Goodrich Petroleum Corporation
Q2 2015 Earnings Call Transcript

Published: 5 Aug 2015

[Operator:]

Good morning, and welcome to the Goodrich Petroleum Corporation Second Quarter 2015 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Jan Schott Senior Vice President and Chief Financial Officer. Please go ahead.

[Jan Schott:]

Thank you Andrew. Good morning and welcome to our second quarter earnings conference call. I would like to begin with the introduction of the management team on the call with us this morning. Gil Goodrich, Chairman and Chief Executive Officer, Rob Turnham, President and Chief Operating Officer, Mark Ferchau, Executive Vice President of Engineering and Operations and Mike Killelea, Senior Vice President and General Counsel. 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. Finally, I'd like to remind everyone that we posted an updated slide presentation that we will reference throughout this conference call. You can access those slides through our Web site at www.goodrichpetroleum.com through the Investor Relations tab Events and Presentations section. Click on Goodrich Petroleum 2Q'15 Earnings Conference Call which will take you to the link the slide deck for the earnings presentations. Now I will turn the call over to Gil Goodrich, our Chairman and Chief Executive Officer.

[Gil Goodrich:]

Thanks, Jan. Good morning, everyone. As we announced last week we've entered into an definitive agreement to sell approximately 12,000 net acres and associated in wells in the Eagle Ford shale for $118 million. We expect the transaction to close in early September. This transaction does a number of important things for us during this difficult commodity price cycle. First, it allows us to retain the majority of our undeveloped acres for approximately 17,000 net acres for future developments or out write sale. We estimate the retained acreage has approximately 150 potential future locations. The $118 million also allowed us to pay off our RBL facility in full and retain the difference in cash on the balance sheet. The completion of the transaction will boost our liquidity, linked in our runway and provides incremental increased flexibility during this current commodity price environment. During the first half of the year we've worked diligently to reduce operating cost both in the field and at the corporate level. These efforts are beginning to show up in the quarterly financial results, with the exception of exploration expense each of our operating costs were lowered on an absolute basis versus the year-ago period by approximately 30% or more. The increase in the quarterly exploration expense was associated with the release of some non-core lease hold. As the releasing of previously held acreage is a non-cash charge approximately 93% of our second quarter exploration expense was non-cash. Going forward we expect to incur additional non-cash lease hold expense as we focus on retaining the 150,000 net acre core position in the TMS through renewals and extensions and allow a portion of our non-core un-delineated acreage particularly in the deeper part of the TMS to expire. We currently expect to exit 2015 and enter 2016 with approximately 250,000 net acres in the TMS. And now I'll turn it back over the Jan to review the financials with you.

[Jan Schott:]

Thank you Gil. I will now cover a few items on the financial side. Adjusted revenue which includes net cash received in settlement and derivative instruments for the second quarter totaled 37.3 million down from 15.2 million for the comparable period last year and consistent with 37.1 million for the first quarter of 2015. Our second quarter average realized prices were $57.23 per barrel for oil, and $1.86 per Mcf for natural gas. Including the impact of net cash received to settle derivatives the oil price was $86.49 per barrel for the quarter. For the balance of 2015 we have a total of 3,500 barrels of oil per day hedged at the blended price of 96.11. We plan to continue to monitor the current commodity price environment and layer on additional oil derivatives as warranted. We’ll also continue to watch natural gas pricing for opportunities to hedge portions of our natural gas production. Moving on to expenses. Operating expenses were down 19.9 million from the year quarter and 0.5 million lower than the first quarter 2015. Our cash operating cost for the second quarter were down 7.5 million from the prior year quarter and down 1.3 million from the first quarter. I will now review operating expenses and also provide a breakout of Eagle Ford Shale cost included in the second quarter expenses. LOE was 4.9 million compared to 4.1 million last quarter and 7.3 million for the prior year quarter. The second quarter included 0.6 million or $0.75 in workover costs. Second quarter LOE included Eagle Ford LOE of 1.9 million which includes 0.2 million in workovers or 1.7 million of LOE without workovers. Production and other taxes continue to trend lower as we add production from the TMS at a 0 severance tax rate. Production and other taxes of 1.4 million for the second quarter includes 0.5 million related to Eagle Ford. Transportation and processing of 1.6 million for the second quarter includes 1 million related to Eagle Ford. DD&A was 19 million or 25.06 per BOE for the quarter compared to 25.93 per BOE last quarter and 28.90 per BOE for the prior year quarter. We’ll reset DD&A rates for the last half of 2015 upon receipt of our mid-year reserve report. Exploration expense of 6.5 million for the quarter includes 6.1 million of non-cash lease amortization as mentioned by Gil mostly for expiring leases in our non-core TMS and Eagle Ford Shale Trend acreage. G&A cost came in at 6.5 million this quarter compared to 7.8 million last quarter and 9.5 million in the prior year quarter. This year we've reduced staff by 25%. About 1.9 million of the second quarter G&A represents non-cash stock-based compensation. We’re projecting a zero tax rate for 2015. We ended the quarter with 86 million drawn on our first lien credit facility and 0.3 million in cash on hand and or net borrowings at 85.7 million. The vast majority of our negative working capital underlined which increased our outstanding borrowings occurred in the first half of the year which is behind us. We plan to use net proceeds from the sale of Eagle Ford to pay down borrowings on revolver to zero as previously mentioned by Gil with the remaining cash on hand. The next redetermination of our borrowing base will occur in October 2015 with our mid-year reserve report. We've included reconciliations on the last pages of our press release for all non-U.S. GAAP measures to the closest U.S. GAAP measure. Please refer to these reconciliations for more detail. We plan to file our second quarter 2015 10-Q with the SEC this week. Please see our 10-Q for more detailed financial discussions. I will now turn it over to Rob to review operations.

[Rob Turnham:]

Thanks Jan. I will walk you through the earnings slides now concentrating on our assets. Although we've retained 17,000 net acres in the oil window of the Eagle Ford and over 30,000 net acres in Haynesville. I'll spend most of my time discussing results for the operations in the TMS. We have an extensive inventory of both oil and natural gas resource potentials and a team that is capable of exploring those assets. On Page 4 for our slide deck we show our year-end 2014 reserves. Our year-end 2014 reserves pro forma for the Eagle Ford sale and pro forma 3P resource potential. Our core property slide on Page 5, breaks up the gross and net acres in each of our four primary operating areas and again our pro forma approved reserves and 3P resource potential. Most investors these days focus on our oil inventory in the Eagle Ford and TMS but we retain tremendous upside and optionality in gas from our 30,000 net acre position in the Haynesville. We’re very encouraged by our early results from outside operators like our friends at Comstock in the Haynesville regarding refracts and longer laterals and we maintain the ability to flip the switch and allocate capital of Haynesville at a future date. But it is been several years since we last drilled the core Haynesville well as our acreage is held by production and the combination of longer laterals and higher profit concentrations providing from much higher production cash flow in EUR's and our average of EUR of 6.7 BCF through 4,600 foot laterals. Slide 6 and 7, deal with our Eagle Ford asset, we'll retain 17,000 net underdeveloped acres after the sale that wasn't associated with our crude reserves including a portion of the burns rent was released where we've been very active in the past. As Gil said, we are projecting our 150 growths, 102 net locations remaining from 6,900 feet true vertical depth or deeper. Focusing on the TMS beginning on Slide 8 we continue to see encouraging results on the play, both operated and non-operated. Our latest two wells reported the B-Nez 1 and 2 and Tangipahoa parish in Louisiana, and IPs of 875 BOE per day and were 99% oil which is the highest percentage of oil we've seen today. Most of the other wells have been in the 92% to 96% range. The restricted shell flowback and lower gas component likely led to the lower IP than the direct offsets being the Blades, Verberne and Williams wells. Both wells treated very well when stimulated and we expect we'll perform similarly and respond well to artificial lift like the other area three wells which I'll show you in a second. On Page 9, we show the top 15 IP wells to date with the top well peaking at 1,900 BOE per day and the average for the 15 wells at approximately 1,500 BOE per day. Obviously what matters more is how that the wells perform over time but it certainly shows how prolific the wells can be especially considering the oil cut is higher than another shell basins. We now have 32 optimized wells spotted on Slide 10 which we have broken out into four areas so that we can better show actual daily production for each of the wells. 150,000 net acre position is shown within the red halo as areas one, two and three. We show Area four, but don’t call it core as the wells are quite as good as the other three areas, although they will likely generate reasonable rates of return and higher oil prices. The current identified core area isn't necessarily the only area that could be core in the future as we are just mapping the best wells growth to date that were adequately stimulated. The green circles on the map are the wells which we will be completing by the fourth quarter. Through data sharing agreement and experience we've identified certain optimized criteria that we believe creates better well results as shown on Page 11. We now have 32 optimized wells that meet our criteria area which is landing in the better quality rock in the lower section of the TMS. Have sufficient lateral links with hybrid frac designs and profit concentration of at least 1,500 pounds per foot. Many of the recent wells that have outperformed have had longer laterals and proppant concentrations in excess of 2000 pounds per foot and both variables have very good co-relations to EUR projections. Even though you could see some minor variability, rock characteristics from sub-surface log and core data suggest only subtle differences within the identified areas, therefore the completion recipe in our mine is extremely important. Slide 2 shows area of one well versus our 600,000, 700,000 and 800,000 BOE type curves. The Crosby well has been the signature well for the play that it has been online now for over 24 months and is produced well over 200,000 BOE in that period. In addition certain well come online over the last 11 months including our CMR/Foster Creek 31, which is shown in light blue, that are tracked well above our Crosby well and the 800,000 BOE type curve. Slide 13 shows Area 2, which has several of the top producing wells drilled to-date including the 1,900 BOE per day well mentioned earlier. Many of the wells in this area are materially outperforming our 800,000 BOE type curve in their 12 months period and are positively affected by longer laterals and higher proppant concentrations per foot. Although we see the benefit in longer laterals, there is an added cost, and our results in Area 3, as shown on Slide 14, are outstanding from shorter laterals. Area 3 wells have typically had lower gas rates than the other two core areas. Our Blades, Verberne and Williams wells continued to top outright performers, B top outright performers and the Blades well, which is completed with a 5,000-foot lateral, continues to be our top producer per lateral foot. All three wells have reacted very well to artificial lift when and we plan on putting wells on artificial lift sooner in the future in this area such as the B-Nez wells to maximize early time performance and shift the curves even higher. Again we think the benefits for artificial lift in this area more pronounced due to less gas in the production stream which accelerates liquid loading. Area 4 on Slide 15, although not currently identified as core, continues to provide upside potential, as the Beech Grove and SLC's are performing prime but need significantly higher oil prices or sharply lower well cost to justify additional capital allocation. Slide 16, we show all 32 wells compared to our type curves and you can see the newer wells are outperforming as completion methodology has been optimized. Well cost in the TMS has come down dramatically from 13 million to 10.5 million on our latest well even though we drilled it in a higher cost environment, to a current estimate using recent bids up 10 million per single well and 9.3 million per two well pads. In development mode where we can drill four or more wells on the single pad we expect well cost to be below 9 million. Well cost have dropped considerably due to reduced drilling days from 40 to 24 and reduced service cost in particular on the completion side. When you average those wells into our composite curve as shown on Slide 18, we’re producing above our 700,000 BOE curve, and would expect this curve to increase over time as the newer out performing wells continue to flow through the curve. When you bake in the lower royalty burdens of 17.4% higher price realization from LLS which is a premium to WTI or no severance taxes until payout you can generate sufficient rates of return at $55 oil. That said we’re still in this price environment for a period the time we'd expect service cost and completed well cost to continue to come down. Factor all of this in with our recent well cost on Slide 19, and we generated attractive rates of return at reasonable well prices which will compare well with many of the more active oil basins as we pass. We also calculate breakeven well economics which we define as PV10 at $44 per barrel our mid case curve. We've also included our drilling inventory slide on Page 20 to show you the effect of the Eagle Ford Shale proved reserve and associated acreage sale which obviously impacts our production and cash flow going forward but has very little impact on our inventory. In summary as we've stated before we've always been in early mover in place whether we were drilling in Cotton Valley horizontals, Haynesville, Eagle Ford or TMS wells. It plays to our technical strength and we like we see in the TMS as well as we did in each of other plays that are now proven. With that said we and senior management have been in the business for over 30 years, 20 of those years of being public and we've seen and been through several downturns. We recognized the necessity to play defense to conserve capital and as Gil said linked in with liquidity run rate. The sale of our proved reserves and associated acreage strengthens our hands in that regards. By time and what time we expect an improvement in the macro environment which will lead to better sustainable commodity prices. Predicting when that will happen certainty is impossible and therefore we’ll manage the business conservatively yet maintaining our core acreage positions in each of the basins for exploitation at the appropriate time in commodity cycle. In the mean time we’re focused on taking a disciplined approach to our capital plans and reducing our cost both in the field with lower CapEx and operating expenses as well as our G&A. With that I'll turn it back to Andrew for Q&A.

[Operator:]

We’ll now begin a question-and-answer session. [Operator Instructions]. The first question comes from Leo Mariani of RBC. Please go ahead.

[Leo Mariani:]

I was hoping elaborate a little bit more on the last comment that you guys made about waiting for a better commodity price environment before getting little bit more aggressive here. You talked about bringing the rig back some time later next year, is there kind of rough target oil environment we need to see? Or is it closer to 60 versus 46 we’re looking at, there is any color you add that would be helpful. A - Gil Goodrich I'll take that, Leo this is Gil. I think that we currently are unhedged in 2016 on the oil and we certainly like to have some hedges in place. I think that Rob just showed you in the IRR chart, we’re starting to getting to $60, $65 a barrel we think at this cost we can start generating some pretty attractive rates of return. We would like to be in an environment where we can hedge into that, we’ll certainly there 30 days ago, and I think we'll just be patient over the next few months to watch opportunities as Jan said to layer in some hedges and be prepared whether it's late this year or early next year to bring rig back and let the oil market dictate a little bit of timing.

[Leo Mariani:]

And I guess additionally you guys talked about delaying some of the completion from 3Q into 4Q and waiting for better oil price similar line of questioning there in terms of getting those two wells online is that definitely going to happen, 4Q where we need to see the price recover a little bit from here?

[Gil Goodrich:]

I think we’re prepared to go forward with that, Leo, it could be late 3Q early 4Q but we still plan to finish completing all those wells before the end of the year.

[Leo Mariani:]

And can you give us little more color on the restricted choke program on the B-Nez wells in terms of what choke size is you guys are using on those wells?

[Rob Turnham:]

I'll pick that up, this is Rob. We’ve been flooring our well, we start on a 10/64 choke most of the early flow back is on a 12/64 choke it's not a whole lot dissimilar to many of the wells of late in particular in Area 3, but we think it's obviously prudent to not pull these wells too hard and as I said in the prepared remarks, we think the lack of gas in this particular incidence perhaps suppress the IP a little bit, but we know we got all of the stages fully stimulated, we know the oil is flowing at a good rate and just feels like in this case in particular in -- with the fact being that we had a little bit less gas, we ought to be conservative in early time flow back. And then obviously monitor when we start to see some loading and we’ll run the jet pump artificially lift those wells. But it's interesting that's the highest percentage or lowest percentage of gas, highest percentage of well that we’ve seen to date even though it's an adjacent to the Williams, Verberne and Blades. That being said those wells were really higher well cuts also probably in 96% to 97% range.

[Leo Mariani:]

I guess just question on G&A here, obviously it's kind of come down just noticing your cash G&A over the last couple of quarters you guys have made some reductions. Is there further room for that G&A to come down later this year and into 2016 or should we think about second quarter is kind of more of a run rate?

[Gil Goodrich:]

Leo this is Gil, I think that you should think about that as a run rate for the balance of this year, but we obviously are watching the markets very, very carefully and I have a liquidity in situation very, very carefully every day and we’re prepared to do whatever we need to do to strengthen the company. So for the time being we’re in good shape, but can always little bit lower if we have to.

[Operator:]

The next question comes from Neal Dingmann of SunTrust. Please go ahead.

[Neal Dingmann:]

Question first on just re-frac you hit on that, what’s potential to go back on some of those maybe just to address little bit on re-frac potential?

[Gil Goodrich:]

Extremely high potential in that all of those wells were under stimulated, we were probably pumping a 1,000 to 1,200 pounds per foot back in four, five, six years ago. So clearly they have been under stimulated and therefore we can go back into those wells and re-frac we’ve seen in the commentary just this morning from Comstock but from others where they've taken 0.5 million a day after 3 million a day on the re-fracs and it's a great opportunity for us at the appropriate time to go back and give that a try. We’ve held off to-date just because we wanted to see more production history from those wells but what we’ve seen so far is certainly interesting and compelling. And then the longer laterals so clearly the way they go and our laterals were 4,600 feet previously. So you combine that with the small amounts of profit and you still get 6 to 7 Bcf a well. So we see -- we’ve seen some EUR so that’s coming from other operators and we can’t argue with their estimates and therefore we’ve got a quite a bit of upside potential here relative to that. And if you just look at North Louisiana, Haynesville for example, we show over half of Tcf of 3p resource potential actually probable and possible resource potential of 566 Bcfe and that’s just using the 6 Bcf per well and 4,600 foot lateral. So in essence you're cutting half your drilling locations and more than double that based on what other operators are saying. So there is plenty of upside potential if we just want to do that in North Louisiana. We didn’t talk about in the prepared remarks our ACLCO well and the Angelina River trend that's extremely up exciting also and that we basically not seen hardly any decline only lost about 400 pounds of pressure to 10,750 pounds over a five-year period with very little drop in our production rate also. So lot of running room there as well and that’s a short lateral also. So plenty of upside on our gas assets and optionality which just held off just due to where gas prices have been.

[Neal Dingmann:]

Rob and then just one follow-up, just you mentioned gets very evident about the lower cost about being able to do on -- if you were able to do the two well pads your thoughts now I know there is maybe some concern about holding acreage and going to that. What’s your thoughts about in ’16 be able to do some of that versus holding acreage?

[Rob Turnham:]

Clearly and cost of things improve on the commodity cycles first if you could accelerate development again we likely bring in a partner to help us. We had two entities that were very close to doing a JV with us right before oil prices tank we think we’re going to have even more interest once the oil prices recover this time because we've eliminated lot of the operational issues, we've shown more prolific wells more repeatable results. So if we bring in additional capital then you could immediately move to spending more money on leasehold extensions and drilling more two and even four well pads, but as we sit here right now in absence of bringing in a partner we think we can spend $15 million maybe $20 million continuing to renew and extend leases keep your drilling activity to a minimum maintain your 150,000 acre position plus probably another 50,000 acres and exit 2016 with 200,000. So really depends Neil on just capital how much you want to spend renewing leases. You can always increase your leasehold budget and then go ahead and drill four well pads and not drill as much. So there is plenty of flexibility there we’ll just have to see where commodity prices are as we enter '16.

[Operator:]

The next question comes from Brian Corales of Howard Weil. Please go ahead.

[Brian Corales:]

Rob you kind of just hit on one of my questions about 2016. If you are guessing if the strips fair today I would assume you'd spend very little capital, was that fair assessment?

[Rob Turnham:]

Yes, Brian with one exception if the gas market and the tangible wealth continue to look as good as they are we could reallocate capital into the Haynesville as well as generating good rates of return but as we sit here right now we would say we’re going to continue to play decent, keep our budget to a minimum, we’re going to spend the money on leasehold retention just because we feel it's important to maintain the core as we come out of this, and we’ll come out of this at some point in time as an industry. So hard to budget right now. We've kind of guided 100 just keep the same budget forward looking just to give you some idea, but frankly for in a $50 environment I think we’ll tend to spend less money and more than the same amount much less more money.

[Brian Corales:]

And if you are choosing between Eagle Ford, TMS to spend some capital for your drilling program, I mean is it still TMS at this point or can you maybe elaborate there?

[Rob Turnham:]

Brian, as you know where we’re our rate of return now that well costs have come down in the TMS are very similar to what we see in the Eagle Ford. Our Eagle Ford acreage has on average about four years of remaining term on the acreage. So we've got some time there. The Burns Ranch component is subject to a continuous development provision but you don't have to drill any wells there. And so probably April to June of next year. So that’s assuming no one else drills on the Burns Ranch. So I think as long as we can maintain that block in the Eagle Ford and achieve similar rates of return in the TMS and capture acreage while we go, then we’re going to tend to allocate more capital to the TMS.

[Operator:]

The next question comes from Christopher Shook of Imperial Capital. Please go ahead.

[Christopher Shook:]

With the slightly cheaper area fees in the core Area 3, I was just wondering if you could sort of give any color going into 2016, so whether you intend to drill and complete more wells in the third area as opposed to the second and first.

[Rob Turnham:]

Certainly that would be our tendency because we have probably a little more pressure on retaining acreage in Area 3, and those well results kind of in the Blades area are certainly encouraging and it does drill pretty fast in that area. We seem to be able to knock those wells out pretty quickly. So I think the likelihood we haven't established that budget obviously as we just said for 2016 yet, but I think the likelihood would be a greater percentage of our activity remains in Area 3, and occasionally you are going to see us drill in Areas 1 and 2, the Crosby lease for example in a mid and Wilkinson County, we have some extra time on that lease although you'll continue to see us drill in the Crosby area routinely. So plenty of time left on most of our Area 1 and 2 leases, and if anything more pressure on Area 3 in those levers have been similar to what we’re seeing in the other areas. That some point Chris we’re going to move towards longer laterals and obviously in excess of 2,000 pounds per foot because we’re really seeing very good and probably better results when you do extend those laterals just like in Canada has done up in Area 2 in particular.

[Operator:]

The next question comes from David Snow of Energy Equities. Please go ahead.

[David Snow:]

It's probably a little early but in the latest two wells -- I guess you don’t have much history or EUR read but given what you know plus the offsets what kind of an EUR do you think those might have?

[Rob Turnham:]

Yes. David if you look back on our Slides for Area 3 for example we are very much encouraged by the performance on these artificial lift, on these wells on artificial lift and no reason to think that these wells which treated really well of late can perform very similarly to what we've seen before. So we think the higher liquid component in Area 3 in the lower gas component in Area 3 just basically tells you let's go ahead and put those wells on artificial lift little centered enough and results that really show that’s the basically Slide 14 of our deck. Our strategy is to go, get pump initially and then once the wells get pulled down and now we convert that for rod pump and those were long-term rod pumps, very efficiently produce these miles.

[David Snow:]

Any thought is to what best guess to EUR on the 200,000 acres that you hold will end up being? It looks like it might be 24 to 800 but lastly reach out it was at least 700 -- what do you think it might be now?

[Rob Turnham:]

Yes. David I mean if you look at it from composite curve that’s giving us our best guess as we're combining all 32 wells and coming up from the composite curve and that shown on Page 18, you can see early time production through the first 10 months we basically are up above the curve and….

[David Snow:]

700 isn't that?

[Rob Turnham:]

Yes above the 700,000 composite curve and as these newer wells continue to flow through the curve we think that’s going to likely pick that curve higher because those wells are performing in excess of 800,000 barrel curve. So I think over time you know it's a mix bag of lateral links and proppant concentrations but I think what we can tell you that’s the recipe certainly seems to be -- the wells seem to be consistent or more consistent when you put the exact same recipe on the -- and certainly the wells had been much better producing wells for the most part of because of the longer laterals and higher proppant concentration.

[David Snow:]

And then just last, do you have any guesses to what the relinquishment charge might be if you drop the remaining acres of 125 or whatever it is would be dropped?

[Rob Turnham:]

We don’t know that our average price per acre that we paid was about $245 per acre. It just depends on overtime as to how much we choose to let go -- I'll take you to where you could kind of take long-term approach and say at the end of this year we are at 250,000 net acres that means you know, we would have 50,000 net acres basically released or not renewed and then another 50,000 acres by the end of '16. It's kind of vary by quarter depending on when those leases were originally taken but that’s basically how we accounted for as we write the acreage off through expiration that’s how it's calculated.

[Operator:]

Our next question comes from Owen Douglas of Baird. Please go ahead.

[Owen Douglas:]

Just a couple of quick ones -- I'm thinking about your ASE causes at Eagle Ford, which areas do you think you might have a bit of room for improvement just you go by having conversation as your various service areas out there. Where do you think that we can make some improvements on that $10 million well cost?

[Rob Turnham:]

Owen again this Rob, good question and you know certainly the B-Nez too the lightest well at 10.5 million was in the Area 3 in Tangipahoa Parish and we certainly have achieved quicker drill times in that area. It seems to go very smoothly. The well's also in line seem to produce with less down time and we don’t know what's driving that other than seems to be a little less maybe not as much of the what we call ruble zone affecting your drilling operations. So I think and that’s again where probably more than half of our activity will be forward looking in 2016 would be in that same Area, so I think if we can get to a point where we can drill two to four wells pads and we're constantly looking at how we might swap acreage with other operators in the play and get to point where you can maximize use and reduce cost by drilling multiple wells off of ne pad, I think that’s likely this area that we would continue to see the lower and lower well cost. I think it's going to happen across the play no matter where you are, but for some reason we are able to drill in that area pretty quickly.

[Owen Douglas:]

And in terms of the components the cost, it sounds like you guys think that the most improvement come from quicker spuds release date say, is that correct or are you also seeing any potential improvements on just sort of labor cost?

[Rob Turnham:]

Yes, that again if you look back on Slide 17, we kind of lay out where the cost savings primarily come from. I think certainly we ought to be able at the more we do of this and in particular the more wells of an existing pad. The quicker the drilling will go and for every day you say it's about $100,000 of savings which is what we call our spread rays. So two to four well pads and knocking-off drilling days certainly can add up on the cost savings. As to common facility you get some economies of scale there. One pad obviously helps a lot versus individual pads and in the frac cost have -- that’s where we’ve seen the biggest decrease in cost for the well, it's just been better stimulation cost and that’s going to be a product that where commodity prices are and what the demand for their equipment is. So I think it's going -- it's likely going to be a combination reduce -- further reducing drilling days economies of scale and the pad and the equipment and then we’ll see where completion cost go.

[Owen Douglas:]

And follow-up question for me, just in terms of thinking about funding that development of this TMS area, what sort of options you think appear to be the most likely for you going forward?

[Rob Turnham:]

Yes, what we’ve had discussion with others about previously was much more of a traditional joint venture in which someone comes in and it's more of a cash and drilling carry per mode. There is also quite a bit of circling private equity has expressed an interest before and we think once the oil prices recover that could be a buyable option as well and how you structure those deals will kind of depend on the entity that you're talking to, but more of a structured finance where you keep. With more of the upside that probably have interest or dividend components to the financing, that’s where we were when oil prices were high and we expect to be right back in that same position once we recover here.

[Owen Douglas:]

And final question for me, just as -- have you guys been able to get any clarity or indications in terms of what availability or the borrowing base could look like in the second half of the year?

[Rob Turnham:]

Well, we’re still finishing up our mid-year reserve report; we need to do that over the next couple of weeks and then hand it to our bank. They then take a while to analyze the report and get a consensus on what they think the borrowing base will be. So no, it's just way early on that, but it was a driving force behind why we decided to go ahead and monetize the proved reserves and associated acreage in the Eagle Ford, it takes the banks and takes them to zero, put some cash on the balance sheet very low cash drain from here to the end of the year. So that the borrowing base becomes a little less important and just you start gone on it.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Rob Turnham, President and Chief Operating Officer for any closing remarks.

[Rob Turnham:]

Thanks Andrew and thanks to everyone who participated on the call. We appreciate your continued interest in Goodrich Petroleum. Good bye.

[Operator:]

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.