised CapEx budget would be, because we're not ready to do that. We still feel very good about where we are in the play and obviously, look forward to getting the completion issues out of the way. Looks like, just seeing kind of a revised number. So for example, and I'm telling you, we think it's more likely we run the 5 rigs than not. But it looks like you would save about $75 million if you just stayed with the 3 rigs running for the rest of the year.
Operator
And the next question is from the line of Dan McSpirit of BMO Capital Markets.
Dan McSpirit - BMO Capital Markets U.S.
Many of the difficulties in drilling and completing TMS wells have been explained by operating or mechanical issues. Is there anything about the rock itself that could present an obstacle to -- too great to make this play economic. I'm asking in an effort to get a better sense on how you feel about the resource today versus 12 months ago, and whether returns could prove as competitive and repeatable as what you're drilling in South Texas.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, I'll -- this is Gil, Dan. I'll take at least the first part of that. As I tried to say in my prepared remarks, the clay content, the higher clay content in the TMS, we think has largely been removed as an issue relative to production capabilities, resource potential and EURs. It does appear that it is a contributing factor, if not the factor, relative to the completion in pipe deformation issues that we believe we've encountered, particularly in the upper target wells. So as I said, 5 of 8 wells that land in the upper target did have some degree of problems drilling out the frac plugs, most of which appear to be pipe deformation-related. So the good news, I think is, that as you, as we've talked about before, the TMS, and we've got over a dozen cores across the play now, is invariably the highest clay content in the very top, the lowest content is almost always in the very bottom. That's being offset by more quartz content in the very bottom. So we've got, call it, 20 wells now that landed in the bottom that didn't have any problems drilling out their plugs, or I should say any significant problems drilling out their frac plugs. So we think that, that increased quartz content, lower clay, is giving a better place to land that casing in terms of what the rock is like surrounding it. And so it's got less elasticity, so that when you pump and propagate your frac, you're not getting as much elasticity or movement of the earth around you and therefore, not having as much issue with pipe deformation. We also, as a mitigating effort, have reduced our maximum pump pressures. It may mean that we end up pumping a little bit more across link gels throughout than an average job than we might have, otherwise. But that's also helping bring the treating pressures down and obviously, keeping the [indiscernible] pressures down is also very important and instrumental in mitigating pipe deformation. So a simple answer to your question is, it's a challenge, and one that we've seen. We see some pretty good pathways for eliminating that, and we're kind of right in the midst of working on that, and I think the next few wells are going to be very instrumental.
Dan McSpirit - BMO Capital Markets U.S.
I appreciate the color and the context. As a follow-up, what are the risks in not being able to fully remediate or fix the Weyerhaeuser well, not unlike the Huff. But if you are successful, is there any reason the well wouldn't flow as if it didn't suffer any issues?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
No, we're -- we certainly are hopeful. We won't try to prejudge what's going to happen. But we're certainly hopeful that by successfully drilling out the frac plugs, we will successfully open up the entire lateral and be able to go back into flowback mode, and have the kind of well we envisioned when we drilled.
Dan McSpirit - BMO Capital Markets U.S.
Got it, and any timing on results from that effort?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
What was the question, Dan?
Dan McSpirit - BMO Capital Markets U.S.
Any timing on results from the -- from that effort, from remediating the Weyerhaeuser well?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
We're getting beat up every which way with timing. And as I've said for a long time, unfortunately the oil field doesn't necessarily work on the same timetable that we would all like. As we've said a couple of times this morning, we are in the process of doing that. All goes well, that should go reasonably quickly. It won't be this week, obviously. But as soon as we can get them done, we will put the well on flowback and report that information.
Patrick E. Malloy - Chairman, Chairman of Executive Committee, Chairman of Hedging Committee and Chairman of Nominating & Corporate Governance Committee
Gil, I very seldom jump in here, but I'd like to go back to the previous question, where they were concerned about the capital expenditures; I've got to say that, for us to give a capital budget through the end of the year is very difficult. And the reason why it's difficult is the world has just changed dramatically. When less than 2 years ago, we were at below $3 at gas, now we're at $6. At $6, it's profitable. So we have to evaluate that. Obviously, our highest priority is [indiscernible] and in the Tuscaloosa Marine Shale. And we believe that we have a major, major asset there, which we're going to put a good bit of capital towards. But this will change numerous times through the year, based on prices. So I'm just, sorry for jumping in, but go ahead for the next question.
Operator
The next question is from the line of Neal Dingmann of SunTrust.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
Say, Gil or Rob, first question just, it sounds like [indiscernible] at least on the drilling and fracing side, you're pretty comfortable there. One, if you could comment around just kind of the timing, how you think on each of those, as you look, finishing up the CMR wells, you're drilling the other 2 wells. You've kind of gotten the processes down on each of those sides?
so that I'm trying to think of, now that you've got up to 5 rigs this year, potentially, how many, and I know you kind of mentioned how many wells you might be able to get, but I'm just trying to get an idea of how long, the drilling side, how long the fracing side typically now take, going forward?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Sure, Neal, this is Rob. The AFE stopped 45 days for the $13 million well cost. We're a little ahead of schedule on our Blades well, which is the furthest along right now. So we'll just see if we can get down on that one, continue at this pace. We ought to come in sooner than that. We're still modeling the 45-day drill time, the 60 day spud to spud and 75 days spud to sales. But certainly, just like every other play, we would expect to drive the number of days down and certainly, projecting over time to knock that 45 days down to 35. So I -- let's see where we end up on the Blades. It's a lower target well. It's over near the Devon Thomas in that vertical Blades Well that, obviously, has been producing for 30 years. But making great progress there. In fact, feeling better and better about the drilling side. Feel good that we're getting the fracs off. Now we just need to kind of check the box on flowback and frac plugs. Now I want to -- I do want to remind everybody that these frac plugs, the permanent plugs that we use, the ball that liquefies over 48 hours or so. We let the well rest for 72 hours. The plugs themselves are permanent, but the balls dissolve, and the plugs themselves are drillable. So in essence, we're basically kind of back to where would have been, had we used the composite plugs. We're just not getting the benefit of $500,000 of savings that Gil outlined. So nothing really has changed, have we used the composite plugs, we'd be right where we are. Granted, we would have been doing that a couple of weeks ago.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
And Rob, why was it on this last one? Was this essentially the same issue you had in the Huff. Why did it take, I think for a while, you thought maybe where it was, I guess, in fact flowing back. Why did it take a period before you realized that maybe it was clogged, whereas on the Huff, you're able to recognize that early?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. We -- on the Huff Well, if the event happened very early, and was so obvious that we had severe reduction in pressure and fluid rates and thankfully, like -- and it just happened immediately. And like we, like Gil said earlier, we had done a chemical tracer on that well and so we were able to see contribution from the whole lateral before it, and very little contribution after it. At plug, that was between, I think, plugs, stages 14 and 15, on a 17-stage frac. On the Weyerhaeuser Well, we were very encouraged in that we were seeing very high frac fluid rates, which were flat for a longer period of time. And it looked like, when we look back at the tracer, chemical tracer survey there, that it took a little longer to really realize what you had, and realize that you were losing flow from the back of your lateral, we just never saw -- usually on a well, and we were still only 5% of the load on the Weyerhaeuser when we saw it. But usually on a well, you see increasing contribution from the toe of your lateral to further out you produce the well. And in this case, we weren't seeing that at all, and then ultimately, you figure out kind of where we were -- what we were plugged up. So just a little different flowback. We were encouraged by the high frac fluids, obviously, and it is a little deeper than the other, some other wells. Although it's not the deepest well we've drilled. We have 3 or 4 other wells that have actually been drilled deeper than this well.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
And then, Rob, last one, if I could. Just on the CMR that's just now finishing up. Will you just, I guess, go ahead and drill out those plugs immediately, or based now on what's happened on the Huff, and there's Weyerhaeuser, what would you do different on the CMR as you come to the very end of the completion process?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, I think, as Gil mentioned, we did run the composite plugs. We will go ahead immediately and drill out those plugs, and it's a lower target well. And its history is any evidence that would give you high hopes that you ought to be able to get your plugs out, but you, and we just got to go ahead and do that. And Gil explained why we think the lower target maybe more susceptible to drilling out the frac plugs.
Operator
The next question is from the line of Phillips Johnston of Capital One.
Phillips Johnston - Capital One Securities, Inc., Research Division
Are you still planning for 40% of the shares wells to be drilled on your legacy acreage, and the rest on acreage you acquired from Devon? And just as a follow-up, are you still targeting a JV for your legacy acreage by the end of this year? And if so, what are the key hurdles that you need to meet before that happens?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, Phil, this is Gil. Yes, that is the current split in our budget and planning, would be 40-60. 60 on the acreage we acquired from Devon, 40 on the legacy. We certainly are interested in, and we've talked about pursuing a joint venture in the TMS during 2014. I think the trigger point, obviously, is we've got to resolve some of the operational issues that we've been out talking about and highlighting this morning. And to gain a little bit of momentum. So again, I don't think its something that's coming obviously immediately. I am-- would think that you might probably consider that more of a second half of the year item rather than a first half of the year item.
Phillips Johnston - Capital One Securities, Inc., Research Division
Okay, and you've talked about possibly selling some legacy gas properties this year. What's the current appetite for asset sales at the Board level, especially in light of stronger gas prices and what sort of proceeds could we expect to possibly see?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, we -- well, first of all, we have no immediate plans to divest any of our existing gas assets. We probably are a little bit contrarian and a little bit more constructive around longer-term natural gas. I think with the liquidity on the balance sheet that we have today, the first order of business is for us to overcome the current operational issues and better and further demonstrate TMS value to potential JV partners before we would consider selling any of the assets. That being said, we're going to see how we come out here at the end of the year, or end of the withdrawal seasonal on storage, and see where it kind of details on the strip prices, land and what that might mean. But we've always talked about our Minden-Beckville kind of legacy, Cotton Valley, being in the $75 million to $100 million range, depending on what this 5-year strip [indiscernible] would look like. And I would say that's still fairly reasonable range of expectation, if we were to move forward trying to sell that.
Phillips Johnston - Capital One Securities, Inc., Research Division
Okay. And just one more, if I could. In [indiscernible] , ramp back up to 2 rigs, now I think, are you participating in any other wells and do you know when we might get some of their well results? And also, do you know if they are using your well design and completion recipes on their wells that they're drilling?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Hi, Phil, it's Rob again. We've seen a schedule that has been running 2 rigs through the entirety of the year that, I think it has some drilling maybe 15 wells, 15 gross wells. We could have a small interest in a handful of wells, not quite sure yet, because there's some placeholders on there. It doesn't look like it doesn't going to be a material amount of wells, or a material interest that we would have in those wells. And we've also had discussions with them in the past about swapping acreage, if that's desired by both parties. So I think, right now, it's -- we've budgeted 5 gross, maybe 4 gross and 1 net well that we would participate, either with them or Sanchez or perhaps Comstock or -- obviously, other operators that are about to announce a position in the play, we feel. And we'll just have to see how that goes. But as we sit here right now, not any material interest with them. As to completion recipe, don't know for sure because, again, we're not in the wells that they're drilling, currently. But the last conversation we had with them was that they felt like our recipe was certainly working really well. If you remember the Anderson 17 #2, they pump basically the same recipe, and in essence, had the exact same well that we had on our Crosby Well about 35 miles away. So hate to dodge that one, we just don't have the information that's definitive.
Operator
The next question is from the line of David Heikkinen for Heikkinen Energy Advisors.
David Martin Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
Just wanted to get an idea of how many wells do you think you'll have drilled and producing before you add your fourth and then fifth rig? Just trying to coordinate schedule and time in the TMS.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Okay, this is Rob. We'll have, obviously, we'll have the Weyerhaeuser, the CMR 8-5 and the Blades and, that we're going to frac that well before too long after drilling the lateral. So I think we would expect another couple of months to get -- to go through before we make decisions. So call it 3 additional horizontal wells that we'll have results on.
David Martin Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
Yes, and with a couple of months of history, it'll tell you whether or not to spend the $75 million. That's helpful. And then liquidity's fine, and I was just running through, maybe adjusting our model. But as I looked at kind of, some of the trailing EBITDA start approaching around 4x, just with where first quarter is and then second quarter is H.ow does total debt level and kind of that factor into use of the revolver and kind of ability, are there any details around that? It's just not something we've talked about recently.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
And we tend to kind of put a hard line or certainly, a target of 50% usage on your revolver. It just feels comfortable that way. I think that's still kind of a soft line we draw there. Our modeling suggest even with the full 5-rig program, that we don't get to the 4 to 1, we've really not done that in the past. And it is -- and that is the metric that we focus on the most. But I think, as Gil said, by the end of this year, we would likely, at least start a process to bring in a JV partner or look at bringing in additional capital. Unlikely, it's equity obviously. So it becomes an asset sale or a JV, is the likely candidate. 2014 is fully covered. We just like to get out ahead of our 2015 plans. So we're continuing to accelerate in the TMS. And of course, if it's working as we hope for, the capital's not going to be an issue. If it's not, we're going to scale back a little bit and not spend the same amount of money.
Operator
The next question is from Brian Corales of Howard Weil.
Brian M. Corales - Howard Weil Incorporated, Research Division
Most of my questions have been answered. But was the only difference between the Crosby and the Weyerhaeuser the plugs used? Is that basically it?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
That's about right. We used the same frac recipe. We've -- have a similar lateral length, about 450 feet shorter on the Weyerhaeuser than the Crosby. But again, sufficient lateral length. Landed in the same target. It's about 3 miles south of those other Weyerhaeuser wells. And the only other differences is the frac plugs. And obviously, as I said earlier, we're kind of back to having to drill those out, or at least preferring to drill those out, because there's -- it's suggesting the plugs in. So that's about the difference. Gil, do you have any additional comments?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, Brian, this is Gil. We don't have 100% of the answers here. But what we suspect the difference between the drilling out of the composite plugs and the permanent frac plugs is that, when you're drilling out your composite plugs, you get the added benefit of sweeping and cleaning out your wellbore, so that any residual frac sand from any individual stage is able to be washed and swept out of the wellbore before you start flowback. What we are suspicious of, and think is a likely culprit of the 2 plugging problems we've had here recently, with the permanent plugs is, is that residual frac sand mixing with other debris, does not have the ability to get washed out. And while moving through 1 or 2 stages or plugs, I should say, is not a big issue. By the time you start moving that through 13, 14, 15, 20 stages, we suspect that some of that is just balling up on us and creating the plug in that we've seen both on the Huff and the Weyerhaeuser. So again, don't have 100% answer. But obviously, we can get in here and get all the plugs out in the Weyerhaeuser, that will certainly go a long way towards answering that question.
Brian M. Corales - Howard Weil Incorporated, Research Division
And then, just one final one. And so going forward in 2014, I mean, I going to say every well, but maybe almost all the wells will be drilled in the lower zone and with the composite plugs.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Certainly, the first part of that is correct, Brian. Current plan is that all the wells going forward will be drilled in the lower target, to try to get away from that higher clay content, which we think is contributing to the pipe deformation issues. I think that the current plant is to go back to the standard composite plan. It's composite plugs, we've certainly -- we and others across multiple plays, have drilled out hundreds, if not thousands of plugs that are composite plugs. We are drilling out currently permanent plugs. And so one of the options is that the permanent plugs, if we can drilled them out as easily and efficiently as we could a composite plug, then there really isn't much difference to cost. It's really essentially the same. And so we have the potential there. Maybe running some more permanent plugs with the plan, it'd be ready to drill them out. But I think near-term, given the hiccups we've had here, we certainly are going to be using composite plugs on the next few wells.
Operator
The next question is from Ron Mills of Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
A couple -- you touched on all the recent wells quite a bit. But if you look at the production charts that you updated for the conference this week, is there any difference in the way that you're filling the wells back, say, at Crosby and some of the Smith and your operated wells, versus how Encana's flowing back the 17 wells, whether it's pump placement or upgrade? And is that, how can that impact the production rates as we see in the slides?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, Ron, this is Rob. Artificial lift is obviously important in the liquids plays. And how you engineer and optimize your lifting is very important as to how you unload the wellbore. So there are some wells that we are -- have an interest in, that we don't operate that have pump depths too high, in our opinion, and fluid levels suggesting that the wells aren't pumping all. And the pumping units perhaps aren't big enough to lift the liquids in an efficient manner. And so there's a lot of give-and-take on analyzing the data and designing the size of your pumps, and how often you run the pumps, what types of pumps we use. The Crosby well, obviously, is -- when you look at those curves, it's clearly performing a lot better than the others. And we're -- we basically manage that and monitor it on a daily basis. We have that well. We continue to pump that well on jet pump, which we feel like is -- has been very efficient. And some of the other wells that have been on 18 months to 24 months, that we don't have an interest in, we feel like the pumps aren't properly placed at the proper depth, and are not functioning quite as efficiently as they should from a standpoint of how often you're running them. So we feel like -- and you'll see it when we show the new slide on the Devon wells, that pump optimization makes a huge difference when you size these things right and you run them correctly. So we would expect our wells and hopefully, that all wells that we participate in don't ultimately get the right optimization, which typically flattens curves, and in effect, unloads the wells, pumps off the well so that you're draining what's feeding into your wellbore more efficiently.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Okay. And then, as it relates to other industry activity, we've talked about 4, 5 other operators in 50 to 60 wells. If you started to receive AFEs from some of the other operators, or at least what can, become AFEs and just, I'm just trying to get a sense, in terms of relative timing, that some of these other operators that you're talking to, probably start ramping up to help accelerate that learning process.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Right. So the benefit of the TMS is that we're all sharing information. We're all meeting on best practices. We're sharing ideas. There is a very notable firm that we feel confident that's going to be in our area with rigs -- a rig or two before too long, who is very capable, very good at what they do. We have not received any AFEs, but we are exchanging general schedules as to where we think those wells are going to be drilled, and whether we would have an interest or not. And we're doing the same thing with them, where they may have an interest. So we would expect to certainly participate as an non-operated interest owner. But feel comfortable with our 4 gross, 1 net well estimate as we sit here right now, based on the information that we have. So that's why, I mentioned in my prepared remarks, you could have 5 operators drilling wells, not just drilling wells, but spreading wells around the area, which will help de-risk and delineate the play, and also create more consistent information flow, which will be hugely important.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And maybe, for Gil. The, I guess, casing deformation or whatever is being caused, whether it be by the clays or whatever. Is any of that related to the casing strength itself? Or is it really more a function of it occurring more, at least in your opinion, around the perforations where you've already perfed the casing?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, no, Ron. We've gone to a very high-strength casing. As you can go back to, remember, the issue we had on the Denkmann well, which raised a lot of questions. A very different situation there on the Denkmann and what we're talking here in with the pipe deformation. But we've been running, as have others in the play, very high-strength casing. I think we're up around 18,000, 19,000 pounds of both burst and collapse on our casing. So we don't think it's a casing strength issue. And we haven't seen any -- since the Denkmann, we haven't seen any ruptured pipe problems at all. It's really more just a little bit of slight deformation, which is creating a little bit of taking or changing in the placement of those plugs and making them difficult to drill out.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Okay. And just 2 more -- just a real quick one. The third rig comes in next month. That's roughly in line with what you expected last fall. If you do -- you end up with another 2 or 3 well results and move to the fourth and fifth rigs, how would you think, Rob, that you would kind of build from 3 to 5, or would it be gradual, or would it still be kind of by late summer or more just by year-end?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, we have pretty much said that if you stagger these rigs every 2 to 3 months, that would give you the ability to collect additional data as you go. Our goal here would be to not be running at full-speed, making similar or having similar issues. But build on your experience and ultimately, by the time you're at 4 or 5 rigs, you're, full cycle, you're running at full speed and you've developed the optimum drilling and completion practices. So we've said it, by the end of the year, but certainly, with good results short-term, you're going to see that happen a little bit quicker than that. So the third rig's coming first of March. Let's get a couple of months down the road, then we'll have those 3 data points that we mentioned earlier with David, and then make a decision on the fourth, and then continue to build from there. But I think it's likely with -- if everything works as we expect it to, or certainly hope for, then we'll have it by the beginning of the fourth quarter, you could see us with the fifth rig.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Okay. And then, just to confirm the -- you currently have a rig on location. I'm assuming it's a workover rig at Weyerhaeuser, drilling out the plugs and then, relative to the CMR timing, given that in the middle of its frac process. Are those 2, in terms of the timing at least, somewhat parallel?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Certainly similar in timing, I think Gil had mentioned, if all things go well, when you likely would have Weyerhaeuser results, kind of midway through the frac on the CMR, then we'll drill those frac plugs out. So certainly, and if -- within a reasonable period of time, if all things go as hoped for, we ought to have some results. And if it makes some sense to kind of group those wells, if they're going to be in similar timing, it makes some sense to kind of group them together.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And is the work-over rig -- is it a work-over or drilling rig?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
No, that's not a drilling rig. That's a work-over rig.
Operator
And the next question is from the line of Mike Kelly from Global Hunter.
Michael Kelly - Global Hunter Securities, LLC, Research Division
Just wanted to check in with you, real quick on how you stand in terms of lease expirations in 2014? And if you do decide to get a little bit less aggressive, maybe stick with 3 rigs for an extended period of time, before ramping to 5, are you in jeopardy of losing some acreage there?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes. Hi, Mike, Rob. 2014 is pretty well-planned out. It's really getting ahead of 2015 is what you need to accelerate for. I think, for us, we've already baked in our lease extension payments this year, within our $15 million budget. So that takes most of our acreage into -- and those are usually 2-year extensions. So I think, if we run 5 this year and things continue to work, and we run acreage next year, that would be the -- certainly the hope and the goal, then you ought to be able to get out ahead of the lease expiration issues. But 2014 is not really an issue. Now whether we have some fringe like acreage that's not of size, that is well out of the core, the area where we're drilling, you could see us, non-material way, let some tracks go, but we may add some tracks also instead of paying those extensions in areas where we're drilling wells and/or plan to drill wells. So I think that's -- we're going to just -- it's going to be fluid, but we don't see material change in the acreage. And if you really look at all of our extensions over the next couple of years, for $145 an acre, or $34 million, we can extend a big portion of our block.
Operator
The next question is from the line of Mike Scialla of Stifel.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
I guess, if I understand the frac or excuse me, the plug issue correctly, it's not so much in, a problem in the actual drilling up the plug part, as it is in, maybe getting the bit to the plugs. Is that the correct way to think about that, given the deformation that you're getting in the casing?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, that's exactly right. Well, for example, on the Huff, we never could get down to the plug and we kept, basically hitting on a ledge, which we feel like was some egging of the casing or slight deformation that basically kept us from getting to the plug. And so, it kind of falls back to Gil's commentary on upper target versus lower. If we're seeing that the deformation of casing, due to the rock characteristics when fracing and the basically, the earth moving on us, it's that irregular shape that's keeping us from getting to the plug more so than drilling the plug itself.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Given that, is there any way to know what the -- what kind of wellbore deformation you're dealing with in the Weyerhaeuser, versus the Huff at this point?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Well, there's really not, except for the fact that, one, we've started the process. And certainly, so far, don't appear to have deformation of casing. And we're also, kind of falling back on the fact that all the previous wells that have landed in the lower target had been able to get their plugs drilled out. So certainly optimistic. More so, than had we been in the upper targeted and experienced the well's results over the last few wells, that would have been of a little more concern. But no way of knowing at this point. Now when drilling it and when fracing it, and getting your plugs to set, all of that. Certainly, it went smoothly. So really, at this point, no reason to think that we have that issue. But until you get into the hole, you just have to speculate.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
And can you say how far you're into the process now with the Weyerhaeuser, in terms of days or how far you've gotten?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Well, we're just getting started. I think we've got a couple of plugs out of the way. But that's kind of where we are, at this point.
Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division
Okay. And then I think Gil mentioned in his prepared remarks, the potential to extend notes without, you've got the $51 million I guess in -- essentially in escrow. Can you elaborate on that at all?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Yes, Mike, this is Gil. I think a number of things. In that we have some questions here this morning about liquidity. We've extended the vast majority of those notes already. There is a remaining stub of $51 million. That's just a negotiation of what we're willing to give and what the holders would take in return. We won't try to handicap whether or not that'll happen or what the terms would be. But it is at least a possibility that, that $51 million is sitting there currently in a restricted account, and should we make a trade that's acceptable, we could drop another $51 million of cash into the liquidity basket. I don't think that you're going to see us do immediately. And I think we'll see how things play out over the next few months, and make a decision at that point in time. In addition, we've got gas assets. There was a question earlier about selling some gas assets. Certainly, Minden backhaul scenario in East Texas Cotton Valley that we've talked about. As I said that's -- we will not rule that out, it's something we might decide we want to divest ourselves of this calendar year. But I think right now, we're just going to see how the year in storage comes out here with the withdrawal season. And then, the real issue for us is just going ahead and knocking out these nagging frustrating operational issues in the TMS, and going ahead and demonstrating the value that we believe is there. And if we can do those things, then in the second half of the year, we think there's a lot of options opened up, to how we take an additional step towards enhanced liquidity for 2015.
Operator
The next question is from Ben Wyatt of Stephens.
Ben Wyatt - Stephens Inc., Research Division
Just a couple here for me. But just curious if results improve, you guys are happy and start the ramp to the fourth and fifth rig in the second half. Any risk or any worries that you won't be able to secure rigs? Meaning, is that market for the type of rigs you guys need, tightening up or anything like that?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, Ben, thanks for the question. This is Rob. there are rigs available. I would not say it's an abundance of rigs. But there are several that we're looking at that could fit our timing. We use a minimum 1,500-horsepower rig, like, even bigger than that, if we can get it. A lot of the rigs that have been sucked into the Permian, sometimes are smaller than that. So we do have, what we believe to be a nice specialty rig inventory from which to choose. But it's -- rates are similar to what we've been seeing, and there are, at least at this point in time, enough rigs to pick from to execute.
Ben Wyatt - Stephens Inc., Research Division
And then, maybe just one more. If we kind of think of the Eagle Ford and Haynesville asset base you guys have, is there any way you can kind of frame up what the production decline looks like on those assets right now?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Don't have that off in. I would encourage you to kind of look at our, certainly, our type curves in the Eagle Ford. I think, if you just looked at base run off, just kind of speaking from memory, but we may be looking at 20% or so of base run off. Obviously, didn't add much in the fourth quarter. But with a rig running now, we're going to drill all 9 gross, 6 net wells back to back, all but 3 pads each. So it ought to get up a nice slug of additional production, obviously, once that kicks in. The Haynesville is a little more post hyperbolic in that, we haven't drilled wells there, or that many wells there. But I would still use something similar. To that, call it, certainly 10% to 20% base run off, although we did add some recent wells from Chesapeake that they operate. And by the way, have no expectations to be participating with Chesapeake in 2014 on some of their Haynesville wells, at least we've been conveyed that our acreage is not on their drilling schedule.
Operator
The next question is from the line of Chad Mabry of MLV & Co.
Chad L. Mabry - MLV & Co LLC, Research Division
Just a quick follow-up to the last question on production. Curious if you could break out by plays, specifically on the oil side, TMS versus the Eagle Ford for Q4. And then maybe, if you could do the same, kind of what you're thinking there in the Q1 guidance by play, if you could?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, unfortunately, a little bit too much in the way for us right here today. We are filing our K, which will obviously give the yearly production, I believe, from each of those areas. And we're filing that, I believe, in the morning. Is that right?
Jan L. Schott - Chief Financial Officer, Principal Accounting Officer and Senior Vice President
Yes.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
For certainly, tomorrow. So that would probably give you some idea of where it is. I mean, I will tell you. Still, the vast majority, because of company wells we have producing, and the vast majority of production is still coming from the Eagle Ford. And you'll see that in a chart in the 10-K.
Jan L. Schott - Chief Financial Officer, Principal Accounting Officer and Senior Vice President
Something for the year.
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Now when you look at 2014, okay, so and there should be certainly something. It looks more like 80%, 20%, if you're going to take a, kind of a rough estimate. 80%, Eagle Ford. Now 2014, when you add the volumes, and with all the activity level in the TMS, obviously, you're getting a good bit more volumes in the TMS than what we have on a typical Eagle Ford well. And so we recognize the difficulty in modeling that out, and we'll give you better entitled guidance as we go over and above what we said for the first quarter.
Chad L. Mabry - MLV & Co LLC, Research Division
Okay, that's helpful. And then, just to clarify on the Eagle Ford. Should we assume then, or can we assume that the 2014 budget's kind of a maintenance CapEx level, in one of these slight declines in the Eagle Ford this year?
Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director
Yes, I think so. I think, once we put out a little more information over the next couple of months, we think, at $45 million, you're going to see flattish to slightly down perhaps, Eagle Ford volumes and obviously, get dramatic growth from the TMS, assuming we execute as planned. So I think that's as good as we can do right now at this point.
Operator
The next question is from the line of Pearce Hammond of Simmons.
Pearce W. Hammond - Simmons & Company International, Research Division
Yes, going back to earlier comments in the conference call. I think it was from your Chairman. Are you implying that there is more flexibility in your 2014 capital budget to do some gas drilling, especially in line of these higher gas prices? Or maybe put it another way, if you ended up, say, running 3 rigs in the TMS, instead of that 4 to 5, would you take that $75 million in savings to the Haynesville?
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Pearce, this is Gil. Absolutely. The comments were to demonstrate the great flexibility we have, we could move rigs, really to any of the core plays. If -- none of us know where gas prices are going to end up, but we can tell you hypothetically where the backs to start moving up, and you could start doing a $5 to $6 kind of hedge out in front of your self over a lengthy period of time, then all of a sudden, our Haynesville's going to start competing pretty solidly, and we would certainly look to blend that portfolio. I believe that's the comments that were being made. We also have a deep inventory in the Eagle Ford. And so we're not -- and we certainly have never viewed the company as a TMS company. We see it as a huge upside of potential. But we're still very much focused on the Eagle Ford, and have great flexibility to move very quickly into the Haynesville if that's something that makes sense.
Operator
Thank you, ladies and gentlemen, for your questions. We are now out of time. And I would now like to turn the call back to Mr. Gil Goodrich, Vice Chairman and Chief Executive Officer, for closing remarks.
Walter G. Goodrich - Non-Independent Executive Vice Chairman, Chief Executive Officer, Member of Executive Committee, Member of Hedging Committee and Member of Nominating & Corporate Governance Committee
Thank you very much. We know it's a bit of a frustrating report here. We are keenly aware of that. We're very focused on it. We're going to be working extremely diligently over the next few months, and we look forward to delivering very positive results to you at the next call. Thank you for your participation.
Operator
Thank you, ladies and gentlemen, for your participation in today's conference call. This concludes the presentation. You may now disconnect. Have a good day. Thank you.
SOURCE: http://seekingalpha.com/article/2036893-goodrich-petroleum-management-discusses-q4-2013-results-earnings-call-transcript?part=single