Saratoga Resources' (SARA) CEO Tom Cooke on Q2 2014 Results - Earnings Call Transcript

Aug.15.14 | About: Saratoga Resources, (SARA)

Saratoga Resources, Inc. (NYSEMKT:SARA)

Q2 2014 Earnings Conference Call

August 15, 2014 10:30 a.m. ET

Executives

Brad Holmes – Manager, IR

Tom Cooke – Chairman, CEO and Founder

Andy Clifford – President

John Ebert – VP, Finance and Business Development

Analysts

Noel Parks – Ladenburg Thalmann

Owen Douglas – Robert W. Baird

Joe Dancy – LSGI Advisor

Eric Anderson – Hartford Financial

Owen Douglas – Robert W. Baird

Operator

Good day, ladies and gentlemen. And welcome to the Saratoga Resources Results of Operations for the Second Quarter 2014 Conference Call. At this time, all participants are in a listen-only mode. Later, we will have a question-and-answer session and instructions will follow at that time. (Operator Instructions). As a reminder, today’s conference is being recorded.

I would now like to introduce your host for the today’s conference call Mr. Brad Holmes, Manager of Investor Relations. You may begin, sir.

Brad Holmes

Good morning, everyone and thanks for joining us for the Q2 2014 conference call for Saratoga Resources.

Before we begin, I need to remind everyone that this call will contain certain forward-looking statements within the meaning of the Section 27-A of the Securities Act of 1933 as amended Section 21-E of the Securities Exchange Act of 1934 as amended, which are intended to be covered by the Safe Harbors created thereby.

To the extent 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 a 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 filings with the Securities and Exchange Commission.

With that, out of the way, I’d like to turn the call over to Mr. Tom Cooke, Chairman and Chief Executive Officer. Tom?

Tom Cooke

Good morning, and thanks for joining us as we discuss the financial results for the second quarter of 2014, and provide an operations update. I’ll begin by providing management’s high-level view of operations and Andy Clifford and John Ebert will discuss operations and financial results and final position in more detail.

Q2 is highlighted by our successful drilling and completion of our Rocky 3 well. Rocky 3 was our third successful high angle or horizontal well in Breton Sound 32 and its test was the best in our company history. We brought the well onto production late in the quarter and curtail rates based on flow line capacity limitations.

We added new flow line to serve us Breton Sound 32 and the new line coming on line in July allowing us to move up production from Rocky 3 as well as other wells in the field although we continue to analyze the optimal production rate on Rocky 3.

In addition, we continue to make progress in our field initiatives to address runtime and restore production levels which were fallen off during Q1 and Q4 of the previous year. During the quarter, we made additional personnel changes and conducted a number of successful recompletions in work hours adding need of gas lift supply and in the process made a number of facilities upgrades. As a result of these initiatives, we saw marked improvement in run-time and production rate with average daily production rate rising from 1330 barrels net of oil equivalent per day in Q1 to 1944 BOE per in Q2.

June is worth noting average 2300 BOE per day and I think as of the 11th as the last production report that I have got in detail. We had Breton Sound shut in for some adjustments on compression but our BOEs were running right at 2662 BOEs per day net. Following the end of the quarter, we were successful on adding much needed compressing in Grand Bay to put in the booster compressor and let other infrastructure repairs which are further enhance runtime and production volumes.

We continue to keep a close eye on field operations to optimize production levels and avoid future production declines as experienced in Q1.

I’ll turn the call over now to our President Andy Clifford to discuss operations after which John Ebert our VP Finance and Business Development will discuss the financial results then we will take the questions.

John Ebert

Thank you, Tom. Good morning everybody. As Tom mentioned, our quarter was highlighted by our successful drilling of the Rocky 3 horizontal well in Breton Sound 32 field. Rocky 3 was drilled to a true vertical depth of 5818 feet for the horizontal leg of 733 ft. The well comes onto production on May 28th.

As a result of flow line capacity constraints, another well in Breton Sound 32 was produced below capacity pending construction of an addition of its flow line. We immediately commenced construction of a new flow line to serve Breton Sound 32 and completed the new flow line in early July. With addition of the flow line we are moving up production in Breton Sound 32 although we are continuing to monitor Rocky 3 to optimize its production rate.

In addition, we carried out three successful recompletions during the quarter and have two workovers ongoing in the quarter end which is since being successfully completed. Through the wells, now recompletion of workover program have added significant gas supply to support our gas lift needs.

Our field operations initiative which was begun during the first quarter to address the runtime and related issues, the pull down production during that quarter continued in the second and third quarters. While we continue to closely monitor field operations and are looking to high-grade our staff and improve operating efficiency, the field operations initiatives have borne fruit as one times moving up from a low of approximately 54% in the first two months of 2014 to an estimated 77% in the second quarter and 80% in June.

As a direct result we raised our average daily production rate from 1313 BOE per day in the first quarter to 1944 BOE per day in the second quarter and as Tom just mentioned, it is getting higher all the time.

With our investments and facilities, the addition of gas lift gas and other field operations initiatives being substantially completed and the resulting rise in production we are now turning our focus back to our development program.

We are running reservoir simulations in Breton Sound 32 to identify (inaudible) parts of the field for additional prospects as well as evaluating additional development prospects in our inventory and we have commenced the firming process to bring forward the most promising prospects.

With respect to our deep drilling prospects in Grand Bay in the Gulf of Mexico, we finalized our packing of our first prospect in Grand Bay known as Goldeneye and we have begun presentation to prospective drilling partners. In fact there is one going on right now down the hall.

On our initial Gulf of Mexico prospects, we are finalizing our package and expect to rollout those prospects for presentation to prospective drilling partners shortly. We presently anticipate during the third quarter and fourth quarter to build our cash position while avoiding substantial operations during the peak hurricane season. While we might be drilling again by the fourth quarter, we are presently targeting early 2015 to resume drilling from our prospect inventory.

In the meantime, we may conduct selected high impact recompletions workovers the similar projects to optimize production and cash built. One more thing, there will be a new Saratoga Resources website, by the end of this week, hopefully, rolled out by next week, long time coming, coincidence with our presentation at the Enercom conference in Dever, so look out for that.

With that I will turn the call over to John Ebert to discuss the financials.

John Ebert

Thank you, Andy and welcome to those on the call. I’m not going to go through the financials line-by-line, but I will touch on some of the key financial metrics and developments for the year.

Oil and gas revenues for second quarter were $15.1 million, up42.6% from $10.6 million in Q1 2014, down 14.7% from Q2 2013. The decline in oil and gas revenues for quarter-over-quarter was directly attributable to the addressing field operations issues discussed by Tom and Andy, which resulted in a 47 point increase in production quarter over quarter.

The discretionary cash flow rose from negative $5.2 million in Q1 2014 to negative $0.5 million in Q2 2014 but was below $3.1 million for the second quarter of 2013.

Our EBITDAX for the second quarter rebounded from $100,000 Q1 2014 to $4.8 million but was down from $8 million in Q2 2013. Both, discretionary cash flow and EBITDAX were adversely impacted by the production declines discussed and the resulting reductions in revenues.

Operating income for the quarter was down to a loss of $600,000 for Q2 2014 from income of $1.9 million in Q2 2013 but an improvement from the loss of 2.2 million for Q1 2014. The decline in operating income and profitability for the quarter reflects the substantial decline in production volumes, together with higher lease operating expenses associated with the various initiatives undertaken in the field during the quarter which and higher G&A expense associated with personnel changes which were partially offset by lower DD&A and reduced severance taxes resulting from refunds of severance taxes associated with our Rocky, Zeke and Mesa Verde wells drilled in prior periods.

The field initiatives undertaken beginning in late Q1 2014 and continuing through the second quarter yield a positive impact through a marked improvement in operating income from Q1 levels. With the completion of our field initiatives in site we expect to begin transitioning in various functions being handled by outside contractors to company personnel and expect to focus on bringing our lease operating expenses and general and administrative expense back down to lower levels and return to positive operating income.

The net loss for the quarter also reflected the fact that we have fully reserved against our deferred tax asset and do not reflect any tax benefit associated with the loss for the quarter.

At June 30, 2014, we had $18.3 million of cash on hand and working capital of $4.6 million. We expect to fully fund our 2014 development through cash on hand and projected operating cash flow.

As mentioned earlier, our CapEx for the balance of 2014 is expected to be focused on recompletions workovers and other high impact, low cost projects focused on optimizing production and building cash with the target of getting back in drilling mode by early 2015.

We continue to take steps to minimize our exposure to commodity price risks with the establishment and maintenance of hedging program. As of June 30, 2014, we are 23,000 barrels hedged on a fixed price LLS-swap averaging approximately $106.95 during the third quarter of 2014.

We are continually looking at the hedging markets and plan to layer in more hedges for 2014 and beyond as we deem appropriate.

Our hedging activity today has been focused solely on oil with the recent strengthening in natural gas prices, we are monitoring natural gas pricing and may consider hedging natural gas prices in the future.

With that, I’ll turn the call back to Tom.

Tom Cooke

Thanks, Brad, Andy and John with that I’ll open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Just a couple of things, mostly focused on the ongoing efforts to add personnel and of course improve the facilities up times and so forth. You mentioned that you had a lot of apparent improvement during the quarter, was that mostly in Grand Bay or in another area or Breton Sound or?

Tom Cooke

It’s kind of the across the board. There were some people in management in Covington office that moved on and the analysis we are starting with Breton Sound 32 that we may changes at the field supervisory level as well. So what we are doing is we are just upgrading or high-grading some of these things for hedges frankly growing still. So we have got a lot of new blood and we have got a lot of new enthusiasm. The number should not increase as we start to shake this out and get it right sized, the number of personnel will probably stay about at the same now. In some cases, our goal is to take some of the contract services and move them in house in Saratoga because we see cost savings there. So we are kind of looking at it from top to bottom.

So we think the G&A actually after we finished this review and the changes that we feel like are necessary. We think actually that the G&A will come down and our LOE will come down as a result across the board.

Noel Parks - Ladenburg Thalmann

And you have also talked about doing some new permitting or beginning to permitting process for some future drilling. Just how many locations are projects that you are looking to permit at this point and how long do you anticipate that taking?

Andy Clifford

Noel this is Andy. We are permitting a new well at Grand Bay. We are trying to design and look for horizontal candidates and some side track we could do from the existing wells of Grand Bay. We have number of wells, we have previously considered drilling at Grand Bay but we are looking for some sort of horizontal components as a result of our success at Breton Sound 32. At the Breton Sound 32 we are going to be permitting a number of locations and will select from those once we get the reservoir simulation work in the full Breton Sound 32 to select two or three of those several candidates we will permit. We just don’t want to lose time waiting for the permit, wait for the reservoir simulation and then decide where we want to permit and want to start the process. So that's what we are alluding to.

Noel Parks - Ladenburg Thalmann

Okay and you mentioned that you actually had discussions going on right down the hall as far getting partners for some of your upcoming projects. And I can’t remember if you have talked about this before, are you envisioning more sort of one-off type of arrangements where there is particular project or handful of projects that you be getting a capital from the partners from or are you thinking of something more long-term putting projects and do a JV where they would have a right to participate in the future?

Andy Clifford

I will start and then Tom will add to it. But certainly right now we have a full Gulf of Mexico leases where we will look for one or more partners, the same partners might taking interest in all four, may be different partner. So that's certainly one area where we want to try and keep 50% -- find 50% partners for those and Goldeneye, Grand Bay and other one that we want to offset about 45% and find one or two partners for that. other than that we have contemplating with some certain areas, maybe we are looking Vermillion 16 again, some other areas and contemplating seeking a partner for some of those efforts but I let Tom to add to that.

Tom Cooke

The things that we are looking are, you mentioned of Vermillion 16, those are gas projects and those are the things that we pushed back because of gas prices. We are starting to see a lot of interest in oil and gas, a lot of renew interest in gas. So I think we could get ahead ourselves if we were to announce any specific plans relative to that. But those are things that we are looking at.

The Grand Bay wells if you recall, our last effort was $25,000 million test and $16,000 fee plus and we are not taking about the ultra-deep which still remains kind of a mystery to the industry as well as McMoRan I would guess. But those are more expensive, particularly little bit higher risk, even commodity risk, that's where we would be looking to take on partners. And it just a matter of being involved in more wells, accelerating our inventory which remains very-very deep and trying to get broader exposure to more production and increase our BOEs per day.

So it’s a way for us to deleverage, it’s something that we have been looking at and looking for the right time to do it and certain cases we feel like that timing is starting to emerge, certainly with Goldeneye that could unlock a whole different level in the field because that's a deeper well which kind of fits that profile and it’s a very-very interesting project but it does carry more risk, it is steeper, it is in geo-pressure. But likewise we are looking at doing some of the lower-cost geo-pressured wells internally.

So remain with the focus that we have got, keeping the 100% where we came and where it gets little more expensive, little more risky that's where we will be looking to partners in some of the projects and simply spoken with the deep inventory that we have and operating at the cash flow, we would like to see that accelerated.

Noel Parks - Ladenburg Thalmann

Great. And just curious, as we have talked with the different (inaudible), have you had interest from international energy investors or operators?

Tom Cooke

Yes. We don’t want to get in any great detail but the answer is yes.

Noel Parks - Ladenburg Thalmann

Okay, great. That's all from me. Thanks.

Operator

Our next question comes from Owen Douglas with Baird

Owen Douglas – Robert W. Baird

I have question here, have a couple of ones. Just curious as to what do you guys seeing with regards to decline rates and the wells being drilled, are this wasn’t keeping with that 6% to 7% rate for I believe for the lot of your portfolio?

Tom Cooke

I would say yes but you are looking at these things as of maturity of the well. We do suffer as everybody does. Some initial decline in the early stages of these wells and then settling and I guess one of the best examples that we have got in our Breton Sound 32 field where we have drilled the horizontal wells. The L1 well is a 20 year old, it’s produced over a million barrels. That well still producing around 100 barrels a day and with virtually no decline, probably has been written-off as far as the reserves, multiple times over the years. But we have got a lot of examples of this.

When you initially complete these wells, some of them have an initial decline for instance our two gas wells over main pass 47, they came on at about 2 million cubic feet a day and there is still a 2 million cubic feet a day. So it’s a kind of a hard hodgepodge, it’s a little bit hard to fit everything that we have in one vein (ph) while we only have about 50,000 acres that we control, we have HPP, we have under lease, they bear it. While at the small acreage, relatively small acreage position, we have got 64 stacked pays in Grand Bay and we have got 22 potential zones in the deeper sections of the Grand Bay.

So it’s a hard question to answer because one size doesn’t fit at all.

Owen Douglas – Robert W. Baird

Okay, I appreciate that. But in terms of thinking about the performance of the Rocky 3 well, I believe you guys now have this for a few months now producing, how was that shaping up in terms of the decline rates or what you guys believe so far to be?

Andy Clifford

It’s been pretty true-to-form to the other horizontal wells and the L1 for instance which I think on the – they did a side track on that well at one point in the same formation because they had a reservoir damage or skin damage to the well and that well are pitted about 1100 barrels a day. That was one of the better wells in the field. Now that well produced a million barrels. As far rates are concerned, the last test we had on Rocky 3 was about 450 barrels but that we still don’t know exactly whether we will produce that well, we can produce at much higher rate we think but we are just in the process. We are taking a very cautious approach. We are doing this reservoir simulation that would give us some additional information. We are also doing some down-hole pressure analysis. So I guess that the best way I can answer that is, it’s producing right about just under 500 barrels a day. We think it should be, we should be able to produce that at a higher rate now that we have got the flow lines and now that we can kind of focus on bringing this production up. So we won’t do anything to damage the well. We will try to keep those rates as high as we can with the water cut as low we can. We do have the ability to produce the luminous volumes of water. So that's not an issue for us but it’s a matter of finding the right number.

Owen Douglas – Robert W. Baird

Okay. I appreciate that and in terms of thinking about, I think you made the comment, correct me if I wrong here that you expect to generate some cash in Q3 and Q4, is that accurate?

Andy Clifford

Yes.

Owen Douglas – Robert W. Baird

And can you sort of walk in through your thinking on that because the third quarter you guys have $9 million or $10 million in cash interest payments. So I just want to get a sense on the puts and takes as we try to think about the Q3, Q4 cash?

Tom Cooke

Well, I think I will talk to it globally; John may want to jump in. The production is increasing primarily due to runtime and things that we have done in the field to enhance production and it’s kind of bringing the wells up and adjusting the gas lift. So we think that there is a lot of run room here just doing some recompletions that we likely have done in Q2 to continue that in Q3 and Q4 with our drilling coming back into play in Q4 or the first quarter of 2015. So we think that there is a lot of room to move the production up with that drilling the wells right now. But we continue to look at wells and we look at the high impacts wells and that is an ongoing process but we feel like that the cash flow will continue to increase.

And as the change that we have made and the infrastructure additions that we have made have been significantly, they been expensive. For instance, the oil line, we were having to treat that line, we spend almost the half of the million dollars in treatments on that line, just trying to keep it up with the production that we are putting into it and with the new lines we don’t have that problem. So those expenses will go away. We also have associated with that new line that was $800,000 to a $1 million I think all in with, and of course it also caused us to curtail production as we got that in place.

In Grand Bay we put this push to compressor rim which is incredibly, it’s helping us balance our gas lift which rather than being up and being down runtimes are much more efficient. It’s a new compressor to push to compressor, something that the company is actually being talking and doing for four to five years, we finally did it. We went out and change 25 valves and these aren’t little (inaudible) valves there are big 150 pounds major valve systems in Grand Bay. So that when we have interruption in production let’s say we have a gas leak, we can shut in that line rather than shutting the whole field. This is another thing that we have been putting off for at least four years.

We actually got that accomplished in about 6.5 hours but it took about two months for at the very intense planning, the execution was pretty amazing. We have fly bottom boats and four air boats so we can get into the mark, we have prepositioned valves, cut bolts and everything was in place and on the various locations and we were able to accomplish the change out of those systems and about six and half hours comparably at the same time Chevron was shutting in their 20 inch line that we flow in to and Breton Sound 32 for the change of one valve and it took them almost two days to get that accomplished and we got a lot of very large, size, heavyweight valve systems changed out in six and half and that's the real point of proud. I don’t think anybody could have done it more effectively or efficiently. And I would challenge any company that they would be able to do it as immaculately or they can go that far as we were able to accomplish that.

Here again that something we have been putting off years, we said because we didn’t want to shut the field in and we said okay let’s plan it so we can minimize that, we did it, we got the compressor on line at the same time. So we didn’t have to put the field down for the compressor coming on line and then have to put the field down for the valve changes, most people didn’t think we could accomplish this in two or three weeks and we got it from the pressure down to pressure back in about 12 hours.

Owen Douglas – Robert W. Baird

And you mentioned having the up time improved, just for a prospective here, in 2013 what was the, well I guess actually excluding that fourth quarter, what was the uptime of the field site and where do you think you can get it for Q3?

John Ebert

Owen I can answer the question in terms of runtime for 2013. Our average runtime during the full year of 2013 was around 75%. Again, so we are up from that, up to 80% currently. About the time that Andy addressed where we think we can get from here, there is a room to move that up. You are not going to achieve 100% runtime, we get as close as we could but we are working to address some other issues out there, chief of these being gas supply, which is kind of may be number one call for it for some of our down time. We have eliminated the second call for it or may be partially eliminated the second call for it was the compression at Grand Bay and we look at it potentially bringing additional compression out there but Tom I don’t know if you have any comments on where we think we are going to end up?

Tom Cooke

No, I think it’s continuing to improve and we concentrated on retaining and adding to the engineering staff for all of our rotator equipment and that's also, we have somebody they start yesterday has mechanic but we are doing a lot of preventative things at this point to make sure and making sure that we have got redundancy so that we are not driven by the skin our (inaudible) with one thing being interrupt everything. So it’s a kind of comprehensive approach but I think our goal is to be 90% plus.

Owen Douglas – Robert W. Baird

Okay, that's good to hear. And final question, just want to better understand with regards to the marketing activity “marketing” development, but just thinking about your PDNP well inventory, it’s relatively sizable as well your PUDs, so just thinking about how you go about marketing these properties what have been some of the challenges or push back that you have received from prospective partners. And what do you think you can do internally to help essentially monetize all of these non-revenue generating resources you have?

Tom Cooke

Andy, do you want to answer that?

Andy Clifford

We haven’t, we really haven’t had any push back here. We really just started marketing one prospect which is basically more than the prospect. We see this is as an exploitation opportunity, multi exploitation opportunity really, lowest exploration through the development. We haven’t had any pushback on that and certainly we haven’t try to market any PUDs or PDNP opportunities, nor would we at this time.

Tom Cooke

I would say that it has been positive, we have been little bit slow out of the shoe but the response has been good and it’s kind of like when I alluded that Vermillion 16 which is primarily gas and it’s expensive drilling but it’s high volume, their large reserve. So that we something would be looking at, of course the GOM leases speak to themselves. We think that they have merit, there is interest there. We haven’t really started typically showing that. We have been kind of waiting for all of our, everything kind of line up and get ready to do so. I am sitting in the conference room, that's got a math on every inch per inch of the walls it seems and the research that's gone into has been very impressive and there is no question that it would be asked by major or a small or large independent but we can’t answer. These things are things that when we do take the math and discuss it with the market, we are ready to answer any of them questions.

As far as doing something with the larger inventory, that's something that we are just in the formative stages of consideration as Andy said we are not looking to sale off our PUDs but our net asset value per share is extraordinarily high when you look at the reserves that we have on the books.

If we were resource company people we would be throwing money at that opportunity to put those high quality projects on line, being conventional in South Louisiana, little less enthusiasm but needless to say we think that compared favorably our success has been a high percentage, a very high percentage and the longevity of these reserves as we have said before we have got wells that have been producing for 70 years. So I don’t know how to answer that specifically nor do I think I should but whatever is going to make to sense for our shareholders, we have always been focused on building value in the equity and we remain focused on that. I hope that helps.

Owen Douglas – Robert W. Baird

Okay, well thank you very much guys.

Operator

(Operator Instructions) our next question comes from Joe Dancy with LSGI Advisors.

Joe Dancy – LSGI Advisor

Most of questions have been answered but let me fill a couple of more, you already touched on this a bit but deeper exploration efforts going in the Gulf in the industry, have there been any development in the last six months that might be of interest and actually might enhance the asset value of our company?

Andy Clifford

Certainly not in the Ultra Deep Joe but certainly we have been kind of following the way of Energy 21 in terms of their horizontal development drilling and one thing that EPL didn’t do prior to Energy 21 buying. One thing I believe Energy 21 (inaudible) in that deal as applying that horizontal technology and get the higher EUR, 2.5 to 3 times a EUR on the reserve.

The way you see the way we can get, so that's one application of technology angle that we are benefiting from other falling suit, as they comes as we are talking to as we were showing Goldeneye to say, well tell us about your horizontal drilling, we would like to do some of that too and which is current need but not other aspects, other things which are thing on in the Gulf, significant events of this multi-nodule seismic, (inaudible) Energy XXI using now.

They are doing with the great success, I think it will successful around salt domes, we don’t have any salt domes and we like the fact that we don’t salt domes because you have a lot more area in the middle of the field that isn’t covered with salt, it has got prospective sand section instead. So to all stages salt domes are very prospective if you can image them big drilling risk around the edges of salt domes too as people are finding out and leaving dome and some other places. So we watch them all, we watch them very closely but I think we are going to benefit greatly in our Gulf of Mexico efforts with some of our seismic prospects, 3D prospects.

Some of which we have some PUDs on too. I think we are going to benefit by some of the new thinking and applications as we go forward and the remarking effort the next month and getting excited about what we are seeing the enhanced efforts we are putting into it and talking to some of these companies to partner up with.

So with Goldeneye in that, we really do, would like a strategic partner or two that can add some value to and we can, not just the check rider but someone who we can learn from and with and stay with us and fully develop these assets.

Coming back to the Owen’s question, one thing that has taken a bit of time as we never really had a marketing capability, we are not a shop that generate prospects and flips like some other companies. So we have to develop that and I think we have successfully done that in the last 12 months because basically GO’s production and development types not exploration type. So I think we have enhanced that capability which will help us going forward if we want to broaden the effort and find more partners from more things, I think we have developed that capability a lot more than we have before.

Joe Dancy – LSGI Advisor

That's a good summary. Thank you, I really – in the last six months I really sort of loss track what’s going on in the gulf. I mean you touched on it little bit too I mean I think Saratoga’s assets are incredibly interesting, be conventional in the Gulf with the approved reserves and it seems like investors are deviating for the shale plays onshore and are you seeing any increased interest at all in our type of development offshore in the shallow formation versus coming on shore in the Bakken where you drilling these the shale plays have no permeability, porosity and get frac hedge out of them?

Tom Cooke

There have been some new starts up. New money coming into conventional south Louisiana, just in last month or two. And we have heard about a few and successfully funded and likewise in the shallow Gulf as well, so it moving back toward these kind of assets. As some of the bloom comes off the rose and some of measles place and some comes doing very well and suits what’s but there’s a lot which aren’t doing so well and we have seen a bit of a migration back to conventional Gulf coast assets likely. So I think that will help us too.

Joe Dancy – LSGI Advisor

And the valuation there definitely I mean, what approved reserve is almost incredible, let me go to your, you just mentioned the 2,600 barrels of oil per day that’s like for the last month or last week and certainly we can't expect that for the third quarter of averaging family or what is that 2,600 number that you guys just fill out earlier during your commentary what is the study and what can you comment on it?

Tom Cooke

Well, it’s that was last Wednesday, two days ago and that also included (inaudible) which was because our compressor was, we had to replace a couple of heads on the compressor. I believe that we have got room to run and get those numbers higher. I must be reluctant to talk about averages because that’s where you can easily get into trouble.

Joe Dancy – LSGI Advisor

Yes, exactly. I don’t want to forecast, but I just was curious.

Tom Cooke

We think we have got runtime, we think we have got. We are well ahead of the curve on increasing the runtime which is really to having that consistency but we are moving in a right direction and I could say we have got a lot of infield things that that are kind of a low hanging improve, right now we are perforating a little recompletion of that today. So it’s a gas well give us lot more gas, lot more gas supply and security in the main path area, but it will also add to our BOEs per day. So we are looking at some of those opportunities and even our melting plants. What we go out and melt these wells, we’re trying to be little smarter about how we do it. We are actually getting more barrels out of the well but milking it less, letting the well recover and build up and then milking it on a schedule relative to the time in which you start producing that well and let it build up. So and that’s having an impact. So lot of these things are pretty boring but that’s as I say where the rover hits the road, that’s the cash flow and that’s where we’re focused.

Joe Dancy – LSGI Advisor

Right, right. I understand, one last question and I sort of ask this (inaudible) your discounted present value of your proved and improved reserve lesser that is like $7.52 or some more and therein that’s given the probable and possible reserve like the zero and I assume management doesn’t think that share price of a $1.70 is reflective of Saratoga’s assets when potential share price, I know that you mentioned one of your goals is building shareholder value and I guess the assumption is, you think there is value there above a $1.70 and that’s why you’re going to like intercom conferences and some of the other industry sponsored investor conferences.

Tom Cooke

Well, we certainly believe that does not reflect the true value of the company and the share price should be substantially higher and I think the real key to unlock that is barrels per day. We’re at a heavy discount to our net asset value per share when you look at our proven reserves and we’ve had very good success in developing those proven reserves. So that remains a little bit of a frustration to us but I think the cash flow and the BOEs per day are going to go long way to terming that perception.

So, I don’t know what more to say on that.

Joe Dancy – LSGI Advisor

That’s fine, I just was curious that was my assumption and never – it’s been a while since I’ve seen a discount of present value of proved reserve that such a discount really, such a premium for the sale price and I know you guys are working on it, not I can agree that you can get the stuff in the pipe and get a crawled things to work out well for us. So, thank you guys, best of luck in this quarter and the rest of the year.

Tom Cooke

Thank you, Joe.

Operator

Our next question comes from Eric Anderson with Hartford Financial.

Eric Anderson – Hartford Financial

Good morning, if I can go back briefly to Tom your comments about trying to build in redundancies to the system such that you don’t have issues that crop up from time-to-time either with regards to gas lift, water disposal or just takeaway capacity with pipelines on various wells or fields. How do you balance the need to do things like that that really if you do alright it won’t show in terms of your – you won’t use it, but at the same time you got to spend the money subtracted from cash flow in order just to have it, so you don’t have these disruptions, I mean, how do you, I think about actually spending and budgeting that money versus what it would do in terms of reducing your ability to work on some of these high completion opportunities?

Tom Cooke

Well, it goes to run time and your total barrels and your cash flow. Compressors are going to go down, but you want to have a stand back and presence in Grand Bay, we’ve got four low speed compressors that are very old, we put the new booster compressor which is extern, okay that the new compressor is going to go down periodically. We want to make sure that we have got backup compressors so that we don’t have any shutdown time. Every time we shutdown a field, we’ve to go back in and rebalance the gas lift and it causes, it’s a major headache just for time, I mean, these guys go out, they’re working 24 hours a day when we have a shutdown of those sorts much less, but the impact on cash flow.

So, we think that’s, we look at it as a payout it’s not just having an extra compressor, it’s having an extra compressor which we know could save you 20% on your bound time because you don’t have to worry about shutting in, you can just go to your backup systems. So, we’re not spending an exhaustive amount of money relative to that, we’re spending enough money and we’re thinking smarter on maintenance and prevented maintenance and making sure our backup systems are tested on a regular basis so that we don’t find ourselves in a hole like we did first for the year and that went to the operations group and that’s why we’ve made the significant changes we’ve made in the operations group. But, we don’t think it’s an either odd, we think it’s very additive.

Eric Anderson – Hartford Financial

I was not trying to be critical with that. What I was trying to get at is that, there is always things that you could do and I guess first is knowing what exactly are the potential weaknesses that are out there in the system before they actually break then you have to deal with the consequences, so it’s no way I am trying to be critical, just a question on how do you balance just given the fact that you’re dealing with a lot of old infrastructure and it would be nice to get to --?

Andy Clifford

One thing Eric we’re doing now is kind of cooperate there, checking all out to protection in all our fields, all our wells, putting rectifiers and the compressors and doing a lot of that. Spending a lot of time and effort making sure everything is setup well for the future.

Tom Cooke

That’s not a very expensive solution that’s the complexion is not expensive, what’s expensive is if you start having hosing, your tubing and your casing and your systems and then you have shutdowns relative to it. So that’s something that this company before we bought it had completely neglected it and I think Andy and I were kind of shocked when we realized how neglected that protection had become and it was springing like here, and springing like there and we’re going why, and part of the research that’s what we needed to do for preventative maintenance. But those aren’t expensive things to do. We look at everything and every project on payout even if it’s redundancy I’m calling it redundancy or call it maybe more appropriately backup systems we look at that on the payout. This new compressor I think is going to cost us around $200,000 it’s already saved us $200,000 on the first three weeks of service. This time of the year you have problems with these all compressors overheat. So I mean we look at everything on a payout basis it’s going to make sense to our cash flow and one of the things that you do when you do a flurry of this activity and you’re trying to right size everything, you spend a little bit more money, but we think that that will start come back into balance here very shortly.

Eric Anderson – Hartford Financial

Okay another question when you are talking about these potential partners that you would like to have with regards to the more expensive or pressured wells, do you anticipate always being the operator of these wells or might you give that up to get the right type of an arrangement on well by well basis?

Tom Cooke

We are not necessarily, we envision being the operator on these wells, certainly we would have to be compatible as, if we partner with somebody that’s got a very impressive drilling department. We are going to know exactly what the procedure is going to look like before we would endeavor go down that road. I mean, I think we have all heard the four storey where you get in partnership with the major and they make it into a science project and that ends up costing you two or three times of what it would really cost if you were just running for that main objective. So, all of that goes into the analysis of who we think as a partner, it’s not necessarily going to be driven who can write the check.

Eric Anderson – Hartford Financial

So compatibility and flexibility?

Tom Cooke

Absolutely. And we’ve got this, we understand this thing in enough detail not just from geology and geophysical side, but from the engineering side that we have got specific ideas and we have got specific ideas as to the cost of these. We are going to have to be very compatible and we will be making an arrangement with somebody who was comfortable with how we are going to go about drilling the well. So, we don’t find ourselves in a cost run scenario. And there is other ways to skin that category, if you do have a cost run scenario then it maybe a backend for that additional interest, so that you got to carry for part of it and let’s say on the cost overrun you get backend and you don’t get diluted, you don’t railed out of the project, there is ways that you can structure, not saying that that’s what we are going to do but there is ways you can build in to the deal some protections in that regard.

But we are not desperate to do a deal at any cost. So, if the deal isn’t right, the deal won’t be done.

Eric Anderson – Hartford Financial

That’s comforting to hear. And that’s my last question, I know that you’ve got plenty of things to do in terms of prospects that have already been identified, but I know also from time-to-time there is additional acreage that comes up in lands that are contiguous to what you’ve got and you have been successful at grabbing few hundred acres here and there. Is there anything along those lines where you’re seeing things that potentially could come up that would make an operation more efficient in a field or in the exploitation of what you’ve got?

Tom Cooke

I will answer that Andy, the answer is yes, but I don’t want say anything more at the myth. There are a lot of people looking at where we are, it’s pretty small neighborhood, but yes, we do see some of that and we’re always looking and we’re always looking to see what other people are doing close to us that maybe upside or seismic coverage. But –

Andy Clifford

Well that has to be valued against what we have currently, it always be an opportunity we see to upgrade something we have on the books that has to stack up. So, we don’t, not that we’re just going lease land for the sake of it, it has to have a strategic reason and be somewhat better than something else we have as an alternative.

Eric Anderson – Hartford Financial

Does the stay have like auction process or can you nominate something that --?

Andy Clifford

You can nominate every, each month and then it’s about 90 days away before it becomes in this, which is great because in the federal its once a year and people get rejected, which gets rejected because they have a minimum on [MRROV] so number of things, we have been on one a few years ago and was rejected.

Eric Anderson – Hartford Financial

Okay. That’s all from me thanks very much for taking my questions.

Tom Cooke

Thank you.

Operator

Our next question is a follow up question from Owen Douglas with Baird.

Owen Douglas – Robert W. Baird

Hi guys, thanks for taking the follow up. Just really a quick one, I wanted to understand again what is the 2014 CapEx budget just in mind of all the projects you’re talking about?

Tom Cooke

Well, we live within cash flow, right now the focus will be how much cash we can build up and which projects we can layer in. We don’t have anything per say in the drilling budget for the remainder of the year, although if we can build the cash towards the end of the year, we may try and slide well in, we’ve a couple of things that Andy, he didn’t mention in particular projects, but in terms of that’s why we’re permitting things right now, and if we consider them in at the end of the year we will, the near term focus will be as we said on the call, some lower cost but relatively impactful opportunities that maybe workovers, recompletion, quality remark. So much depending on our cash flow and again we are acutely aware of making sure we – on and all our obligations that are after as well.

Owen Douglas – Robert W. Baird

So, is there a cash or minimum cash number you guys are trying to give to, or --?

Tom Cooke

Yes, but I will not go into any more detail.

Owen Douglas – Robert W. Baird

Okay, thanks guys.

Operator

I’m not showing any further questions at this time. I’d like to turn the conference back over to our host.

Tom Cooke

Well, thank you all for joining us, we feel like that we have turned the corner and we have made a lot of improvements, the enthusiasm of Saratoga is high, the moral on the field is high and we are getting things accomplished, everybody is not just going through the motions here, they are going to the motions with an objective to build this company and make it a long term job opportunity. So I think that what we’ve seen in the production increases, we are going to stay focused on that management spending more time in the field, be in a little bit more hands on and I think that’s bearing fruit and we will continue to do that. It’s going to be some long hours but we are dedicated to accomplish in our goal and building value for our shareholders.

So with that unless you got anything else to add Andy, John, thank you again for joining us today. And hopefully we will make you proud shareholders of Saratoga Resources.

Operator

Ladies and gentlemen that concludes today’s presentation. You may disconnect and have a wonderful day.

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