Saratoga Resources Management Discusses Q1 2013 Results - Earnings Call Transcript

May.13.13 | About: Saratoga Resources, (SARA)

Saratoga Resources (NYSEMKT:SARA)

Q1 2013 Earnings Call

May 13, 2013 10:30 am ET

Executives

Brad Holmes

Thomas F. Cooke - Co-Founder, Chairman and Chief Executive Officer

Andrew C. Clifford - President and Director

Michael O. Aldridge - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Analysts

Jeffrey Connolly - Brean Capital LLC, Research Division

Daren M. Oddenino - C. K. Cooper & Company, Inc., Research Division

Evan Richert - Sidoti & Company, LLC

Eric B. Anderson - Hartford Financial Management, Inc.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Joseph Dancy

Operator

Good day, ladies and gentlemen and welcome to the Saratoga Resources Results of Operations for Quarter 1, 2013. [Operator Instructions] As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host for today, Mr. Brad Holmes with Investor Relations. Sir, you may begin.

Brad Holmes

Thank you, Ben, and good morning.

Before we begin, I need to remind everyone that this call will contain certain forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, which are intended to be covered by the Safe Harbors created thereunder.

To the extent that these -- that there are statements that are not recitations of historical facts, such statements constitute forward-looking statements that, by definition, involve risks and uncertainties. In any forward-looking statement where we express an expectation or belief as to future results or events, such expectation or belief is expressed in good faith and believed to have a reasonable basis but there can be no assurance that the statement of expectation or belief will be achieved or accomplished.

For a complete forward-looking statement, please see our SEC filings with the Securities and Exchange Commission.

With that out of the way, I turn the call over to Mr. Tom Cooke, Chairman and CEO of Saratoga Resources.

Thomas F. Cooke

Good morning, and thanks for joining us this morning as we discuss the financial results for Q1 2013 and provide an operational update.

I'll begin by providing management's high-level view of 2013 operations and Andy Clifford, our President; and Mike Aldridge, our CFO, will discuss our operation and financial results and our financial position in more detail.

Entering into 2013, our focus was on production growth while continually keeping an eye on opportunities to grow and upgrade our prospect inventory. Although we did have a high -- a very slight decline in production volumes from Q1 2012, by the end of Q1 2013 we have completed operations in 2 fields that weighted on our production during the quarter and we are seeing production in those fields move back up now entering into the second quarter.

Additionally, going forward we expect production to benefit from tubing replacement programs that we will expect to roll out by the end of Q2 and by drilling more impactful wells identified through our field studies, which we reinitiated in 2012.

Our lease position enhanced by our field study program continues to yield new opportunities to supplement our growth, our core producing assets. We control over 32,000 acres, almost all of it held by production to all depths in shallow water and our positioned to add some exciting shelf prospects covering our 19,000 additional acres.

We have a deep inventory of relatively low-risk PDNP and PUD conversion opportunities that serve as what we believe is an ideal platform to grow production and are also positioned to participate in the growing ultra-deep play with multiple ultra-deep targets already identified in our holdings.

In addition to our PDNP and PUD conversion opportunities, we believe we have significant behind-pipe reserves beyond the amounts quantified in the proved reserve category, which provide us with significant number of exploration projects.

With a $9 per share NAV of proved reserves and what we believe is significant untapped potential, we continue to be excited about our assets and the production growth potential of those assets.

In looking at the quarter and where we are moving into the second quarter, we see opportunities to realize the value of our assets and grow production and profitability in a number of areas in the short term, as reflected in our NAV per share of $9, our favorable LLS and HLS pricing, which allowed our revenues from oil and gas to remain relatively flat during the quarter despite a slight decline in overall production and the exploration of our full field study, which is yielding more and more impactful opportunities, our -- we are -- our apparent high bid on our 4 Gulf of Mexico leases, totaling 19,814 acres and the pending initiation of our tubing replacement program in Grand Bay that we think has potential to add 400-barrels-a-day-plus to production for a relatively minor capital expenditure.

I'll turn the call over to our President, Andy Clifford, to discuss operations. After which, Mike Aldridge, our CFO, will discuss the final results. Then we will take your questions. Andy?

Andrew C. Clifford

Good morning, and thanks for joining us this morning. Thank you, Tom.

During the quarter, we produced a total of 230,991 BOE, which is down slightly from the same quarter in 2012 and from the end of the year. However, our oil production was 156,770 barrels, which was an increase of about 5% from the first quarter of 2012. So the drop in overall BOEs was due to a drop in natural gas production.

As we told you in our year-end call, we had several wells in our Main Pass 25 Field that were shut in due to a lack of gas for gas lift or due to problems relating to third-party processing facilities. In addition, the QQ-24 well at Grand Bay was shut down for 5 weeks while we drilled the QQ-25 well adjacent to it. These issues have since been addressed and we are now seeing an increase in production from those wells, which will offset any natural declines.

Pricing continues to be strong in the LLS and HLS markets. We received an average price of $110.92 for our oil for the quarter and $4.22 per Mcf for our gas. So our overall oil and gas revenues remained steady.

During the first quarter, we completed the QQ-209 Buddy well in Grand Bay Field. The well was drilled to a total depth of 6,820 feet measured depth/TVD and was successfully completed in the 3A sand. Flow testing of the Buddy well demonstrated an IP test rate of 208 net BOE per day. Flowing tubing pressure was 580 pounds per square inch on a 19/64" choke.

The SL-195 QQ25 Roux Toux well was drilled to a total depth of 8,453 feet measured depth or 8,000 foot TVD during the first quarter and was successfully completed as a dual completion in the Main Pass 47 field. The well had an IP test rate of net 509 BOE per day with a flowing tubing pressure of 1,800 psi on a 14/64" choke on the short string and 275 psi on a 30/64" choke on the long string. The well has subsequently been tied back to the company's Grand Bay facilities.

In addition to these, we also did 3 recompletions and 2 workovers during the quarter, one of which was still in progress at the end of the quarter. All 3 recompletions were successful. We've now restored production successfully from the few remaining wells that were shut in due to Hurricane Isaac. We are in the advanced stages of negotiating for a barge rig to drill our first horizontal well in Breton Sound 32 field, the SL 1227-25 Rocky well. We're looking to drill more impactful wells, as Tom alluded to, including horizontal completions such as Rocky and deeper exploratory tails under our in-fill wells.

Rocky itself involves drilling a 70-degree directional pilot to the 5,800 foot sand, then to plug back and drill a horizontal leg with a 750-foot lateral into the reservoir, with an estimated completed well cost of less than $7 million. We've already established the current water level in that part of the field by running a PNL log in the SL 1227-21 well, determining that the oil-water contact has risen only 6 inches in over 20 years. This significantly reduces the risk for this horizontal completion.

After Rocky, there are several other horizontal completion opportunities available to us, including Zeke and Charlie, which are also in the Breton Sound 32 field and we are investigating other opportunities in Grand Bay and elsewhere.

Our reprocessing of our proprietary 3D survey at Grand Bay is revealing amplitude versus offset, or AVO, anomalies in the shallow, geopressured section that includes the Cib Carst Uvig 25 [ph] sand in new prospects such as Goldeneye, Pintail and Redhead.

So we'll be looking to optimize our deep drilling in Grand Bay to target the best opportunity, so as to: A, give us the best shallow bay land opportunities above the 25 sand; and B, give us our best shot at the deeper Tex W objectives.

As Tom mentioned, we are implementing the tubing replacement program at Grand Bay Field, as well as looking at gas lift optimization and considering workovers of wells where thru-tubing gravel packs have failed in the past. This program is designed to restore curtailed and shut in production. 21 wells have been reviewed as candidates to date but many other wells are being reviewed and high-graded.

Each of these wells was producing between 20 to 50 barrels a day before being shut in. Some of the wells reviewed to date have presented new recompletion opportunities to the company. The program involves installing a pulling unit on a barge with an estimated cost of about $200,000 per well. Once completed, we anticipate that up to 400 barrels a day of production will be added.

We continue to work with a third-party operator regarding upgrades for the Main Pass 25 facilities. The objective is not only to increase production but vastly improve field economics and reduce our dependence on third-party processors, which caused the shut-in of most of our Main Pass 25 production during the first quarter of 2013.

We did successfully recomplete the state leased, 16432 #11 [ph] well in the 7,900-foot sand during the quarter and this is expected to provide sufficient gas-lift gas to upload all the oil wells in the field.

Now an update on the 4 leases in the Gulf of Mexico, where we were the apparent high bidder. These 4 blocks are all located in the shallow GOM shelf with water depths between 13 and 77 feet. The 4 leases combined add 19,814 acres gross and net. Most important, our internal estimates relative to these blocks, as yet not audited by third-party reserve engineers, are 51.2 million gross barrels of oil equivalent, of which we believe 5.4 million gross barrels equivalent were qualified as PUDs. We were attracted by the high liquid content of these reserves, which we estimate will exceed 8 million gross barrels of oil in 3P reserves. Finalization of the leases remains subject to approval by the BOEM, which we are hoping to receive during the second quarter.

Several prospects were already identified in the blocks, all generated using high-quality, 3D seismic data. Lease bonuses total $880,000, with first-year rentals of $138,000, a price that we view very favorably relative to our estimate of resource potential for the prospects.

The blocks include 100% working interest in each lease with 77% net revenue interest. Our plan is to seek joint venture partners with first drilling expected in 2014 at the earliest. These new leases offer potential in normally pressured target reservoirs shallower than 15,000 feet.

With regard to the ultra-deep play, we remain encouraged by recent results announced relative to the Chevron-operated Lineham Creek well in Cameron Parish, just 30 miles to the west-northwest of our Vermillion 16 acreage. I would note that the Mesa Verde well, which we drilled last year, in addition to it adding production, further solidified our lease position in Vermillion 16.

Just one comment I want to make about -- we've been making some key additions to our operating team since the end of the first quarter, including adding 2 seasoned reservoir engineers and a geophysicist, who together are working with me to maximize the payback of our field study program. We've also added an experienced land manager to bring in-house our land management operations.

With that, I'll turn the call over to Mike Aldridge, our CFO, to discuss the financials.

Michael O. Aldridge

Thanks, Andy, and welcome to those on the call. As in previous conference calls, I'm not going to go through the financials line by line. However, there are a couple of things I do want to point out.

We had approximately $22 million of cash on hand at March 31, and positive working capital of $18.6 million. Our cash balance has increased to in excess of $24 million today. Our planned CapEx for the year is approximately $45 million, of which we've spent over $7 million in the first quarter. All of which will be funded by cash on hand and cash flow. Our working capital adjusted debt to trailing 12-month EBITDAX is 2.9x at March 31, and our net asset value remains very strong at approximately $9 per share.

As reported in our year-end call, we took substantial steps late in 2012 and so far in 2013 to minimize our exposure to commodity price risk with the establishment or reinitiation of our hedging program. To date, our hedging program has focused solely on our oil production but we are encouraged by recent gas price movements and are monitoring opportunities to layer in some gas hedges. As of March 31, we had 297,000 barrels hedged on a fixed -- on a couple of fixed price swaps that averaged $108.10 that expire in March of 2014. We are continually looking at the hedging market and plan to layer in more hedges for 2014 and beyond as we deem appropriate.

We continue to monitor costs very closely and in this quarter, we were able to reduce G&A expense by 23.4% to approximately $2.1 million, down from approximately $2.7 million in the first quarter of 2012.

With that, I'll turn the call back to Tom for closing comments.

Thomas F. Cooke

Thank you, Mike and Andy. I did want to point to the new additions that we have in our group and we feel like they're very significant adds and I also wanted to point out that we believe that these people are coming on board and we believe it'll be a net neutral to our G&A expense because we will be replacing third-party consultants in all regards. Don Olson [ph] is highly qualified reservoir engineer and he'll be joined with Laura Vasut, also a reservoir engineer. This is going to give us more horsepower at that position than the company has ever had. Patrick Keegan is joining us on the land side in-house. It'll give us a real go-to guy. We feel like that's going to be a great add and we've been solely relying on third-party land services. And we have just recently hired a geophysicist to work closely with Andy Clifford and his world-class expertise. I cannot give you his name yet but he agreed this weekend to join the team. So we're real excited about having these guys come in.

I also wanted to point out that our hedge position, we're very proud of it. We've seen some volatility in oil prices and gas prices, and we're currently about $1.9 million in the money on those hedges. So that gives us a little bit of comfort and a little bit more rest in the nights, not knowing what pricing we're going to wake up to in the morning.

So with that, I'll open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Jeffrey Connolly of Brean Capital.

Jeffrey Connolly - Brean Capital LLC, Research Division

A quick question on current production. It's running at about 3,000 BOE per day. 4Q production was about 3,365 BOE per day. Can you just help me square up what that 365 BOE per day difference is?

Thomas F. Cooke

I'll take this. It's just operational issues. Things shut in, compressors down. We've gone in and reworked our water disposal wells, which is something that we do every 12 to 18 months. We brought a water disposal well online and we just completed it because it was taking water and we didn't do the normal acid job that we would -- and clean up of that well before we put it online. So we're right within that general maintenance window and that affected our production as well, and I think probably more so than anything else. And then just things that were shut down due to compressors, just general maintenance-type things, which are all being remedied as we speak, if haven't already been remedied. And as we pointed out, the tubing replacement program, we had some wells that were going off due to mechanical issues. Those go into another basket. Now those -- we feel like that those will actually add PDPs to our reserves because as some of them happened right at the end of the year or close to or right after the first of the year, those declines obviously go into your third-party reserve calculations. So we think we'll actually add some PDPs and certainly we'll add current production to the mix. And some of the projects -- frankly, the transition and getting our new reservoir engineers up to speed. We have made sure that we got a fresh set of eyes looking at all of our reserves now and not relying on consultants that have a little less skin in the game. So we think that, that's starting to have an impact. And we pushed off some of those projects until we can get these guys up to speed, which we're very comfortable that we're getting there at a very fast pace, if not already there. So as we finish these final reviews, we move more into that workover basket out of the 20, 21 wells that we've identified so far. So it's more of a general maintenance issue. There's nothing alarming there to point to. I hope that -- hopefully that will help you.

Operator

Our next question comes from the line of Daren Oddenino from C.K. Cooper & Company.

Daren M. Oddenino - C. K. Cooper & Company, Inc., Research Division

Tom, you talked about the Grand Bay tubing replacement program. How should that look? I mean, will that -- what does that 400 barrels a day look like? When will we expect to see that come on? Is that going to be pretty gradual?

Thomas F. Cooke

Yes, it will. You'll see it be completed by the end of August. We're anticipating adding about 121 barrels per month in June, July and August. So that's kind of the way it shakes out. And we're - like I said, those are just general estimates but we're going to keep adding more to that estimate. And actually, it's -- we anticipate it's going to look a little better than we first anticipated. As Andy mentioned, we're going back and looking at some wells that sanded up, that were done as thru-tubing gravel packs and we've been working with Halliburton to come up with remedies for screen repair in some of those staled gravel packs. And so we think with the fresh set of eyes and us going back instead of just moving forward -- a lot of these things even go back to when we went through the -- 2 years ago, when we were in bankruptcy and operating on a real shoestring, some of these projects sanded up and we just moved on for lack of resources to apply to those projects. So some of this is just way past due housecleaning. But we think it's going to arrest some of the decline that we've seen that's been considered to be a decline wherein, in reality, it's mechanical issue. So...

Daren M. Oddenino - C. K. Cooper & Company, Inc., Research Division

And how many could you typically do in a month?

Thomas F. Cooke

Well, it depends on how they go. So I don't want to say. We just kind of got it laid out as an average. Now some of these wells, we'll move the equipment over the hole and we'll -- and after further inspection, we'll say, "No, we're not going to go into this one. It's going to be cost prohibitive." And we'll move to the next one. In some cases we're looking to see what kind of access we have because of silting in the field, especially in Grand Bay where it's very shallow. We'll determine whether we can do it by just wheel washing [ph] the site and what we're going to have go through in the permitting process. But I think the number of candidates is approaching 30 so we feel like we're going to be able to safely say that we should be able to come up with 20 good candidates. And it will kind of depend on how they go. Some of them will be really easy and some of them will be a little more difficult but we'll be very careful about not getting into difficult wells where we see things like our Tomahawk well, what we affectionally call the hatchet job well now, where we got into a workover program that we anticipated costing us like $1.8 million and it ended up costing us over $6 million. We're not going to do that again even though we can point to that well and say, "Well, we doubled production." I'm not sure if it'll ever pay out. So we're going to go in with a cautious approach. So I think you'll see some really good results and we anticipate seeing some better results than we've indicated in some of these wells.

Daren M. Oddenino - C. K. Cooper & Company, Inc., Research Division

Okay. And then what are your expectations for the Rocky well? And when could we expect to see some results related to that?

Thomas F. Cooke

Rocky is -- Andy had alluded to the fact that we have a verbal agreement on the rig, which would make it available as soon as June 1, maybe a little earlier. I think June 1 is probably the prime target for that rig. They promised us that it's not going anywhere else and we're in the final legal review of the contract, which could be done by the end of the day. So we think that, that well will be in production by the end of June, certainly the first part of the third quarter. But our goal is to get this in production before the end of the second quarter. And as far as production -- anticipated production, we think that we're looking at about 663 BOE net from that well and we think that's probably a conservative number, as well. We look at the offset horizontal wells that have been drilled in there and 1,000 barrels a day is not unheard of at all. We've seen 2x to 3x the production rates from over the vertical and 2x or 3x the recoveries. So we're going to be pretty careful about our forecast. But this well, which we're calling a high-impact well, if this works, then we have other candidates. We think it will work. We don't see any reason why it shouldn't. And I've got a lot of experience in horizontal drilling going back to the first horizontal wells drilled on shore, in the Pearsall Austin Chalk. So this is something I'm very familiar with. And Crescent has brought in Baker Hughes and we're looking at Schlumberger, we're looking at Energy XXI and how they've approached their program. So we've done a lot of study on this and it's done nothing more than enhance our confidence that we will see the results that we're looking for. We're not in a reservoir that's unusual because it's been horizontally drilled and -- in these offset locations. And some of those wells remain, after 20 years, still producing 80 barrels a day plus. Some of the best wells in the field were originally drilled horizontally. So we think this is past due. But it's time for us to look at some of these things that are more impactful. But this and our Tex W test, which will bring big reserves in, maybe not the same kind of production rate but multimillion barrel objectives are the kind of things that you'll see us try to focus on, while we still will continue to do our low-hanging fruit opportunities and some of the less expensive drills and PUDs and behind-pipe recompletions. And as Andy likes to say in the presentations, our probable reserve recompletions are over 90% successful, which would typically be equated to proven-reserve type categories. So we still have a lot of that on the bone.

Operator

Our next question comes from the line of Evan Richert from Sidoti & Company.

Evan Richert - Sidoti & Company, LLC

We obviously have your daily rates, the average for the quarter. I was wondering if you could just give some color on how that looked at the end of the quarter versus, obviously you had some workover, some issues with a third-party, but any idea of relative -- if you can give any color on that?

Thomas F. Cooke

Any idea -- I'm sorry, would you say the last?

Evan Richert - Sidoti & Company, LLC

Your daily production rates. They were down obviously, year-over-year a little bit and down from the fourth quarter. If you could just give an idea on how that looked going into the quarter versus coming out?

Thomas F. Cooke

I think our production was actually up 18% last year. The fourth quarter was -- still had some of the lingering effects of Hurricane Isaac but, as we pointed to in the conference call, Main Pass 25 was pretty much shut-in for the entire quarter due to third party handling. And those issues are being resolved and we are -- by the end of the month we should be well into our construction project to be able to take our well away from that third-party facility. It'll reduce line pressures. We think that we could be looking at 125-barrels-a-day increase just by lowering the line pressure by not going into our pipeline, which goes from a -- don't hold me to this but like a 6 to an 8 to a 10 to a 4, and it's a hodgepodge of lines and it creates a lot of back pressure. So we think conservatively we'll add 125 barrels a day to that. In that process, we spoke of the well that we completed for gas, where we shut in about 40 barrels of oil a day when we completed that well. Once we get all of it back up and running and get the field balanced out, we'll be able to bring that well back in on a co-mingle arrangement that state has granted us. That also -- getting permission to co-mingle also pushed us back a little bit on our timing but the agreements are in place. We'll be handling some third-party production, which will lower our LOE in that field. Also of note, with the production increases, we'll save between $80,000 and $90,000 a month in LOE just from not having to deliver it to a third-party for processing. So those are, I think, the principal culprits here to seeing the production down in the second quarter and I think, when everything's up and running, we'd be close to 3,300 barrels a day today.

Evan Richert - Sidoti & Company, LLC

Okay. Also, the CapEx, obviously it's a little low for the quarter. I guess that's a lot just related to the workovers and the overall plans you have. Any idea, I guess, for the year, seasonally, if you can -- what schedule you're looking at for that?

Michael O. Aldridge

Yes, I can take that one. We spent over $7 million in the first quarter and we're probably looking at spending approximately $10 million in the second, $10 million in the third and then a little more in the fourth because that's when we plan to fund [indiscernible] that Tex W test that Tom alluded to earlier, probably around October is the thinking right now.

Evan Richert - Sidoti & Company, LLC

Okay. And next, onto the hedging. You mentioned you started up with oil, you're looking at gas. But as far as the oil, are the levels you're at now, do you think that's somewhere you'd like to stay or would you look to add into that, too?

Michael O. Aldridge

Well I think we've probably done all the hedging we're going to do for 2013, absent, say, Rocky coming in a lot better than expected or something like -- there might be an opportunity to lay some additional hedges in 2013. But really the focus primarily is on first quarter '14 and beyond, which we do have 500 barrels a day in first quarter '14, and so we're looking to add to that position in the remainder of the year.

Evan Richert - Sidoti & Company, LLC

Okay. And last question, just on the Ultra-Deep. You don't really see anything material on that coming in the near term? Obviously, the gas prices are a little higher but just historically, that's not really on your plate for the foreseeable future?

Andrew C. Clifford

Tom didn't mention we're going to spud up Long John Silver in September? That's okay, I'm just kidding. No, we're really just watching the activity around us, letting the play de-risk itself. And as we've said before, Tom said before, we'll just let the play come to us. But remain very interested in it, but we can just -- as long as we can hold shallow production, hold the leases by shallow production and learn more about the play as it develops, we'll just sit and wait.

Thomas F. Cooke

I will add that the results of Rocky will determine a lot of what we do for the remainder of the year and how we spend our money. If Rocky -- I like to think optimistically. If Rocky produces at the rates that we anticipate or potentially better than those rates, then we would probably look more towards horizontal wells and try to keep our powder dry for those opportunities. So you'll see a lot swing on how we approach our assets with those results.

Andrew C. Clifford

Just one more thing on that. Part of the field study effort is geared towards finding some other candidates within Grand Bay and elsewhere as part of that process. That's not the only thrust but that is part of the thrust.

Operator

Our next question comes from the line of Eric Anderson of Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

I wonder if I could just follow up a little bit on Rocky. You mentioned that the water level in the field has risen very modestly over the last 20 years. What does that imply about either the field or perhaps production that has been targeting it over the years?

Andrew C. Clifford

Well, Eric -- this is Andy. Certainly in that part of the field that's the case. And we had -- one thing we did note and, if you go to the slides from our last presentation, they're on the website. There's a little map cartoon with a green blob showing the 5,800-foot sand. And underneath that semi-transparent green showing where the current oil-water contact is, there's green circles, which are the wells which have drained that reservoir. And you'll notice much more dense -- denser cluster on the west and central part of the field than there is on the east and southeast, which is where we have our Rocky and Zeke prospects. So we think that those -- that part of the reservoir is underdrained. Now whether or not that eastern part where Rocky is, is fork-separated from the main part but very subtle fork that we can't see on 3D or not, we're not sure. So we can't really extrapolate that 6 inches to the rest of the field but we have a hunch that maybe there's more still to be found in the central part of the field that hasn't been adequately drained or maybe there's some recharge. A lot of these fields get recharged, other [indiscernible] field's replumbed over time and so that may have been the case. There may have been some recharge of oil into the reservoir but it's certainly of interest to us. I mean that is the main driver with the horizontal, is staying above the water leg. Now we are doing a directional pilot. We've weighed up whether or not we should do that or not, just go straightforward or not, because if you know where the water is you don't need that so much. But the big uncertainty is how high we can get attic on the reservoir to the 21 and 22 wells. I mean we can -- we could gain 5 10-foot structure and get a thicker oil column than the 20-foot that we expect to have on top of the -- in the oil lake on top of the water. So there's good upside there but the water leg is the key thing. We think there may be a chance that the Rocky and Zeke structures are actually joined. There are very little information in that part of the field. So the upside is we could find a lot more. Whether or not the one well will tell you that or not is probably -- it's doubtful. But anyway it's encouraging that the water -- we were surprised how little the water level had moved up over 20, 30 years. So that's good.

Eric B. Anderson - Hartford Financial Management, Inc.

Do you -- are you going to try to land the lateral portion -- or the horizontal portion right in the middle of the oil zone or what's the thinking of where you actually try to land that?

Andrew C. Clifford

Tom, I'll let you address that if you want.

Thomas F. Cooke

Well that's one of the things we're evaluating now, whether we -- our thinking right now is to stay in the top 5 feet and of course it will depend on what's above you, as well. We think that this particular shale that sits on top should kind of guide the wellbore through the section. We're only going out 750 feet, so it's not rocket science and it's not difficult to stay within a small target. But we'll try to stay in the upper portion and try to stay away from that water contact the best we can. Now the L1 [ph], for instance, is a well that still produce -- it's one of the wells that we'll be doing some work on. When it went off production it was producing about 80 barrels a day and it's been in production over 20 years. Now it produces a lot of water but we're positioned to be able to handle that water. But it kind of -- these declines kind of defy logic when the water contact hasn't moved any further than it's moved in over 20 years. I kind of prescribe to the recharge theory. But as far as how we're going to drill these, I noticed that Energy XXI said that they tried to stay towards the center of the section but I think the reservoir will dictate that. But that's a question that's still under review.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay, and if I could ask just one follow-up. When you get around to the Grand Bay deep opportunities either later this year or in the future, are those all exclusively vertical penetrations at this point or may some of those also be horizontal?

Andrew C. Clifford

Tom, I'll address that first and you can add if you like. We're trying to keep them as vertical as we can. The trouble with when you go horizontal, you're almost forgoing the bailouts up above because you're coming in at an angle. That's not such an issue with Breton Sound 32 because there isn't really anything above 5800' sand. That is the shallowest objective or 5750' is, anyway. But so you're really not giving up those bailouts. But at Grand Bay, we do pride ourselves on having bailouts on the way down. So what we're trying to do is we'll either need go vertical or it'll -- it's sometimes also dictated by the surface, so whether or not you've got an excess where you can do minimal dredging to get to. And so that will dictate whereabouts you start your well and it'll be a low -- probably a modest directional. But what we're trying to do is to stack up as many pays and potential pays on the way down. So I would say more than likely, it will be a directional, not a very high-angle directional, very modest directional that's very easily done. And we'll keep them as straight as we can and then it's a question of how many things we really want to stack up in the same wellbore. And sometimes we use a part of the wellbore as an exploratory tail, not only deep but also sometimes up shallow in the part of the field which we want to reconnoiter a little bit more. So the horizontals in Grand Bay will be more likely single-objective targets, sands such as the 3 sand, the 4 sand well, sands which have produced a lot of the reserves in Grand Bay historically but we think are underdrained, underswept. And in those cases, we'll probably do a pilot first and then do a directional. The well we just did, the Buddy well, the 209 well, we completed in January. The channel sand would've been an ideal candidate for a horizontal in hindsight but we've completed that as a vertical with a gravel back. But that would've been a good candidate. So another sand opportunity like that elsewhere in the field we will more than likely target with a horizontal sometime in the near future.

Thomas F. Cooke

Now let me add to that, Andy. In the exploratory tail, those are highly -- those are very high-quality exploration targets, let's say, because we're -- we've got the structure map and we're drilling on amplitudes. But those, as we mentioned, even where we know we're drilling a pilot to be able to identify the top and the bottom of those sands and the productivity of those sands. So I don't think you're giving anything up by drilling a vertical hole to prove your reservoir and you'll get virgin pressures and high production rates even out of the vertical. And then we would do the analysis of whether those new targets, those new discoveries are candidates for horizontal. But as Andy said, it's kind of the good news and the bad news. We've got some big fat sands that would be wonderful targets right now for horizontal drilling but you've got multiple-stacked sands above it. So you're almost forgoing that if you whip [indiscernible] stock one of those existing wells or drill a new well just for that target. But depending on the results, it may be -- we may be able to determine that if we're looking at 4- to 6-month payouts on these horizontal wells, then I think you'd see us going in and drill some just for the horizontal test and pick up the end pipes [indiscernible] in the existing wellbore. So it's good to have options and that's what we've got.

Operator

Our next question comes from the line of Noel Parks of Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Just a couple of things. Are we thinking -- in the new onshore acreage that you got in the lease sale, what's the deepest production that's been drilled on that acreage so far?

Andrew C. Clifford

It's a maximum of 13,000 feet, more in the 10,000 to 12,000-foot range, Noel.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

And were those, I don't know, Miocene targets?

Andrew C. Clifford

Yes, it's all Miocene, all normal pressure. So none of it involves a pipe test, intermediate casing and all in shallow waters and stacked objectives. In most cases -- in some of the cases, stacked objectives, some of the cases more likely some single objectives.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. Have you guys given any thought to whether there's deeper potential on the acreage? I imagine that's not something that would be a near-term target but...

Andrew C. Clifford

That's not something we've evaluated at this time on these particular -- that wasn't one of the drivers. But there may be or maybe not. So we haven't evaluated that yet.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay, good enough. And just in the onshore, in the transition zone. What's the overall industry activity level look like these days? We've had a little bit of fluctuation in commodity prices and so forth. So are things looking any different as far as who you see drilling out there, either among other public or private companies compared to say, beginning of the year?

Andrew C. Clifford

Tom, do you have any comments on that or do you want me to...

Thomas F. Cooke

Yes, I think you might be best suited to -- I mean, we're seeing some activity as far as other operators are concerned. The barge rig -- cost of barge rigs has gone up slightly. That indicates that the demand for barge rigs, which are your shallow water rigs, is up. As Andy mentioned, the new leases are in 13 to 77 feet of water. We're not in anything close to deepwater, so the costs should be normal.

Andrew C. Clifford

Yes, there've been some -- there continues to be some M&A activity in the immediate nearshore area, so -- and companies surrounding us are as active as before. I don't think it's anything specifically any greater activity this quarter over the end of the year but -- and we are close. We do talk to a lot of our neighboring companies in terms of just getting to know each other, in terms of helping with operating efficiencies, issues like insurance, rig activities. So I think things are pretty much the same or slightly picked up a bit but we're not seeing any great increases in service costs, maybe a slight bump.

Operator

[Operator Instructions] Our next question comes from the line of Joe Dancy of LSGI Advisors.

Joseph Dancy

Going back to the Rocky well, how did we come up with a lateral length of 750 feet? I mean in the future, if this works out, can we go further? And I'm just curious if this is a standard lateral and if it's reservoir-constrained, technology-constrained or exactly where we got that proposed length?

Andrew C. Clifford

Joe, there've been 4 previous horizontals in Breton Sound 32 in the field we're talking about, and there's 1 in Main Pass 25 and 1 in Grand Bay. The 4 in Breton Sound 32, the earliest of those was 1995 by Kerr-McGee, and then there's such ones in '96, '98, '99, I believe. And they all range from 300 to 900 feet laterals. And all had the 2.5x to 3x recoveries and enhanced rates over verticals that Tom alluded to. So 750 is kind of towards the higher end of that range but we feel that we don't have to get that far out. Anything over 300 foot we'll be doing okay. It's certainly not a reservoir related -- we're not in danger of going across a fault or anything like that. So we think anything in the 300 to 750 range will be suitable. Tom, do you want to add anything to that?

Thomas F. Cooke

Yes. It's -- what we'll do is we'll go in there and let the reservoir and the sand tell us, dictate to us whether we go 350 or 750 feet. We're prepared to go 800 and we think that, that's ample from the look-alikes. But if it becomes difficult drilling or we start seeing problems with the hole, then we'll stop where we are and take what we've got. We'll be drilling this as a high-angle test, which is -- there's a school of thought that says high-angle is sufficient. We feel like the horizontal is going to just add to that but I don't think, as far as technology, we're challenged nor by the reservoir. We're kind of going by the previous results even though those are somewhat dated over what we can do technological-wise today. But I don't think that you're going to see -- there's no need to try to drill 1,000, 2,000, 3,000. It's a whole different animal than the shale plays that people like to try to put us in, into that concept. We should be able to drain these reservoirs adequately with 700-foot laterals and, like Andy said, I think we'll have obtained our objective by a multiplier on production rates and recoveries with as much as a 300-, 350-foot lateral. So we just don't want to get in here and try to do something and be hell-bent on getting to even 800 feet. The well will let us know when we get into that structure. And the main thing is to get your hole, do your dummy run and then put your feedback screen in as soon as you can so you don't have any kind of deteriorating hole conditions.

Joseph Dancy

Okay, that makes sense. I'm just not really familiar with the -- so you can actually achieve your objectives, unlike some of these onshore shale wells, with a much shorter lateral, is pretty much what you're telling me. As well as the technology, I'm sure, is like heads and tails above these 1995 wells, I assume.

Thomas F. Cooke

It really is but you're talking about 2 totally different type of structures. We're not frac-ing these wells. These wells will be gravel-packed. The permeability and porosity is very high. The production rates have been very high. They've been in that 1,000-barrel a day range on the old horizontal drills. One of them was a sidetrack that went out 350 feet. That well's cumed about 700,000 barrels of oil and still producing about 80, 90 barrels of oil a day. So we don't feel like we've got to set any distance records here to make good wells nor do we have to frac them. So we've got a big advantage over what has been kind of a hijack technology in my mind for the resource plays.

Joseph Dancy

Okay. I think I got the timeline right here. So we're going to do this before July? Is that right?

Thomas F. Cooke

No -- yes. We're going to spud this well -- as it stands right now, we will spud this well about June 1. And we think that drilling and completing of the well is within 30 days.

Operator

Our next question comes from the line of Jeffrey Connolly of Brean Capital.

Jeffrey Connolly - Brean Capital LLC, Research Division

Guys, I want to ask a follow-up on Rocky about the completion, but Tom just answered it so that's it for me.

Operator

And with no further questions in queue, I'd like to turn the conference back over to Mr. Cooke for any closing remarks.

Thomas F. Cooke

I want to thank everybody for their time and their patience. We continued to have some challenges in the first quarter. We really see those things starting to come together. I can't emphasize enough how important it is to have a fresh set of eyes in our reservoir staff and have all of that in-house and not be relying on consultants. So we think the quality of our prospects is going to be increasing. We think the wells we're going to be drilling are going to be more impactful wells. We have absolutely no concern at our production levels right now other than to get them up. And that's what we're in the process of doing and we're really going back and reviewing everything and we're reviewing declines and things that were considered to be declines that were actually mechanical. I think that's going to bear significant fruit and I think it's been one of the things that we've been kind of fighting against. But we've got the resources in-house now to get all of that accomplished with the new geophysicists coming onboard to help Andy and not relying on third-party consultants. That's going to be very significant. Bruce Ballenger [ph] and Bob Monahan are doing an excellent job on identifying our geologists, in-house geologists. We've had them go in so many different directions we feel like now we can focus on accomplishing our objectives and trying to keep things more in an orderly basis and moving in the right direction. So we're happy to be pulling it together and we think that this is going to be a very good year for us with a little bit of a slow start. So we got a little bit of catching up to do. But I think everybody just needs to hang in there. A $9 per share net asset value, not reflecting the new leases, is not being reflected on our stock price. So we're hopeful that our stockholders will be patient with us because we think the results are going to be excellent. We think that there's a buying opportunity in our stock today. And I want to thank you, again.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program and you may all disconnect. Have a great rest of the day.

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