W&T Offshore Inc (WTI) 2013 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore fourth-quarter earnings conference call.

(Operator Instructions)

This conference is being recorded today, March 7, 2014. I would now like to turn the conference over to Mark Brewer, Manager of Investor Relations. Please go ahead, sir.

Thank you operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results of the fourth quarter and full year 2013. Before I turn the call over to Management, I have a few items that I'd like to point out.

If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to be Investor Relations section of the Company's website at www.wtoffshore.com or via recorded replay until March 14. To use the replay feature, call (303) 590-3030 and dial the passcode 4665733#.

Information recorded on this call speaks only as of today, March 7, 2014, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our fourth-quarter 2013 earnings release for a disclosure on forward-looking statements. At this time I would like to turn the call over to Tracy Krohn, W&T's Chairman and CEO.

Thanks, Mark. Morning, everyone. Thanks for joining us this morning on our fourth-quarter call. With me today is Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer.

Yesterday we released our financial operating results and news release, so this morning we'll review some of the key items before we take your questions. 2013 was a dynamic year, marked by very significant exploration and development success, the acquisition of a prolific oil field in the deepwater, and further realization of the substantial potential of our acreage in west Texas.

Talk a little bit about growth strategy. We're on a path to create more multi-year projects that gives us better visibility into future production and reserve additions. Our exploration success last year in the deepwater and the deep shelf, and in West Texas, is the foundation of a multi-year development project that we will add value for years to come with.

Let's talk a little bit about onshore. Our sizeable position with approximately 26,000 net acres in West Texas Midland Basin is in the heart of one of the most attractive plays in the US. We were an early player in the northern portion of this basin, and established a contiguous acreage position that's well-suited for multi-zone developments. For each bench, think about adding another 26,000 acres, effectively.

Offset operators are having good results in the Wolfcamp A, B, D, and Sprayberry, and we have all of those benches in our acreage. We approach this piece -- this field evaluation very carefully. The majority of our leasehold is now held by production as a result of our vertical drilling program.

Meanwhile, we're taking advantage of and benefiting from the high level of industry drilling activity that is now surrounding our field. We, along with offset and nearby operators, are announcing significant well results across multiple stack targets.

Earlier this week, we provided an update on our first operated Wolfcamp B well in our Yellow Rose Field, the Chablis 9H, and we now see 24-hour production rate of 549 barrels of oil equivalent per day, of which approximately 73% is crude oil. The well was completed with an effective lateral length of 5,905 feet.

That was in 22 stages using a hybrid frac treatment. If we normalize these results to a 7,500-foot lateral link, this equates to a rate of about 697 barrels of oil equivalent per day.

We're pleased with the results of the well, and we'll continue to analyze our operations to determine the optimum drilling and completion techniques as we move forward. We believe we may be in the core of a highly prolific Wolfcamp Sprayberry play, and have an acreage position that could support hundreds of vertical -- excuse me, horizontal locations in multiple horizons.

Talk a little bit about offshore. Our increased focus on participating in high-end pack deepwater projects is yielding some superb results. Adding to our Big Bend discovery in late 2012, we had two successful discoveries nearby, Troubadour and Dantzler.

Those will contribute reserves and production in future years. These projects take a big up-front CapEx commitment, but they can pay huge dividends later on, as well as provide the visibility into sustained growth profiles.

Over the past few years, the last few years, our Mahogany field remains a highlight of our growth discussion. This field just keeps getting bigger and bigger with each new well drilled.

We're enthusiastic about how this field has grown and developed into a long-term program, with eight productive horizons discovered so far, many successful wells in place, and more to come. We've concentrated a lot of manpower and capital on this field, with engineers and geoscientists working to understand the full potential of this prolific sub-salt play.

In 2010 we developed a reservoir stimulation model to determine the most optimal future development plan for the Mahogany field, and we've subsequently drilled seven highly successful wells, not including the A-15 that's currently drilling. As a result, production grew substantially from an average of about 1,509 barrels of oil equivalent per day in 2011 to current production of about 10,000 barrels of oil equivalent per day. We believe the field has a great deal more to offer, so we're in the process of obtaining new wide-azimuth 3D seismic, or WAS, over the field to provide even more clarity of the long-term potential of Mahogany.

We're also working to identify more multi-year projects like Mahogany, and to accomplish this we're paying new WAS seismic data over some of our other fields in the Gulf of Mexico. As one of the largest holders of acreage on the shelf, we believe if we could identify and develop additional prospects or potentially discover additional productive horizons, that could deliver multi-well long-term opportunities for wells on our existing acreage.

Our acquisition strategy has always supported the longer-term focus, as we generally target the acquisitions at fields with additional exploration or development potential. Others talk about it. We've been doing it that way for nearly 30 years.

Our acquisition of Callon's Gulf of Mexico assets is a perfect example. Medusa field is offering numerous identified drilling opportunities, and the potential to provide multi-well and multi-year reserve and production additions.

Organic reserve additions; let's talk a little bit about organic growth. Even as we continue to shift to a longer-term plan throughout 2013, we're able to replace 100% of our production and maintain steady proved reserve volumes ending with 2013 year-end proved reserves of 117.7 million barrels oil equivalent. Most of our reserve additions came from organic activity, with extension discoveries of proved reserves and 20.1 million barrels of oil equivalent for 2013.

Exploration drilling resulted in eight of nine projects being successful commercial wells. Development drilling was 100% productive, with all 37 wells drilled named successful.

As we've continued to expand our onshore and deepwater presence, we've seen our forward-looking, three-year depletion rate for our proved reserves drop from upwards of 52% to around 39%. This equates to a longer-term reserve life profile, and supports our strategic efforts to provide better long-term visibility for the market.

Exploration discoveries were made offshore on the conventional shelf at our Ship Shoal 349 Mahogany field, and at our Main Pass 108 field. In the deepwater Gulf of Mexico we had reserve additions from the Mississippi Canyon 698 Big Bend, but we booked less than a quarter of that reserve because we believe ultimately we'll recover from our interest in that discovery.

We think that it's prudent to wait until we get the field on line before we book any more of those. We haven't booked any reserves for Dantzler or Mississippi Canyon 699 Troubadour.

Onshore we've had substantial reserve additions from our Yellow Rose field, with proved reserves associated with our interest increasing from 31.6 million barrels oil equivalent at year-end 2012 to 38.2 million barrels oil equivalent at year-end 2013. Our planned continuation of the exploration program should contribute new proved reserves in 2014.

We've booked 2.1 million barrels of oil equivalent of proved reserves for acquisition of Callon's Gulf of Mexico assets, with the focal point of the group being the Medusa field. It's a very prolific deepwater oil field that's currently producing about 6,300 barrels of oil equivalent per day gross or, 945 barrels of oil equivalent per day net to our 15% working interest.

With that, I'll turn it over to Jamie.

Thank you, Tracy. Total production for the fourth quarter of 2013, volumes were up 14.4% over the fourth quarter of 2012 to an average of 56,100 barrels of oil equivalent per day. Production volumes were split 35% oil, 11% natural gas liquids, and 54% natural gas.

Production for the year was up 5%. We have been able to drive our oil reserves 5% higher, and oil production 16.3% higher over last year. Our 2014 capital program will continue to focus on oil projects which are driven by current economics.

Revenues in the fourth quarter were $244.9 million, up 3.3% over the fourth quarter of last year, primarily due to higher oil production. Reserves for the full-year 2013 were $984 million, an increase of 12.5% over 2012, due to higher oil production and higher natural gas prices.

For the year, adjusted EBITDA was almost $600 million, an increase of over 10% compared to 2012. Net cash provided by operating activities for 2013 were $561.4 million, an increase of 45.8% over 2012. Of course this would have been higher if we hadn't had unusually high levels of deferred production.

We also incurred an anomalous high level of workover cost in 2013. We had two very expensive rig workovers, with one being at Main Pass 69, and the other one in our Mahogany field on the A-12 well.

Those two projects cover -- the cost of those two projects were over $30 million. Both of these wells were casing-pressure issues. We do very few workovers with drilling rigs, so 2013 was highly unusual in both the work and the cost.

After operating in the Gulf of Mexico for over 30 years, we have a solid track record for excellence, and are continuously looking at ways to perform even better. As we've previously reported, we are currently working closely with governmental agencies to address two issues we initially received in November. Regarding the BOEM notice concerning potential increases in our supplemental bonding requirement, we were granted a stay until April 15, 2014, to facilitate ongoing negotiations, which we have said are in progress.

We are also continuing to actively work with the EPA regarding their notices of proposed debarment relating to the environmental violations that occurred in 2009. At this time we do not have any updates to report. We take very seriously our responsibility to operate safely, properly, and reliably.

That is demonstrated every day on every project. As a result of this focused and continuous effort by our team members, this past year we were awarded the Special Marine Safety Award from American Equity Underwriters for having the best safety record from among more than 200 other members in our classification. We continue to strive for this level of excellence, and know that our personnel are focused on meeting these high standards.

Capital expenditures in 2013 were $634.4 million, including $82.4 million which was spent on the acquisition of Callon's Gulf of Mexico assets. Our initial capital budget of $450 million was increased to $550 million, to allow participation in another or second deepwater exploration well, Dantzler, and to drill additional wells onshore in our Yellow Rose field. We also experienced a significantly higher success rate with our exploration drilling, which led to additional well completions that were not part of the original budget.

Our 2014 capital budget is $450 million. Approximately 42% is expected to be for exploratory activity, and 52% is allocated to oil-focused development activities, with the remaining 6% to be utilized for seismic and leasehold. Our success last year with a budget that was more heavily weighted toward exploration has resulted in a budget this year that is more heavily weighted toward the development of those exploration discoveries.

Approximately one-third of the budget is focused on deepwater activity in the Gulf of Mexico. This includes significant capital for development of Mississippi Canyon 698 Big Bend and a planned deepwater well at Medusa. Currently 68% of the 2014 budget is allocated for projects in the Gulf of Mexico, and 32% of the project onshore in Texas.

Now I would like to walk through the projects that we plan to see as part of our 2014 programs. As a continuation of our 2011, 2012, 2013 program, we continue to have a drilling rig on location at Mahogany, and expect to keep that rig on site through 2014 and into 2015, with current drilling at the A-15 well being followed by a re-completion and two additional wells later this year. Total productions in this field is holding steady at just below 10,000 barrels of oil equivalent per day, of which 79% is oil and NGLs.

The A-15 well is an exploratory well that is a long-reach, step-out well designed to test and penetrate new stack sand in the southern end of the field. Our enthusiasm for this well is reinforced by the fact that we've already logged some pay in the well. We should reach our total depth near the end of the quarter, and have this well on production in the second quarter.

After drilling the A-15 well, the rig is scheduled to conduct a re-completion in the A-6 well to a new zone. Following the A-6 re-completion activity, we will plan to proceed with the A-16 well, which targets reserves in the M, N, O and P sands identified during the logging of the A-14 exploration well last year. An additional exploration well, the A-17, is in early planning stages, and is likely to spud toward the end of the year.

As another carry-over from the 2013 program, the Mississippi Canyon 243 A-5 well at our Matterhorn field was completed and brought on production during early January, and is currently producing approximately 1,150 barrels of oil, and 1.1 million cubic feet of natural gas per day net to W&T. As a reminder, the A-5 was designed as an injection well to provide pressure support to the reservoir in the Eastern portion of the field. But due to significant pay that was logged, the decision was made to commercially produce the well before returning it to the original injection plan.

Additionally, from the 2013 program we continue our drilling operations in East Cameron 321 field, with the A-2 side track well drilling at about 6,900 feet. The total depth is expected to be in a couple -- in a few weeks. This is an exploration well, and our initial production estimates for this well are approximately 850 barrels of oil equivalent per day net to W&T, of which about 60% of the production is expected to be crude oil. Assuming success, we expect first production to be in second quarter of 2014.

At Big Bend, we are currently completing the discovery well, and the operator is moving forward with development activity. First production is expected late 2015.

Later this year we expect to participate in the drilling of a new exploration well at the Medusa field. As Tracy mentioned earlier, we acquired 15% of this prolific oil producer, and we're attracted by its upside potential.

Timing of this well is dependent on the operator obtaining a rig and receiving all the appropriate permits, but we expect the well to spud sometime in the fourth quarter at a net cost to W&T of about $18 million. This was an exploratory well, representing potential new reserves additions in two separate sand intervals for W&T.

In addition, our budget includes another deepwater exploration well. We are currently evaluating several opportunities, and the particulars of that project will be provided once our commitment is in place to move forward.

Onshore, at the Yellow Rose field, we are very encouraged by the response of our first operated Wolfcamp B well. We are currently planning to spud a second horizontal Wolfcamp B well in mid-March.

Also, as reported in our February 14 news release, we are participating with an adjacent operator in a joint venture well, which began drilling a non-operated Wolfcamp B well in early February. Drilling of this well is complete, and we expect the operator to frac the well towards the end of the month. We would expect to have results to share some time during the second quarter.

Our 2013 budget accounts for seven horizontal wells at Yellow Rose, many of which will focus on the Wolfcamp B. Given the recent successes in the nearby acreage, we expect to test additional horizontal benches this year, with the Sprayberry and the Wolfcamp B as the most likely targets at this time. Additionally, our budget includes the drilling of approximately 20 vertical wells, many of which will continue to prove up our 40-acre in-field position, and continue to hold more of our acreage by production.

Now with that, I'd like to turn it back over to Tracy.

Thanks, Jamie. As I said before, our early success and the success of operators on nearby acreage in numerous benches supports our confidence in the value of our position in North Midland Basin. We believe that there will be tremendous long-term exploration development opportunities in our Yellow Rose Field, which along with our deepwater and deep shelf success will create value for our shareholders. As a side note, our 2014 production guidance that was in our press release yesterday assumes some minor success with the many acquisitions we are pursuing at this point.

Now operator, we're ready to take questions.

Thank you very much. Ladies and gentlemen, at this time we will begin the question-and-answer session.

(Operator Instructions)

Neal Dingmann, please go ahead.

Tracy, obviously good cash-flow story again, it continues to be. With the success you had obviously on that Wolfcamp B, why not go ahead and throw some more, obviously, assets at that and maybe develop that a bit quicker, given the success and given the cash flow (technical difficulty)?

It's a function of our internal budget, Neal. Fortunately, we don't have a gun to our head and yes, we could probably get out there and throw more money and more rigs at it and get the production up, but I prefer to balance that a little bit more with our production out in the Gulf, and generate the cash flow to cover that, so I don't have to borrow more money or sell equity to cover that net.

Got it. Then just one follow-up. Talking about offshore, just your thoughts in general, Tracy, about M&A? Is it as good as it's generally been out there? Are you still seeing a number of deals?

Then if you could just comment on infrastructure? It doesn't seem like you all continue -- I know some of your peers had sort of isolated infrastructure that's out there that have hurt them. You don't see this continuing to happen, though? If you could just comment on M&A and infrastructure offshore?

I think M&A is looking pretty good offshore. It's mostly A, as opposed to the M part of that equation. I think we're seeing quite a bit, still. We had some to sell last year, as well, and sold a little bit of it.

We've got opportunities on the shelf. We've got opportunities in the deepwater. We've got opportunities onshore, as well. That whole market is beginning to heat up, and that's not a surprise to us. We saw a lot of activity last year, and we think it makes a pretty compelling argument for us that we'll have some more acquisitions this year.

As far as infrastructure, clearly as more operators are involved in the deepwater Gulf of Mexico, that basin continues to get more and more mature, and it's easier to get the product to shore. That's one of the things we've recognized. We think about deepwater as being fairly new, but really we've been out there for two and a half decades now, the industry has.

Thank you, Tracy.

Sure.

Curtis Trimble, Global Hunter.

Good morning everyone. Going back, following up on Neal's question on the Permian. Obviously fairly stark, I think, difference between what you guys are, it looks like, in terms of value for the share price, and some of the other deals we've seen out there. Tracy, in terms of continuing on the development side, vis-a-vis, maybe just selling this off, can you go through your thought process, given some of the data points that have been posted over the past few months out there?

I'm sorry, I didn't get your question?

Basically just looking what data points you're looking to see from the Wolfcamp -- the B, the D, the Sprayberry possibly -- to motivate retention and continued development, versus just the straight sale of the property, given some of the fairly healthy valuations we've seen from all the analog areas?

Again, I don't mean to be flippant here. I'm just trying to boil down your question. You said a lot of things, but you didn't actually detail the question. Can you just ask it so I can figure out what you are trying to tell me, please sir?

Sure. What type of well performance are you looking for to retain the Permian, as opposed to divest it?

I want wells that make money. I always want wells that make money. At the end of the day, you want to do something that makes cash flow. Our optimal strategy anywhere is to be able to generate cash flow from operations, whether it's onshore or offshore.

Okay. In terms of rate of return you're looking for is it 20%, 40%? Can you give some detail on that?

I want as big a return as I can possibly get everywhere we are. I don't set limits on rates of return.

Okay, but in terms of lower bound, just not going to talk about that?

I'm not sure what your question is, if you're asking me would I put a limit on my production --

Just a lower bound on it. If wells return 20%, is that large enough to warrant your risk in drilling the wells? Just what the lower bound of that hurdle rate is for your rate of return, your desired rate of return, your lower bound of it?

Yes, sir. Rate of return is always a balance for us. We're not just in the Permian Basin, so we look at our entire portfolio and determine where we want to push money to, to maximize cash flow.

Very good. Now looking offshore on the Medusa --

Sir, I've got of other lot of people on the line could we move on, please?

Sure, thank you.

Biju Perincheril, Jefferies.

Good morning. Just a couple of questions on the Permian, Tracy. You have that JV for one well. I was wondering how do you think about possibly a JV larger scale? If you do go down that route, how do you think about retaining operatorship versus a non-operated joint venture?

For me, it's not really a philosophical issue, sir. It's -- again, it's about making money. As long as we feel like an operator is competent that's not an issue for me.

Okay. On the follow-up, what was your production in the fourth quarter, and can you talk about what are you assuming for 2014 out of the Permian?

Out of the Permian it was about 800 barrels of oil equivalent per day gross or so. I think that's 3,700, 3,800 barrels a day net. Expectations for the Permian Basin for next year is going to be a function of kind of what we drill in the next quarter or so to figure out where we're going to focus our energy.

Okay. If I could have one more question on the verticals in the Permian, it looks like it's slightly lower activity levels. Are these some of verticals now in areas where you don't expect to drill horizontals because of lease shape or what have you? I mean, how do you think about slowing down the vertical program in anticipation of a horizontal ramp-up?

We did drill some vertical wells to make sure that we maintained acreage. Fortunately, we had a pretty good contiguous position out in the Yellow Rose Field, so that allows for some longer laterals. Of course whenever you get to a situation where you are doing pad drilling, or you are drilling horizontal wells across some leased acreage you're going to have that blind spot where you need to put some vertical wells anyway. The program will include a number of vertical wells.

In the ultimate scheme of things it would certainly make us -- it would certainly behoove us to drill some vertical wells to make sure we get full coverage on all those acreage positions. Also, we do have some priority on reducing acreage from 40 acres to 20 acres in some of these vertical plays that will make it -- that will certainly push up our reserves and production in the future.

Okay, that's helpful. Thanks.

Thank you.

Gail Nicholson, KLR Group.

Good morning just two quick questions. Looking at the horizontals in the Permian, what are the current well costs running you? Of the seven horizontals, are you guys planning to do 7,500-foot laterals, or will it be kind of a mixture there?

The short answer is, yes, we are planning on doing some more horizontal drilling in the Wolfcamp B. I don't know that we've necessarily optimized our design there. We think we had -- I mean we did have a good result with the first Wolfcamp B well we drilled. It's an iterative process. When we started that here, we assumed that we'd probably have to drill 15 to 20 horizontal wells before we felt comfortable with a more or less standard formula.

I don't think all of these wells are just necessarily a standard formula. Sometimes you start pumping into one of these zones and you realize you are going to get up to a certain pressure, and then you change the formula from a slick water to a gel type of frack. We're not set in stone. We're going to do it as the conditions would warrant. But generally, we're looking more at a slick water type of approach than we are at a gel approach for most of the stuff we're looking at.

As far as geographic representation on a 7,500-foot lateral, that's what we think is maybe the sweet spot -- 7,000 to 7,500 feet, and many of the lease configurations that we have will accommodate that. That's kind of what I would like to get to. It doesn't mean we can do it on all the leases that we have tied together, but that's kind of what we're looking at.

Okay, great, thank you. Regarding the seismic studies that are being done in the Gulf, will you have these back in late 2014, or is that more of an early 2015 time frame?

I think that it will be late 2014. In fact, we've got some pre-data now, but I think we'll have a pretty good idea first quarter of 2015 where we're going.

Okay, great. Thank you.

Thank you.

Noel Parks, Ladenburg Thalmann.

One of the last items you mentioned as far as upcoming plans was that you were looking at another deepwater well that I guess was just in the planning stages. Is that an operated or a non-operated opportunity?

We're not sure yet.

Okay. Just if understand, so I can take from that operation is a possibility, at least?

Yes, sir.

Okay, great. Then the new Mahogany A-17 well, exploratory well that you mentioned, what are you targeting there? Do you have any pre-drill thinking about how much that might contribute at work?

We're working on that stack pay analysis, sir. I don't have that answer yet.

Okay. Similar to the -- I guess was it the A-14 which was last year's successful exploration well -- so similar to that, just looking for additional zones?

Yes. That's true, and also how to stack them. As we go through the process of drilling these wells we find these sands in various positions. What we would like to do and what we've been doing is as we get more data, we tie that in with the seismic, and we look for aerial extent, and then we look how we can stock the pays with the directional drilling profile.

Okay, great. That's all for me.

Yes, sir. Thank you.

Richard Tullis, Capital One.

Good morning, everyone. Just a couple quick questions. Tracy, what do you expect the development cost to average net to WTI, say over the next couple of years for the deepwater discoveries, Big Bend, Dantzler, Troubadour?

Dantzler and Troubadour -- I don't know that I have that full answer for you yet. We're not the operator yet, and we haven't sanctioned Dantzler or Troubadour at this point.

Okay.

In 2014 we've got about a third of our budget dedicated to offshore, and most of that of course is in the deepwater.

Okay. Then looking at the LOE guidance for 2014, how much workover activity is factored into that guidance?

Hold on, we're coming up with that answer. I'm not sure -- just give me a second, I think we'll be able to get that up for you. Let me look -- we'll get back to you. I'll announce that, if you'll just hold on the phone here, I'll come back to that answer here shortly.

Then lastly, Tracy, how much storm down-time is factored into the 2014 production guidance?

It's just a few days. It's about the same as it was last year.

Okay, that's all for me. Thank you.

Yes, sir.

Michael Glick, Johnson Rice.

Good morning. Just a follow-up on an earlier question on the Permian, specifically. Considering valuations in the basin are pretty hot right now, are you considering monetizing Yellow Rose?

Yes, there was a sale south of there. It'd be silly not to even think about it. Yes, I guess that would be a reasonable statement.

Let me interrupt you just a moment, Michael. In answer to the previous question about the workovers for Noel, it's about $25 million, is what we've dedicated for our workovers for 2014.

I'm sorry, go ahead and continue.

I know this is kind of a hypothetical scenario right now, but in the event that you were to sell it, how should we think about those proceeds? Is it pay down debt or special dividend, or fund deepwater development?

I'm sorry, please repeat the question?

Just talking hypothetical, in the event that you were to sell Yellow Rose, how should we think about use of proceeds?

If I were to sell Yellow Rose -- well, how much would I get for it?

You tell me.

I don't know. That is a hypothetical question. We would have to take a look at anything, just like we would with any disposition of any asset anywhere. We look at it and analyze it as a function of what we think our portfolio requires. We're -- we've been doing this for a long time, so hopefully we would apply it in something that would help our shareholders and help expand the Company.

Got you. Just kind of a quick housekeeping question. On the Gulf, what type of P&A budget should we model in for this year?

We've been running around $70-ish million to $80-ish million per year, so somewhere in that range has been for the last few years about what we've been doing.

Got it. Thank you very much.

Thank you, sir.

(Operator Instructions)

Noel Parks, Ladenburg Thalmann.

Sorry if I missed this, I got on a little late. Do you have any updated thoughts on east Texas, the James Lime out there?

We've finished drilling the fifth horizontal well. We have -- we are continuing to test same. When we went into this project in east Texas, we were thinking it'd probably take 15 to 20 wells across the acreage we had to come up with a plan to continue and accelerate the development. That's kind of where we are.

I don't have a whole lot of production data for you at this time that I want to share. We're looking at it as -- to proceed on towards 15 to 20 wells on the horizontal side of it, and make that determination or whether we should make that determination a little bit sooner, or whether we should just move on. I don't have a definitive answer for you, but we're -- we know we've got more work to do if it's something we're going to continue to pursue.

Sorry about that, so that 15 -- I did hear you mention the 15- to 20-well program needed to establish that. I thought you were talking about the Permian, but that was actually east Texas, is that right?

That was both.

Oh, okay.

We would assume that if we were going to go ahead and do a real development-type program such as what we're going to do out in west Texas that we would need 15 to 20 wells to evaluate the acreage position that we have in the area. We haven't made that decision yet. We are on the fifth well. We're still evaluating those results, and trying to determine if this is something we want to carry forward with or not.

Great. At this point, where are you on the ticking clock of lease expirations out there? I can't remember exactly when you guys entered the play?

We don't have any real serious considerations about maintaining acreage out there, other than whether or not we want to continue drilling. It's more of a drilling obligation than anything else. It's not -- you've got to jump out there and drill 100 wells, or something like that, Noel. It's a very limited obligation.

Okay, great. That's it for me.

Thank you, sir.

At this time there are no further questions. I would like to turn the call back over to Management for any closing comments.

That's it, operator. I appreciate it, and we will talk to the markets again either on our next call or before. Thank you so much.

Thank you. Ladies and gentlemen that will conclude the conference for today. We do thank you for your participation. You may now disconnect your lines at this time.