Petroquest Energy's CEO Discusses Q2 2013 Results - Earnings Call Transcript

| About: PetroQuest Energy (PQ)
This article is now exclusive for PRO subscribers.

Petroquest Energy, Inc. (NYSE:PQ) Q2 2013 Earnings Call August 6, 2013 9:30 AM ET

Executives

Matt Quantz - Manager, Investor Relations

Charles Goodson - Chairman, CEO and President

Todd Zehnder - COO

Bond Clement - EVP, CFO and Treasurer

Analysts

Ron Mills - Johnson Rice

Joseph Allman - JPMorgan

Will Green - Stephens

Tim Rezvan - Sterne, Agee

Richard Tullis - Capital One Southcoast

Andrew Coleman - Raymond James

Kerr Friedman - Simmons & Company

Operator

Good morning, and welcome to the PetroQuest second quarter 2013 earnings conference call. (Operator Instructions) I would now like to turn the conference over to Mr. Matt Quantz, Manager of Investor Relations. Please go ahead.

Matt Quantz

Thank you. Good morning, everyone. We would like to welcome you to our second quarter conference call and webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO and President; Todd Zehnder, COO; and Bond Clement, CFO.

As you've come to expect, we would like to make our Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest business, which are not historical facts are forward-looking statements that involve risk and uncertainties. For a discussion of such risks and uncertainties which could cause actual results to differ from those contained in the forward-looking statements, see Risk Factors in our annual and quarterly SEC filings, and in our forward-looking statements in our press release. We assume no obligation to update our forward-looking statements.

Please also note that on today's call, we will be referring to non-GAAP financial measures, including discretionary cash flow. Historical non-GAAP financial measures are reconciled to the most directly comparable GAAP measures in our press release included in our Form 8-K filed with the SEC today.

With that, Charlie will get us started with an overview of the quarter.

Charles Goodson

Good morning. During the second quarter, we produced 8.7 Bcfe or approximately 95 million cubic feet of gas equivalent per day. The 95 million cubic feet equivalent per day was comprised of approximately 74 million cubic feet of gas, 1,270 barrels of oil and 2,300 barrels of NGLs. Our second quarter 2013 average daily natural gas liquids production increased 65% over the comparable 2012 period and was a seventh consecutive quarter of total company production growth.

The recently completed Gulf of Mexico acquisition, plus our ramping up production in other areas of the Gulf Coast, Woodford and Cotton Valley assure us that we will add to this consecutive quarter growth.

Revenues for the quarter were $38 million, with product price realizations averaging $104 per barrel of oil and $3.01 per Mcf of gas. NGL product price realizations were negatively impacted by the continued deterioration in butane and pentane prices, and averaged approximately $28 per barrel. For the second quarter net income available to common stockholders totaled approximately $4 million or $0.06 per share.

With all that said, these number do not include any contribution from our recently announced acquisition, and we look forward to reporting third quarter numbers that will include the anticipated increase in oil production. As a result, we are expecting our blended realizations to be significantly stronger going forward than the $4.39 per Mcfe reported for the second quarter.

Now some details on the acquired properties. On July 3, we closed our shallow water Gulf of Mexico acquisition. This transaction substantially alters our production profile from both a product mix and overall rate standpoint.

For next year, our oil and NGL production is projected to increase 33% and 61% respectively, compared to 2013. In addition, our total production is expected to grow 20%-plus, as we accelerate our Woodford and Cotton Valley programs to record levels, while maintaining our discipline capital allocation relative to Gulf Coast assets.

With our shift to a more oil-weighted production stream, we are forecasting a big jump in our future cash flows. We have begun to layer in oil hedges to protect the anticipated cash flow, and as we sit here today, approximately 40% or 14% of our estimated oil production is hedged for the remainder of 2013 and 2014, respectively.

Our projected cash flow is expected to be more than sufficient to fund our 2013 and 2014 capital programs, and we believe that we will be able to drive down our debt-to-EBITDA from three times currently to our internal goal of two times by the end of 2014. This transaction is highly accretive and we're excited about integrating these assets into our legacy Gulf Coast portfolio where we have consistently been able to generate new opportunities and have achieved a 70% success rate over the last nine years.

With that I'll turn it over to Todd, to go over operations.

Todd Zehnder

Thank you, Charlie. Good morning, everybody. Starting with Gulf of Mexico, we have modified production on one of the wells that we recently acquired in our West Delta 89 field. As a result of that operation, we are able to increase the gross daily production from this well by approximately 550 barrels.

It's really important to note that there was essentially no cost with this procedure as we just opened up one choke size. This will be a common theme during the development of these assets, as you'll see over the coming months.

In total, we're forecasting only $1.6 million of additional capital needed to potentially realize the full 3P value of $278 million that was originally calculated using average prices of [$92.32] [ph] per barrel and $4.37 per Mcf of gas.

Looking forward, during August, we have several new projects that are expected to increase current production from the newly acquired assets. First will be two well at Ship Shoal 238 that have already been completed and are awaiting a pipeline interconnect.

The pipeline is expected to be online within the next week or so and we project that these two wells will add approximately 500 barrels of oil net per day and approximately 600 Mcf of gas additionally. This is in addition to the acquired assets run rate that we currently are experiencing of approximately 1,300 barrels of oil and 18 million cubic feet of gas per day.

After that, there will be two recompletions at West Delta 89, which are projected to add another 300 barrels of oil per day and additionally 6 million cubic feet of gas per day net. So basically in total over the next few weeks we expect to bring on additional 800 barrels of oil and 6 million cubic feet of gas net, which by our estimate should increase total daily net production from the acquired properties to approximately 2,100 barrels of oil and 24 million cubic feet of gas per day.

Now, moving on to our legacy Gulf Coast assets. Our third well at La Cantera, the Broussard Estates number three was recently brought online and is currently flowing at approximately 28 million cubic feet of gas, 540 barrels of oil and 660 barrels (audio gap) both the three wells at La Cantera flowing at a combined rate of approximately 102 million cubic feet of gas, 2,000 barrels of oil and 2,400 barrels of natural gas liquids.

In addition, our mid-stream partners thoroughly upgrading its processing plant, and the latest estimates for this work is to be completed sometime in November. At that time, we expect our NGL recoveries from La Cantera to significantly improve, which will be accretive to the numbers that I just cited.

Moving on, our Thunder Bayou project is proceeding as planned. We recently completed our evaluation of the 3D data and are diligently working on drilling and development plans at this time. The unitization hearing is scheduled to occur this month to finalize the Thunder Bayou drilling unit. Our latest estimates call for us having between 35% and 45% working interest and its high impact prospect, which will be a significant increase in ownership versus our La Cantera working interest, as you'll remember.

In addition to Thunder Bayou, our 74 square mile 3D shoot has identified several new potential prospects in this mini-basin. We're continuing to work on these targets and expect that several will be added to our expanding Gulf Coast inventory list and ultimately next years drilling schedule.

In addition to our La Cantera and Thunder Bayou projects, we have two liquids-focused projects later for the remainder of the year. First our, Tokay prospect located in Ship Shoal 72 where we've achieved 96% drilling success over previous 13 years, is expected to spud in September and exposes up to approximately 2.5 million barrel equivalent.

Next would be our Sawgrass prospect, which is about 2 million barrel equivalent target and is expected to spud sometime in October. We have approximately 35% working interest in this well, which will be located in Terrebonne Parish.

Moving on to our resource trend. In the Woodford, we recently reached total depth on two wells in our Horse field. This prize is expected to be completed in approximately three weeks, which will be the last of our dry gas activity for the foreseeable future, as our recently acquired liquids-rich acreage is now ready for development.

We're in the process of mobilizing our rig in bay area currently. In addition, we expect our second and third rig to arrive in early fourth quarter of 2013 and first quarter of 2014 respectively, as we significantly are accelerating this program next year.

In total, we expect to drill approximately 50 gross wells next year compared to 16 gross well count for this year. With our active leasing campaign this year, we have increased our total liquid acreage by 17,000 net JV acres and currently have over 20,000 net JV acres in this section of the trend. We will continue to be active here on the leasing front, as this area of the trend generates rates of return in north of 80% in the current commodity price environment.

Moving on to our East Taxes, where our PQ number 9 horizontal Cotton Valley well continues its strong performance. The 4,200 foot lateral, 100% working interest well established a 24 hour max rate of 6.3 million cubic feet of gas per day and 458 barrels of NGL in early April. Today, over four months later, the well is flowing at approximately 5.3 million cubic feet of gas per day and 382 barrels of NGL.

Our internal EUR estimate of PQ number 9 is approximately 1.1 million barrels of oil equivalent as of June 30. Its results like these that have us excited about running a constant rig in this trend, which should help us capture some economies, scale and drilling efficiencies as we've seen in the Woodford.

We plan to reinitiate our program during the fourth quarter and are projecting to drill approximately eight to 10 wells in 2014, of which half are estimated to be at 100% working interest wells and the other half being 50% working interest wells. Assuming 10 wells are drilled that would have equate to about 7.5 net wells, which would then have the same impact, had we drilled 15 gross, 50% working interest wells.

Quickly touching on the Mississippi line, we recently received our 3D seismic data from Kay County shoot and have begun the evaluation process of this newly acquired data. In addition, we expect to commence the Pawnee 3D site from shooting approximately two months. We will use both of these data sets in conjunction with historical wells result in production to determine our development plan for 2014.

At this time, I'd like to turn it over to Bond.

Bond Clement

Thanks Todd. During the quarter, our LOE totaled $8.8 million or about $1.02 per Mcfe. Maintenance and repair costs were below expectations during the second quarter, which contributed to our lower than expected cost. Additionally we were able to establish permanent power at several well sites in both the Eagle Ford and the Miss Lime, which resulted in a decrease in rental compressors and generators and related fuel costs.

For the third quarter, even with the inclusion of our newly acquired Gulf of Mexico assets, we expect LOE per Mcfe to approximate our historical norms. We'll point out our third quarter LOE guidance does not, however, consider potential cost synergies or economies of scale, as we integrate our new assets.

G&A cost for the second quarter totaled $6.4 million and included about $1.2 million of non-cash stock comp cost. G&A cost also included about $1 million of transaction cost related to our Gulf of Mexico acquisition. We expect to incur additional $2.5 million of transaction cost during the third quarter, the majority of which has led to the commitment fee that we paid on the bridge financing put in place to backstop our acquisition.

Interest expense during the quarter totaled $3.1 million. We capitalized $1.3 million of interest during the quarter. So in total, interest costs were $4.4 million. As you saw the release this morning, we have increased the guidance relative to the interest expense going forward to reflect our recently issued $200 million in 10% notes.

Looking at the balance sheet, during the quarter we invested $22 million in CapEx. The breakdown of this capital is about $13 million of direct CapEx; $5 million of leasing and seismic; and about $4.4 million of capitalized overhead and interest. From a funding perspective, discretionary cash flow during the quarter totaled about $19.8 million.

As we noted earlier, the impact of the Gulf of Mexico acquisition should be evident in next quarter's cash flow numbers. Now, we're not giving guidance here, I'm just doing the math of the guidance that we've given out for the third quarter. But if you take the midpoint of our third quarter production in cost guidance and just utilizing realizations from the second quarter, our cash flow would be approximately 40% higher than our reported second quarter cash flow $20 million.

While this alone is a significant increase, it only includes a partial quarter of production from the ongoing work at Ship Shoal 238 and West Delta 89, that Todd highlighted, just a bit ago.

From a liquidity perspective, our bank group recently increased the borrowing base from $150 million to $200 million, to reflect our newly acquired assets, with only $65 million drawn in a fully-funded budget for 2013 and '14 our liquidity position is stronger today than before our Gulf of Mexico acquisition.

Looking at production guidance for the upcoming quarter, we currently plan to produce between 117 million and 125 million cubic equivalent per day, assuming the midpoint of our guidance, this represents a 27% increase in total production over the second quarter. More importantly though, our average daily oil production is forecasted to increase from 1,270 barrels to over 2,800 barrels per day, which is the main contributor to our growing cash flow profile.

Our production mix in the third quarter is forecasted to be 75% gas, 14% oil and 11% NGLs. However, our revenue is expected to be more than 50% derived from oil production for the upcoming quarter. For 2014, our plans continue to call between producing 125 million and 140 million cubic feet equivalent per day, of which 70% is expected to be gas, 13% oil and 17% NGLs versus the second quarter production mix of 78% gas, 8% oil and 14% NGLs.

On the hedging front, we currently have about 172,000 barrels of oil, 6.9 Bcf of our remaining 2013 production hedged, the oil contracts we've in place are having average floor of $101.73 per barrel. The gas contracts have an average floor of $3.63 per Mcf. For '14, we have about 164,000 barrels hedged and 3.6 Bcf of gas, at an average floor of $94.86 per barrel and $4.08 per Mcf of gas respectively. We will continue to look for opportunistic points to layer in additional hedges as we always have, especially relative to our 2014 oil production.

With that, we'll turn it back to Charlie.

Charles Goodson

Thank you. As we look at over the next couple of years, we believe that we'll remember the second quarter of 2013, as one of the most significant turning points in this company's history. We internally see with clarity, how these properties that fit perfectly with existing Gulf of Mexico operations, and a rolling cash flow, with virtually no development cost, will be catalyst to change our rate of growth, while staying within cash flow. We now look forward to our articulating this to the market through performance.

Comparing our second quarter production numbers to third quarter guidance, you can already see the positive impact that this acquisition is having on our company. In just three months period our average daily oil production is expected to more than double from 1,271 barrels per day to approximately 2,800 barrels per day.

With next year's guidance at almost 3,000 barrels per day for the full year, you can see that there is significant upside to our current cash flow profile. We believe that there will be significant shareholder value created, as this cash flow is converted from guidance to reported results.

With that, we'll now open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from Ron Mills with Johnson Rice.

Ron Mills - Johnson Rice

Couple of questions, one maybe for you Todd. On La Cantera, when you talk about the processing upgrade and increased NGL recoveries, what kind of impact can that have on the NGL recoveries versus current recovery rates?

Todd Zehnder

It really, it's varying by product, Ron. But I think maybe a general statement is you can see an uplift of probably 40% when the plant is fully expanded. Probably most important is you'll see the heavier go from, where we currently are running maybe 60% to 70% recovery, it should get back up to near a 100% of recovery. Just because we have that plant with the three new wells, we have that plant more than maxed out. And so we're just not getting the recovery that we want or that the plant wants to deliver.

So it's a hard answer to just generally say 30% across the board. I think maybe offline we can give you a little bit more detail by product, if you'd like, but the real value comes from the pentanes and the butanes going up to near a 100% recovery from the 60% that we're seeing right now.

Ron Mills - Johnson Rice

And then, on the oil guidance, Bond, for the second half of this year, the guidance was more oily I think than I may have expected. Is there anything driving that or because I know the oil growth is coming in as expected on the Gulf of Mexico acquisition or was I just too gassy before?

Bond Clement

Hard to say, Ron, I'm not looking at your numbers previously. But as you know, we haven't changed our full year guidance in terms of the mix of our product. It's a function of us giving the third quarter guidance out, with maybe some earlier than expected timing relative to bringing on additional oil from the acquired assets.

Ron Mills - Johnson Rice

Then two quick ones on the other stuff. It sounds like in the Woodford you added about 5,000 additional acres since your last update, and what does that do for your current drilling inventory? And what rig count would that be based on in the liquids at Woodford?

Todd Zehnder

We're assuming that we're going to drill about 50 wells next year, and we're still toggling with how many exact rigs that's going to take and maybe a combination of three, probably three for the majority of the year. We're more focused about number of wells at this point than we are rigs. And it's a playing through from a mantra of efficiencies with the rig that we have running. So based on 50 wells, which is our internal estimate for next year, where we stand right now, we've got roughly four years of inventory at that pace.

And I can tell you that, when we come back to you guys in November, on our third quarter call, we'll have more acreage, because we are continuing to pick up acreage. We've been working on this project for about eight or nine months now, and we're kind of coming around the final turn, I would say, from the number of acres that we're going to pickup. But it's going to continue to add and we'll have a nice solid inventory out there for several years.

Operator

Our next question comes from Joseph Allman with JPMorgan.

Joseph Allman - JPMorgan

So my first question is on recompletions. These two recompletions, you mention in the press release, are bringing on about 11 million a day combined, if I'm calculating correctly, because your acquisition production has gone from 26 million a day equivalent to 37 million a day equivalent. And so that would be in average of about 5.5 million a day for each recompletion. So how many recompletions do you have in the inventory with these new properties? And what are the costs per recompletion? Todd I think you said $1.6 million total. And what's the timing of the recompletions? I know it's probably hard to figure out. And what kind of production increase can you get combined from these recompletions?

Todd Zehnder

I'm going to try to answer all those in one answer, but correct me if I didn't get them all. I think first of all, let me focus on the actual rate increases, which are including and there is the two recompletions that we have slated for West Delta 89 as well as two new wells that have just been waiting on final hookup.

The pipeline is connected. We're really just waiting on [inaudible] final approval at this point. So the rate that the 11 million equivalent, I think that you’re citing, that actually comes from four wells. Two wells at Ship Shoal 238 that are virgin wells, new production just waiting to get turned on, and then the two wells at West Delta 89. Those are the uphole recompletions.

The timing of those is what, slickline in the field tomorrow, which is Wednesday. I believe one of the two wells will immediately get recompleted at that point. And we will evaluate and do a little diagnostic work, as one of the wells appears to probably still have some reserve that we can sweep out of an existing zone.

And so we're going back in and assessing whether we can go ahead and turn it back to production, just based on pressure data. We think we will. So we'll have those two wells producing from either, one, from an existing zone, and two, from an uphole recompletion or both from uphole recompletions. And that will happen within the next call it week or two weeks, by the time the production is actually flowing.

The actual cost per job, we're not talking about much here, we're talking sliding sleeves. These wells are all set up with a sliding sleeve, existing gravel packs already done, while rig was on location. So it's a pretty insignificant amount of money, I cited a number that's $1.6 million in total net recompletion capital. And most of that money is allocated to West Delta 89. In the five well, there is probably 15 additional recompletions over the life. And so it's pretty routine type downhole work that unless something happens we're not forecasting. It's just a slickline type job.

Joseph Allman - JPMorgan

Todd, what's the timing of those 15 recompletions?

Todd Zehnder

It all depends. I mean we're hoping that each producing zone last longer than our 1P. I mean if you remember when we acquired these reserves and it is very akin to what you've seen out of us over the last 13 years at Ship Shoal 72. We have proved reserves book and that may tell you that you a recompletion coming in the first quarter of 2014. But if that zone outproduces its 1P and gets into the 3P, which we clearly expect, it will dictate the timing of the uphole recompletion.

So they're going to be spread out over time, Joe. And I don't a pure recompletion schedule in front of me. We have a reserve report estimate, but that will all be based off of 1P numbers. I can just tell you that the two that are scheduled are currently within this quarter.

Joseph Allman - JPMorgan

It appears that your current production from the acquired properties is the same, as when you brought the properties. I know it's just over a month ago, but you also added 550 barrels a day from a recompletion. Is that recompletion just offset the natural declines?

Todd Zehnder

Well, first of all, the 550 is a gross number. And what you're seeing is our oil rate is up probably 100 to 200 barrels from when we acquire the properties, on a current run rate. And so we're citing a daily production number, I can tell you it's growing right now. The gas is off a little bit just due to one of the fields, I wouldn't even call it a really natural decline, we had a pipeline shut-in on a downstream and we had to get it back on line, and we're just now starting to see full rate again. But you know, these wells are so new, we're not in really a natural decline stage just yet. And like I said, you'll see that rate jump up to 2,100 barrels here pretty soon.

Joseph Allman - JPMorgan

And separate question, what's the impact on G&A of the Gulf of Mexico acquisition?

Bond Clement

In total Joe, we're forecasting about $3.5 million of transaction cost for the year. We recorded $1 million in the second quarter, so we're forecasting it $2.5 million in the third quarter.

Charles Goodson

And if you're asking from a more of an integrated and run rate type number, what it'd be going to look like, it's pretty insignificant just because these fields are brought into an existing asset base, where we're not having to add a whole bunch of people. We're bringing on a couple of technical folks to just help exploit the asset, but I would clearly say the impact is going to be negligible.

Joseph Allman - JPMorgan

And Bond, when is that $2.5 million come in?

Bond Clement

Third quarter.

Joseph Allman - JPMorgan

And then, Todd, on the two prospects, Tokay and Sawgrass, what's the chance of success for those?

Todd Zehnder

I think those are about 65% to 75% chance of success by the wells. One in Tokay, being in Ship Shoal, it's got seven different horizons, most of the field is paid in a lot of these different sand. So I feel very comfortable, we're going to have a very economical well out there.

We saw that prospects, it's old Hollywood production in Terrebonne field, where we as a company have had many successes over time and feel really good about the prospect. We have had in inventory for a little while now and just have had to work through some permitting issues and so froth. So looking forward to getting both of those drilled.

Operator

Our next question comes from Will Green with Stephens.

Will Green - Stephens

I want to first get started on the JV, sorry if I missed it in prepared remarks, but what's the balance of that kind of I guess JV fund right now. And then can you talk about the timeframe of which that gets spent, and then what the Woodford looks like beyond that?

Todd Zehnder

Well, at the end of the quarter we've got ballpark $55 million or so left under to carry. And by our estimates, with the 50 wells that we'll drill in '14, in addition to the remaining drilling we had this year, we're projecting the drill carried in last right around until the end of next year.

Will Green - Stephens

I mean, if the asset base look similar to where it is now, would you guys look to shift some of that Woodford capital towards say East Texas or Gulf of Mexico? I know there's probably a lot of variables involved there.

Todd Zehnder

You're right on the last part. There's a lot of variables involved in that process. But I think what you'll see is consistent with what we've said over time, we're going to allocate capital to the highest rate of return type activity. And we take in the consideration of repeatability and a host of other factors that go into it to say, where the capital allocation will be for '15, it's probably a little premature. Obviously, one of the biggest factors of what's going to drive that is going to be gas prices.

Will Green - Stephens

And then another one, can you guys talk maybe a little bit more color around Thunder Bayou, you have the drilling process. I mean, what kind of net pay are we looking at here? I mean, any kind of additional color would be great, if you guys have any?

Charles Goodson

It's truly come out, since we haven't drilled the well yet and talking about that type of stuff, let's say, it's analogous to La Cantera, its just north of that, looking for the same zones, where we had up to 450 feet of bay. We're hoping some of those same lower Chris Sands will pay. And step one is to get the well drilled. And that will start before the end of the year.

Will Green - Stephens

And then any help on gas differentials. In the third quarter, I know you guys obviously have a meaningful contract rolling off, now that you've got a little bit of third quarter behind you, is there any help you guys could give us on third quarter differentials there?

Todd Zehnder

I think, Will, at this point it looks like we're going to stay. You would keep your historical differentials for the third quarter rolling from the second quarter. I don't see much changing in our areas of activity. Obviously, most of the Woodford is tied to Henry Hub with the big basis adjustment that rolled off in October, so I think fourth quarter you'll start to see some change. And as it relates to East Texas and our legacy Golf Coast assets, I don't see much change going forward.

Operator

Our next question comes from Tim Rezvan with Sterne, Agee.

Tim Rezvan - Sterne, Agee

Just had a couple quick ones for you. First on production guidance, if we're using midpoint of what you've said for the third quarter, and then the midpoint of full year, it looks like you're guiding implicitly to flattish fourth quarter production. Would you say that's more conservatism based on the newly acquired assets or is there something that's going to be shut in. How should we think about production into yearend?

Bond Clement

Tim, I'd say, we don't have any real shut-in forecast, but we do have some limited amount of hurricane risking in both the third and fourth quarter, but I would just say, we are getting our hands around the assets through an integration process and you're trying to compare the two midpoints of two ranges to come up with your thesis that production guidance will stay really flat. Let's just, let's rollout third quarter and see where fourth quarter flushes washes out.

Todd Zehnder

And I think just to add something to that. You'll see a lot of our activity that's ramping up for the second half of the year, it's going to have an impact of our production later this year and into 2014, specifically when you have a rig work, and our first rig that's going to be going into the liquids-rich area is going to be drilling a five-well pad, if I remember correctly. So you're going to have that impact really coming on later in the year and additionally most of the things that we have, aren't going to be driving much near-term production but you should have a great run rate towards the end of the year.

Tim Rezvan - Sterne, Agee

That's a Woodford five-well pad you're going to start drilling?

Todd Zehnder

I think its five wells. Call back on that, but I'm pretty sure, it's either a five or six well pad.

Tim Rezvan - Sterne, Agee

And then just to confirm as you ramp to three rigs next year in the Woodford, do those rigs, will they be able to drill Miss Lime wells, if you want to revert them?

Todd Zehnder

Yeah, we could actually. We're going to a smaller rig than we've used in the past for our Woodford drilling because on the western side of the trend, in the liquids area, it's a shallower part of the trend. And so that's one of the reason why we had a slight delay with getting a rig that was more fit to purpose for the western side and based on the results that we see, once we have the 3D data and that would probably be about the right size rig to have go drill Mississippi Lime well if we chose.

Tim Rezvan - Sterne, Agee

And then this one maybe for, Bond, with the new debt that you have, does that have similar call provision as the old debt?

Bond Clement

Yes, the new notes are virtually identical to the old notes, so same call provision, same covenant package et cetera.

Tim Rezvan - Sterne, Agee

And is the call, is it 2014 when you'd have the option to call those?

Bond Clement

September 2014 is the first call, that's correct.

Tim Rezvan - Sterne, Agee

And then just one last one, I am trying to get little more detail on the Thunder Bayou. I know you have some unitization issues to work out, when you say end of fourth quarter can you give in more specificity on when you hope or when you think you might be able to start drilling? And then would that be more of first quarter '13 or maybe even with your first quarter earnings report, when we might hear results?

Todd Zehnder

Our internal, call it, estimate at this point at beginning of November spud date, and that's depended on unitization permit and then ultimately rig availability or just overall service community availability, which at this point we think at early November timeline should be achievable. With that timing, I would then call it mid-first quarter, we ought to have well results on that. So I am not when it will exactly be, depending on when we spud and how the operation goes, it could be around our yearend earnings call, first call or somewhere around there, but obviously a lot of things are up in the air on that right now.

Operator

The next question comes from Richard Tullis of Capital One Southcoast.

Richard Tullis - Capital One Southcoast

Todd, jumping over to the upcoming exploration wells planned, what's the estimated cost to drilling complete, say, Sawgrass, Tokay and Thunder Bayou.

Todd Zehnder

Tokay, in the most near term from an 8.8 drill cost that will be probably about $7 million from a gross basis to drill, and then if successful you would have about $3 million completion. We will be tied in our existing Ship Shoal 32 facilities. So there is not too much incremental facilities cost. From Bayou, the cost standpoint the drilling cost there is roughly $5 million. That one with success would have a facilities cost and that we will have a longer pipeline to lay. I think all in, that project will have success capital of somewhere in the $9 million to $10 million range, of which we have a third or 40% of that.

And then the bigger one obviously will be Thunder Bayou. We're still working towards a full prog on that, but I think just roughly, what you can say is, it's on land, that's going to be cheaper in La Cantera. We would assume that we will probably have a similar type program to our three La Cantera well, which had so much success, so just the ballpark scoping at this point $18 million on the dry hole cost at this point.

Richard Tullis - Capital One Southcoast

And then those are predominantly targeting liquids, correct?

Todd Zehnder

Well, Tokay is clearly targeting primarily oil. The Sawgrass prospect is a mixture of gas, NGLs and condensate. It's typical Hollywood productions very rich gas with a good condensate cut. Thunder Bayou being deeper is going to have hopefully a very similar production profile to our La Cantera, which is, I guess, a high grade problem to have with that much gas coming out of that, but deep you're going to expect to have a pretty good gas cut as well, but you can see the three well at La Cantera producing 2,000 barrel oil a day, but it's altogether $100 million cubic feet of gas plus NGL.

Richard Tullis - Capital One Southcoast

What sort of rate of return can you generate, say, with the type of reserve estimates you've provided in the well cost? And what sort of ranges are you looking at on using current commodities?

Todd Zehnder

I think these type projects, Richard, if you look at them on a risk basis, which we do everything on a risk basis, you're going to be looking anywhere from 50% to 100% rate of return. Obviously, we have to do that, because you're going to have some geological risk that comes along with that. On an unrisk basis, most of the things in the Gulf Coast, if you well know, are going to generate 100% plus rate of return, if you find your stated objective or your most likely reserve.

Richard Tullis - Capital One Southcoast

And then, one of your other Gulf of Mexico peers, recently had some subsalt success. How do you guys, view that play on your acreage?

Bond Clement

Here it's not been our primary focus, but we are watching what others are doing. In Ship Shoal, we have some subsalt opportunities and/or we're mining some data out there right now. It's nothing that we've allocated significant man power or capital to it at this point, but we've continuously monitor what other's success in the area are and hope that some point down the road we can make a play out of it.

Operator

Our next question comes from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James

Looking at the Woodford and Cotton Valley, now that you're starting that program in East Texas again and kind of adding small rigs to the Woodford. Do you have any plans to change the completion styles in both and I guess could you talk about the shorter laterals on the Woodford, but can you tell, I guess, refresh our memory, what kind of fracs you're pumping for those wells?

Todd Zehnder

First of all, it's not shorter lateral; it's a shallower area on the western side. So our standard well depending on how the well is pooled and if it's just a conventional section, is plus or minus about 5,000 feet. And in the Woodford, it is weak. We really don't want to change what we're doing from a completion procedure. We have modified our completions on the western side of the trend to account for a shallower and lower frac gradient and lower reservoir pressure.

So what we've done is we've backed off on the amount of water and our cluster spacing and so forth. We've done some things there. But as far as changing the frac procedures or propane used or we're a slick water frac over there. We're not going to jail. It's a pretty routine plain-vanilla type frac if you will. And we've got a very good, I would say, success rate with the rest of our guys up there have developed. We're always tinkering with things like I've mentioned on percentage of propane versus water, and horsepower need and we will continue to do that.

In the Cotton Valley, no changes, but one thing we are seeing in the Cotton Valley, is there is a lot of operators drilling Cotton Valley wells right now. So we are always looking to others in our areas specifically and best practices and learning from that. But at this point, we don't have any plans to change and want to get us slick water fracs over there. Everything is done, conventional perf and plug, we don't use (standard plugs) or those type of systems on these types of frac jobs.

Andrew Coleman - Raymond James

And if you could also elaborate a little bit more this time, like you'll see, is that a condensate or NGL yield or gallons per Mcf that you're seeing in those plays as how they might compare to some of the other liquids plays that have been involved over the last couple of years?

Todd Zehnder

Yes. We can give you probably more detailed after the call, Andrew. But in general, our Woodford program generates about 60 barrels per million of NGLs across the board. It is the latest estimate. Now, obviously, we've expanded our footprint over there and we can give you some more detail on what our expectations are. We're using wells throughout the basins. We've created maps and our assumptions.

And in the Cotton Valley, those wells typically on a horizontal well that comes all on making 5 million to 8 million a day, would generate probably about 30 to 40 barrels of condensate, just pure condensate. And then from a NGL recovery standpoint, I think we're in the 55 barrels per million range. Matt can give you a little more detail on that after the call. But the composition in East Texas is heavier barrel, which you'll remember. We've got a pretty decent natural gas and oil cutout there, which brings the value of the barrel up also there.

Andrew Coleman - Raymond James

And last question I had is you all have made a lot of change in last few years to bump up the onshore component as a portfolio. And clearly you've got some great cash flows coming from the offshore piece you've acquired. It looks like you're about fifty-fifty, onshore, offshore right now? Is that about accurate? And I guess how you see that moving forward as you step up this accelerated 2014 plan?

Todd Zehnder

Yes. I think production has a probably pretty good estimate, we're somewhere close to fifty-fifty. And I think what you'll see is, we have a very easily forecasted growth rate coming from the Woodford and East Texas, where we have less predictability is the success that we can have in the Gulf Coast. And the prime example is La Cantera because I feel net it is producing close to 20 million a day and if we're sitting here two years ago looking out, we weren't able to put that type of production ramp.

So when you have well like Thunder Bayou, Tokay, Sawgrass and the myriad of other prospects that we have out there, it's harder for us to give accurate and defendable, I guess, production guidance. But I think that you'll see us continue to try to generate more profit and more production coming from the Gulf Coast, simply to capture more of the oil production than we're able to bond them.

It has clearly been our best basin for drilling oil and that's one of the main reasons we come down here in a, I guess, the more accelerated manner, is to keep the oil to gas balance more in line. So we are less looking at the allocation of the production throughout the various basins and more focused on how can we get more of the $100 of commodity in our book volume.

Operator

Our next question comes from Kerr Friedman with Simmons & Company.

Kerr Friedman - Simmons & Company

I guess, taking first 2014 production. You're drilling pure gross wells in Cotton Valley, with the same net wells. So I'm trying to think how that comes online in 2014, if the productions comes online little bit earlier than your prior guidance implied, than is that fully offset by your pad drilling and the Woodford coming out a little bit later or does that perhaps a little bit of upper bias on 2014 production estimates?

Bond Clement

As we sit here today, we're comfortable with our 2014 production guidance, irrespective of if the gross well counts have changed, the net well counts we think are consistent with our previous guidance. And really from an operational perspective, you're going to have programs going on simultaneously in both the Woodford and the Cotton Valley, so we're comfortable with our '14 guidance, as we sit here today.

Kerr Friedman - Simmons & Company

And then, kind of, shifting over to the Miss. Is there any capital currently been allocated for your '14 budget to the Mississippian? And if the seismic data has come back positive, should we be expecting your '14 CapEx budget to potentially increase or should be you looking for more of a reallocation of capital?

Todd Zehnder

We would find the reallocation of the capital at this point. Our CapEx budget isn't firmly set in stone, but it's probably a pretty good estimate, and we've got some wide room on how we allocate capital throughout the region. But in general, I think that if it does more add some additional activity, it will clearly either increase CapEx or will reallocate if it generates the better rate of return in another area, we'll find the money for it.

Kerr Friedman - Simmons & Company

And then last one from me. Thinking about your four year inventory in the Woodford, I'm curious what's basic assumption that implies and is there any doubt biased to the basic assumptions eventually?

Todd Zehnder

What is concerning is four wells per section and I would say that we have tested five wells and have seen success in that, but we're not ready to say five wells per section is going to work everywhere. So I think when we put the four wells per section, it either gives us some more for unique spacing that we would go or a unique pooling that we would do in the shale reservoir development act, which maybe a longer lateral or it may just taken into consideration that some sections only need four or three because of faulting. But in general, we are very comfortable on that estimated spacing throughout the basin.

Operator

This concludes our question-and-answer session. I would now like to turn the conference back over to Matt Quantz for any closing remarks.

Matt Quantz

Thank you, everybody for their time this morning and please call if you have any additional questions.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!