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Saratoga Resources Inc. (NYSEMKT:SARA)

F4Q2013 Earnings Conference Call

April 01, 2014 10:30 am ET

Executives

Tom Cooke - Chairman of the Board, Chief Executive Officer

Andy Clifford - President

John Ebert - Vice President, Finance and Business Development

Analysts

Noel Parks - Ladenburg Thalmann

John Polcari - Mutual of America

Hassan Ahmad - Imperial Capital

Owen Douglas - Baird

Joe Dancy - LSGI Advisors

Operator

Good day, ladies and gentlemen. Welcome to the Saratoga Resources Results of Operations for Fourth Quarter 2013 Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Manager of Investor Relations, Brad Holmes. Please go ahead.

Brad Holmes

Thank you, Charlotte. Good morning, everyone, and thanks for joining us for the year end 2013 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 Securities Act of 1933 and the Securities Exchange Act of 1934, which are intended to be covered by the Safe Harbors created there under.

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 CEO of Saratoga Resources. Tom?

Tom Cooke

Good morning, and thanks for joining us as we discuss the financial results for year-end 2013, and provide an operations update. I'll begin by providing management's high-level view of operations and then Andy Clifford and John Ebert will discuss our operations and financial results and financial position in more detail.

In 2013, we saw some exciting developments for Saratoga as well as challenging issues in the field operating level. The net results of such developments were disappointing in financial performance for the year, but we believe tangible progress has been made in addressing difficult and lingering issues in the field which we expect will allow us to improve runtimes in the field and renew, stable and growth production levels.

Highlighting our efforts during 2013, where the drilling of our first horizontal Rocky and our first triangle well Zeke, 2013 also saw success in lease acquisitions with the addition of 19,814 acres in the Gulf of Mexico, including four identify prospects containing 2.7 million BOE of approval reserves an additional 1,070 acres in state waters in Louisiana, including two prospects containing 763,000 BOE of proved reserves.

As expected, Rocky and Zeke wells delivered superior results in terms of initial production and anticipated recoveries as compared to our historical directional drilling. With that success, we are focused on pursuing additional horizontal wells and have identified a number of potential horizontal targets with additional prospects being evaluated. Andy will discuss our plans in more detail shortly.

Relative to our Gulf of Mexico properties, we have recently completed shallow hazard 3d surveys over each potential drill site as a first step towards getting our initial wells permitted, and we will begin our efforts to seek joint venture partners with first drilling expected later this year.

We are excited about the number of additions to our professional staff as well as personnel changes in the field. We are seeing positive results from these additions in terms of field performance and prospect analysis, selection, and planning, we expect these additions along with other initiatives to result in ongoing improvements in the field and improved performance in our development drilling program.

I personally have spent substantial time in the field in recent months to observe first-hand performances and issues that have resulted in production being low, lower than expected levels. With the addition of gas lift supplies to meet our needs for the foreseeable future and personnel changes in the field, we are beginning to see improved runtimes and resulting stabilization and increases in production rates that we expect to see through our operating results for the second quarter in 2014.

With expected improvements in production and operating results and cash on hand to support our development plans, we are optimistic that initiatives taken in recent months will improve performance in 2014. We did experience a decrease of production in 2013, reflecting operational issues across multiple fields.

During Q4 and continuing into Q1 2014, we commenced the bottoms up review of field operations to diagnose and remedy field operating issues weighing on production. That review confirms some of management's original beliefs regarding operational issues in the field and revealed a few issues that were previously unknown. Most notable among those issues identified were an ongoing inadequacy of gas lift gas to support production in the field and certain personnel issues that have directly impacted runtimes.

In the second half of 2013, we estimated that we had $4 million worth of deferred production. As a result of our view, we focused much of our attention and workover program in Q4 and Q1 of 2014 on restoring gas production levels to provide an adequate supply of gas to support gas lift needs and have now added 2 million cubic feet of gas a day primarily for gas lift with some redundancy there, so we’ve got a little bit of overkill. We also have a gas buyback arrangement that kind of backstops all of those efforts. Our gas supplies have now increased to a level adequate to support our gas lift requirements. Additionally, we have ready projects that we are pursuing as we speak anticipated to bring 279 barrels of oil and 33 million cubic feet of gas a day online.

On the personnel front, we have made numerous personnel changes in the field and are continuing to evaluate performance of select personnel to assure that field personnel both have the requisite expertise and commitment to maintain optimal well performance across all fields. As result of increased gas lift supply and personnel changes in the field by late Q1 2014, runtimes in the field had dramatically increased and production levels have stabilized and begun to climb.

As for our operating results, we did report a loss for the quarter and for the year as a whole, with losses largely driven by decrease in production in addition to several non-cash charges totaling $11.7 million, each of which will be discussed by John later.

As we look forward to 2014, we see opportunities on our horizontal drilling focused program and development of our newly acquired Gulf of Mexico and Louisiana state leases to realize the value of our assets and grow production and profitability in a number of areas. We continue to be excited of our asset base and the potential of those assets which possess various attributes and are attractive to us including an undervalued asset base, continuing favorable LHS and HLS pricing.

Untapped or unappreciated opportunities, which are being high graded through acceleration of our full-field studies, potentially high-impact horizontal drilling opportunities, and attractive opportunities to participate in higher risk reward opportunities through JVs to drill deep prospects of Grand Bay and our newly acquired Gulf of Mexico prospects.

I will 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 he financial results. Then we will take your questions. Thank you.

Andy Clifford

Good morning. Thank you, Tom. As Tom mentioned, during 2013, our production was down 28% from 2012 levels to 803,000 BOE. The decline in production was driven almost entirely by combination of field operating issues resulted in unexpected downtime and decreased run rates in several fields.

The principal factors that impacted our production were gas lift supply issues that adversely affected production in Grand Bay and Main Pass 25 fields, Flowline restrictions and facility repairs in Main Pass 46, third-party product handling issues and platform shut-ins due to construction projects in Main Pass 25 field, and disappointing execution by some of our field operating team.

While we continue to review the performance of our field operations team, we believe we have turned the corner in our field operations with the addition of gas lift supply as Tom mentioned as a result of recompletion of workover program in Q4 and the first quarter of this year, the completion of work on most facilities, repair work and with personnel changes in the field.

In fact, the recent recompletions in workovers during the first quarter 2014, specifically on the [Jericho] (ph) and #5 wells in Breton Sound 32 field and the QQ199 wells in Grand Bay field have resulted in an additional production of 2 million cubic a day in recent test results as earlier mentioned by Tom Cooke.

On a positive note, despite limited gas lift supplies, our oil production held up reasonably well declining 10.8% as compared to 54.6% decline in natural gas production, with oil accounting to 75.1% of our combined 2013 production. As Tom mentioned earlier additionally, the pricing continues to be strong in the LLS and HLS markets that we benefit from.

Year end 2013 reserves reflect production of the 803 MBOE during the year as well as the addition of 3.5 million BOEs of proved undeveloped reserves associated with the acquisition of new leases in the state waters of Louisiana and in the Gulf Mexico and the reclassification of 2.439 million BOEs of reserves out of the proved undeveloped category to the P90 probable category pursuant to the SEC five-year rule, wherein reserves cannot be maintained in the proved undeveloped category for more than 5 years. The reclassified reserves in question were primarily gas and are associated with leases held by production.

The re-categorization does not affect our prospect inventory or resource potential, but instead reflects our conscious decision in the light of low natural gas prices to move those predominantly in natural gas projects back in our development plans in favor of more economically attractive oil predominant projects. It should be noted that additional reserve or loss under the five-year rule may echo in 2014 and future years based on our development schedule, but those P90 reserves may be reinstated to the proved category in the future for no additional CapEx.

Proved reserves at year end totaled $17.24 million BOEs, 53.6% of which was oil, with the PV10 of $410.8 million, using SEC pricing adjusted for quality and location for average realized pricing of $108.64 per barrel of oil or $4.35 per MCF and natural gas. This represents a marginal increase over the company's year in 2012 proved reserves of 17.23 million BOEs, of which 48.8% were oil.

In addition to proved reserves, year-end 2013 probable reserves totaled 16.8 million BOEs, up 25.7% from 2012, 40.9% of which was oil, with a PV10 of $306.5 million. Of these probable reserves, 2.44 MBOEs of the P90 probable undeveloped reserves mentioned as we categorized from the proved category into the five-year SEC rule. The P90 probable undevelopment reserves are 84.4% gas, with the PV10 of $26.1 million. Possible reserves as of December 31, 2013, totaled $39.7 million BOEs, up 15.8% from the $34.3 million BOEs at year-end 2012, 47.8% of the possible reserves of oil, with a PV10 of $658.4 million.

In summary, total reserves including proved, probable and possible as of December 31, 2013, were $73.7 million BOEs, 47.6% oil, with a PV10 of $1.38 billion. We are pleased, we managed to maintain our reserve totals with 2012 levels of the production and despite the re-categorization of 2.44 million BOEs of proved, undeveloped reserves due to the SEC five-year rule.

The proved reserves associated with our new state and federal leases acquired 2013, more than adequately compensated for the re-categorization of the proved reserves to P90 probable. More satisfying to us is the 4.8% increase in proved oil versus gas reserves. The 9.8% increase in PDP reserves, the 1.3% increase in proved developed results, 25.7% increase in probable reserves, 15.8% increase in possible reserves and our year-end net asset value per share in excess of $8 for proved reserves alone.

June 2013, we drilled four successful development wells, the QQ-209 Buddy well in Grand Bay field, the QQ-25 Roux 2 well in Main Pass 47 field and the state lease1227 #24 Rocky and state lease 1227 #25 Zeke in Breton Sound 32 field. As Tom mentioned earlier, the Rocky well was our first horizontal well.

We also undertook 22 recompletions and 10 workers during the year, 17 of the 22 recompletions or nine of the 10 workovers were successful. I would also note, our success in acquiring the 212 acre Little Bay lease of the Louisiana state lease sale in November, with proved developed non-producing reserves of 254 MBOE. The lease is of three-year primary term and includes acreage previously operated by Saratoga and the state lease 5097 1 well is temporary abandoned by Saratoga pending deployment of a workover rig. The third quarter 2013 release of a formal operating agreement of Little Bay lease was the source of non-cash impairment charge to earnings of $2.2 million in the third quarter that we previously reported.

Looking forward, near-term development plans are focused on proved undeveloped opportunities and conversion of the PDNP opportunities. We have been contacting potential contractors and gathering necessary data to undertake detailed reservoir simulations of Breton Sound 32 and Grand Bay fields. These studies will support our future horizontal and high angle development well planning.

At December 31, 2013 an exhaustive review of prospects was underway to identify and prioritize and bring forth the most promising prospects. With added depth and quality of professional staff we have identified an intent to focus development drilling plans on approval of high impact prospects.

We expect to spud our next horizontal well, state lease 1227 #29, Rocky 2, offsetting the first Rocky well, which is still performing well, in a couple weeks utilized in the Parker 77B barge rigs. We are excited about this well. We are also preparing to undertake a number of significant recompletions of workovers, utilizing (Inaudible) barge rig. As Tom mentioned, we expect this next phase work to add $279 barrels of oil a day and 3.3 million cubic feet of gas a day or net 624 BOE per day.

Present development plans expect to be similar to those undertaken during 2013, in terms of both, number of wells and CapEx. In order to advance development plans with respect to our inventory of deep and ultra deep prospects, including advancing discussions with potential partners beyond general discussions, we have additionally tossed out our expanded professional staff for developing exhaustive analyses and marketing materials to support full professional marketing plan to identify and secure potential drilling partners. Those efforts are expected to lead to commencement of a formal marketing plan to potential partners during the second quarter of this year's, principally focused on our recently acquired Gulf of Mexico leases and our Goldeneye prospect in Grand Bay.

With that, I will turn the call over to John Ebert, our VP-Finance and Business Development, to discuss the financials.

John Ebert

Thank you, Andy. 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.

As Tom mentioned in his opening remarks, overall performance in 2013 was disappointing and resulted in a net loss of $26.4 million or $0.85 per fully diluted share. Our net income was negatively impacted by non-cash charges of $11.7 million or $0.38 per fully diluted share relating to our deferred tax asset, impairment and hedges charges, which I will discuss later.

Oil and gas revenues for 2013 were $68.7 million, down 16.7% from 2012. For the fourth quarter of 2013, oil and gas revenues were $14.5 million, down from 36.7% from the fourth quarter of 2012. The decline in oil and gas revenues for both, quarter and full year, was directly attributable to the field operations issues discussed by Tom and Andy, which resulted in a 28% decline in production volumes for the year.

We had discretionary cash flow of $9.1 million or $0.29 per fully diluted share in 2013, compared to $29.3 million or $1 per fully diluted share for 2012. For the fourth quarter, discretionary cash flow was a negative $700,000 or a negative $0.02 per fully diluted share, compared to discretionary cash flow of $9.7 million or $0.31 per fully diluted share for the fourth quarter of 2012.

Our EBITDAX for 2013 was $28.7 million, down 37.2% from 2012. Both, discretionary cash flow and EBITDAX were adversely impacted by the production declines discussed and the resulting reductions in revenues.

Operating income for the year was down to $3.7 million from $12.3 million in 2012. The decline in operating income and profitability for the year and fourth quarter, reflects the substantial declines in production volumes, together with heavy losses of $1.7 million and impairment loss of $2.2 million and the tax provision of $8.6 million as a result of our fully reserving against our net deferred tax asset. These were all non-cash items.

The hedging loss for the quarter and year included $1 million non-cash charge attributable to the failure of certain hedges to satisfy U.S. GAAP requirements for correlation between product pricing and benchmark pricing. The impairment loss was a non-cash charge related to the expiration of a Little Bay lease, which Andy discussed, which was required to be recognized under GAAP. Despite the fact that we re-leased substantially the same as acreage recouping substantially all associated reserves shortly after the lease expiration at a cost of less than $100,000. The tax provision reflected the determination to fully reserve against a net deferred tax asset and the amount of $13.8 million. Net operating losses totaling $73.9 million will remain available for use against future taxable income.

For the full-year, the decline in operating income and profitability was partially offset by decline in operating expenses, reflecting among other things decreased workover expense, down $1.4 million or 35.3% as a result of decreased workover activity, decreased loss on plugging and abandonment, down $1.8 million or 71.6%, reflecting a lower level of PMA expenses in excess of estimates during 2013, lower depreciation, depletion and amortization expense, down $10.1 million, or 37%, reflecting lower production volumes during 2013 and decreased severance taxes, down $0.5 million, or 6.4%, resulting from lower production volumes, all partially offset by increased lease operating expenses which was up $2.4 million or 12.3%, reflecting one-time non-recurring expenses associated with the salvage of a barge in Little Bay, regulatory compliance charges relating to Grand Bay and cleaning of a flowline in Main Pass 46, increased exploration expense, which was up $400,000 million, or 64.5%, reflecting increased delay rentals associated with the acquisition of the Gulf of Mexico leases and field study expense in the Gulf of Mexico and Grand Bay.

Increased accretion expense was up $1.0 million, or 69%, reflecting an upward revision in asset retirement obligation recorded during 2012, and increased general and administrative expense, up $700,000 million, or 7.8%, reflecting increased contract and reserve engineering fees, legal costs and employee recruiting fees, which were partially offset by lower stock based compensation and bonuses.

From a financial standpoint, we were successful during the fourth quarter and refinancing portion of our existing debt and adding liquidity to support our development plan. The refinancing allowed without payment of any prepayment premium otherwise applicable to existing debt to lower our interest rate on $27.3 million of outstanding debt from 12.5% to 10%.

The fourth quarter refinancing also brought in $27.3 million of gross proceeds, effectively taken the place of our revolving credit facility which we had previously sought, but with much more favorable covenants than we would have expected under our traditional revolver. The notes issued in both, the new financing and the refinancing are redeemable by the company at any time without a prepayment premium, enhancing our ability to refinance our debt in the future.

Supplemented by proceeds of the 2013 debt offering, we had $32.5 million of cash on hand at December 31, 2013, and expect to fully fund our 2014 development budget through cash on hand and projected operating cash flow. For 2014, CapEx budget is expected to be roughly equal to that of 2013.

We continue to take substantial steps to minimize our exposure to commodity price risk with the establishment and maintenance of the hedging program. To-date, our hedging program has focused solely on our oil production, but we continue to monitor opportunities to layer in some gas hedges.

As of December 31, 2013, we had 90,000 barrels hedged on a fixed-price Brent-based swap averaging $107.19, the last of which expired on March 31, 2014. Subsequent to year-end 2013, we hedged an additional 45,000 barrels on a fixed-price LLS based swap averaging approximately $105.68.

During the second quarter - which will be through the end of the second quarter 2014, we are continually looking at hedging market and plan to layer in more hedges for 2014 and beyond as we deem appropriate. Although results in 2013 could have been better, our assets have considerable potential with the net asset value of $8.11 per share. We feel, we have a handle on and are addressing the issues that impacted our results during the past year and build upon the drilling success at Rocky and Zete to realize the overall potential value of our assets.

With that, I will turn the call back to Tom.

Tom Cooke

Thanks, Brad, Andy and John. We will just open it up to question.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question will be coming from the Line of Noel Parks from Ladenburg Thalmann. Your line is open.

Noel Parks - Ladenburg Thalmann

Good morning.

Tom Cooke

Good morning, Noel.

Noel Parks - Ladenburg Thalmann

To start with, in the press release and in your remarks you talked a good bit about field personnel changes and issues. Could you talk a bit more about that, and I was trying to get a sense of whether any of those pertain to the, I guess, you had sort of limited operations on the offshore Gulf properties that you acquired about a year ago or was it more on your sort of traditional, your legacy projects that you’ve had a long time?

Tom Cooke

Noel, there were no operations going on to speak of. It's all technical and we’re actually doing the 3-D surveys for hazard gas, all those things were in preparation for the drilling of the GoM leases, so this pertains to the legacy assets and operations, lack of gas lift supply, just execution, and we have taken that very seriously, and we are already starting to see that turnaround dramatically.

Noel Parks - Ladenburg Thalmann

It sounds like you actually put some concerted effort into looking into the issues out there. Roughly when did your, I guess revisiting of the field issues begin?

Tom Cooke

Well, I mean there has been issues that just puzzled us relative to performance. Obviously, when you start to see the impact of fields being shut-in, because of lack of gas lift, some of which was just planning and some of which was execution and reporting relative to the problematic projects.

From the bottom up, we go into it and start looking at execution and realizing that execution was very poor, so we have made the changes necessary there. It's is still an ongoing effort, but we are almost back to where we were.

In six months, we lost 37,000 barrels, the last two quarters of the year last year due to gas lift alone. Now if they’ve lost,. it's deferred production, but needless to say it impacted our gas lift. That carried over into the first quarter and we have really started to turn that around about March, 1, and that was concurrent with replacement of a lot of personnel in the field, so we feel like we have got a handle on it. We are a little bit ashamed in fact that it caught us by surprise, but I can tell you that we are completely dedicated to resolving those issues.

Noel Parks - Ladenburg Thalmann

Okay. Actually, Tom, at the end of your remarks, I just missed the numbers that you said.

You mentioned that you are anticipating now bringing - there was a certain volume of gas and certain amount of oil production online fairly soon? Could you just repeat what those figures were?

Tom Cooke

Well, what I said is in the last six months of last year, we had deferred production of about 37,000 barrels net for the company, and those losses continued on until the first quarter of the following year. We have since been able to - we focus on our gas lift gas and we have added 2 million cubic feet of gas to the system, so currently I can say all our fields are up and running, but individual wells are still shut-in, and there's other bottlenecks that we have been working on like water disposal systems and due to mistakes in the field, oil carrying over into water disposal wells causing those wells need to be reworked and treated and a lot of stuff like that, but we've got, I guess, on our plate right now here in the near-term ready projects. We have got anticipated production of 279,000 barrels of oil and 3.3 million cubic feet of gas per day -- 279 barrels a day, and 3.3 million cubic feet of gas a day.

Noel Parks - Ladenburg Thalmann

On a gross basis?

Tom Cooke

Yes. The BOE is 624.

Andy Clifford

On a net basis.

Noel Parks - Ladenburg Thalmann

Great. Just one last one for me. I heard in the financial overview, there was a mention about, I guess NOL - I assume carry forwards that have been moved to reserves, but it sounded like most of them were still intact. Could you just explain a little bit about that?

Andy Clifford

I guess, on our – we have booked an asset, our deferred tax asset, we had booked roughly $13.8 million as an asset. Now this is on a book basis. After having two consecutive years of losses, we decided to reserve against that asset, and so it hit income on a book basis, but on a tax basis we continue, we will be able to use those historical losses. Just on a book basis, they've been taken on the income statement this year reversing that asset and putting that as an expense against income this year, so the asset, the tax benefit remains intact on the tax basis. It just doesn't on a book basis.

Noel Parks - Ladenburg Thalmann

Thanks. That's what I was looking to understand.

Tom Cooke

It was a non-cash charge.

Noel Parks - Ladenburg Thalmann

Great. That's it for me. Thanks.

Operator

Thank you. Our next question will be coming from the line of John Polcari from Mutual of America. Your line is open.

John Polcari - Mutual of America

Good morning, gentlemen.

Tom Cooke

Hi, John.

Andy Clifford

Good morning, John.

John Polcari - Mutual of America

It's been a number of years now, where you have had considerable proved reserves that you obviously had difficulty developing and producing. It's gotten to the point where, as you mentioned in your opening remarks, actually moving proved reserve categories back to probable because of the limitations imposed by regulators, this has been an ongoing issue for quite some time.

Other than remarks, you've addressed regarding field personnel, what exactly is the issue? Can you speak to what the key problems have been or the challenges that you have found over the last at least two years, moving assets into the developed and producing category is it more than just a temporary bump in the road?

Andy Clifford

John, this is Andy.

John Polcari - Mutual of America

Yes, Andy. Go ahead.

Andy Clifford

There are several points in what you are saying. I think, one is every public company has got the SEC five-year rule and everyone had the same issue of them moving off the books, and here EPL, energy 21, all the companies mention it. In a lot of the companies, it's also about year-on-year reserve growth, and a lot of it is hidden in the fact they are making acquisitions and is all buried in the weeds, so we have managed to maintain the reserves to lease acquisition and adding replacement reserves without making any corporate acquisition, so that's one aspect of it.

Obviously, our game plan always has been and will continue to be converting the undeveloped reserves to develop reserves and the probables to PDPs and PDMPs. I mean, nothing has changed in that regard that's what we wanted to continue to do and most of the wells we have done. Almost all the wells we have done other than one or two over the last four, five years of it successfully converted reserves and also we have been trying to replace declining production which is everyone has declined. We don't think we have naturally - we have any more than about 7% or 8% decline in our wells, in our fields, but what we think we would have been suffering from, which gets to another point you are making and which Tom alluded to was field related issues.

We think we have kind of inadvertently lost in reserves or that moved back to undeveloped because of some field maintenance issues. You never know if it's a technical or an operational issue if a well has a problem, if it goes off making gas or oil, you have to analyze that. We continue to do that weekly on a number of wells, but not all of our wells, North Tigers and Rockys and Catinas and full corners of being continue to be very successful wells and a lot of the issues we are wrestling with, have been wrestling with have been field related issues and I can let Tom talk a little bit more about that, but a lot of our legacy stuff, we are wrestling to try and make sure we have surplus gas lift gas redundancy and that we had a very well which kind of gave [the] after making about 30 to 35 BCF a gas, and didn't have sufficient fallback.

Another well we had some issues to get coiled tubing out one of our big gas lift wells in Breton Sound 32. Too heavily rely on one or two gas lift producing wells in our fields and we normally have that happen again.

Tom talked about the gas buyback, talked about having some redundancy, so in each case we have made sure that we have got some redundancy, be it at the last resort relying on a third-party to provide that gas that gas to us, but even better when you got your own wells, so you can even turn to, so we have made strides particularly this first quarter, starting late last year and first quarter to make sure that we have surplus of gas lift gas when we need it to float with our boats to make all the oil wells flow and the many of the projects when we look to them historically, economically to do a gas recompletion or to drill a gas well in a traditional sense isn't very economic, because you don't want to choke that gas back, so you want to produce at a 2 million a day, you want to produce at 200 MCF a day for [gas], so it doesn't have the traditional economic parameters that would look for, so in the past I think we have realized that last year we preferentially oil projects and even one of our gas recompletions, turned out to be oil, but doesn't help the gas lift situations, so I think we have got on top of that now, but getting back to the first point that we need to continue to convert our reserve base and I think going the joint venture route, which we are planning to do is really…

John Polcari - Mutual of America

That's where I am heading. I appreciate that. I understand the corporate strategy obviously to move proved reserves into the developed category, obviously make as many PDPs as you can. I am wondering what would it take to accelerate that process to be blunt, to pick up the pace a bit?

As we stand now, I am hearing issues as the gentlemen mentioned about field issues. Was that a major impediments that now that that's behind us, we can look for production to start ramping up. I mean, this quarter, you said you resolved a number of the issues as of March 1, so two-thirds of the way through this quarter with somewhat impeded if that's not correct please say so, but can we look forward to the second, third and fourth quarters which we commence today, beginning a long stretch of ramp up or are there other impediments that still have to be addressed? Is it a lack of adequate financing to hit all the well at a more accelerated basis?

Tom Cooke

Let me jump in. You know, we took a careful approach to it knowing that we had problems that needed to be resolved and we looked at it from G&G, we look at from the engineering, we look at it from operations and field operations, so we have hired another geologist to beef up that area to try to give us a more comprehensive understanding from the G&G side. I mean, we are looking at where we are perforating these wells, we are looking at how we are perforating these wells, we are looking at how much of the zone where perforating to be able to optimize and recover, because we have had a few things that were surprises, but the overwhelming biggest impact has been lacking gas lift gas, the cost now it's - I can't say that's the only reason, but the answer to your question is, we do feel like it's turnaround.

Right now, we still have some wells that are shut-in, because we have to rework our water disposals system and we spend some money relative to that. Operationally, there were issues that came in and undermine that. We cleared the deck on that one and we are going to continued to clear the deck until we get to the core root and completely resolve those issues, but we are starting to see the production ramp up and we believe that we will continue to see that trend and there are some bottlenecks, but they are not very expensive to resolve. They are the less expensive things to resolve.

I think to accelerate the drilling and development and to have more impactful wells, I think you'll see that bind through the joint ventures, where we are sharing some of the risk on more expensive, more high-impact wells that we are excited about.

We continue to get good feedback on Goldeneye for instance. We have challenged ourselves from top to bottom, because we want to make sure that coming out of the shoe that we don't stub our toe on that, but it continues to look better to us and Andy will have that thing cleaned up ready to go out on a former marketing agreement. We have got a nice long list of people that are interested.

We just haven't gotten down to put that in front and showing it to them, but I think that's one of the ways we are going to approach the acceleration. We have an adequate capital to drill, four wells this year and do workovers in the field that we are going back and we are reexamining the workovers and the ones that we prioritized from the past, so one of the problems is simply when you go in and you are completing a zone that's only got 250,000 MCF and reserves in it. It's hard to justify doing a gravel pack and the inclination in the field is this to try to pull that well to try to make the economics look better on it when it's truly just the gas supply well for our gas lift.

When I mentioned 2,000 MCF a day, those are very restricted rates, where we have taken a different approach where we are not - while we had ample gas supply, we are looking at how we produce the wells and to see if we should have restricted the flow to make sure we had gas, because we got a lot of gas reserves and we have got a lot of go-to gas and we have got some high impactful gas wells that we can drill when we see gas prices could improve and they have made some improvement. As John said, we will continue to look at hedging even gas as we see gas prices improved, so it's kind of an all of above strategy. It's bottom-up and top-down.

We are examining everything that we have been doing and how we have been doing it and we are beefing up our engineering group and the G&G group and we have made changes in the field, so it's we have got to take the blame.

John Polcari - Mutual of America

Let me ask you, we have a 24-month of gas lift that's $4.25 quarter and we seem to have moved at least in my opinion to a permanently higher level as modest as it is. Are you comfortable with this level and I don't mean, would you like more. Who would not? But, at $4 to $4.25, I would say $4 to $4.50 range. Are you comfortable attacking your gas reserves?

Tom Cooke

Well, as far as hedging or drilling, we feel like the gas projects that we have that are impact for high volume gas projects, we are going to get some of that with Goldeneye, so you know we are going to be in that market and we will probably hedge accordingly, but that's very rich gas, so it's high liquid content, so it's kind of the best of both worlds.

Andy Clifford

Gulf of Mexico was once too.

Tom Cooke

Yes. The Gulf of Mexico as well as Andy said, so we are already starting to move to our gas projects, but not 100%. We are still being cautious as we approach the gas-heavy prospects.

John Polcari - Mutual of America

We have seen inflection point, where you would be willing to get very comfortable with gas. If it's not $4, is it $4.50, is it $5? What's the?

Andy Clifford

It's correct, John, over $4, $4.25, $4.50, but it's still a bang for the buck. If you look at things in a 6:1 ratio, I mean, you are still better of spending $1 on a return basis on an oil project than in gas at those prices, but that's certainly much more interesting to look at, so I think the only ones we are really looking at seriously are Goldeneye and the Gulf of Mexico projects, which hope to be big gas producers with long liquids, lot of oil and condensate associated with it, but I don't think we'll start moving up really '16 and Main Pass 46 gas prospects just the other well.

John Polcari - Mutual of America

On that oil side, you have the formal data room open, how did you go about this and when do you think you would have at least some MOUs, with a partner?

Andy Clifford

First, Goldeneye, we are really just putting all the documentation together now, gathering until we are happy. We probably have a dry one for ourselves next week and then hit the market with that. I mean, I would certainly love to get Goldeneye drilled…

John Polcari - Mutual of America

I mean, if you open up a gathering for anybody or how have you gone about this for your future prospects one-on-one.

Andy Clifford

Yes. We are not doing a data room or we are not - We will have data available, but it will all be online, but now we don't think we have got to go to a broad marketing effort. It's going to be targeted. There is enough interest in these prospects. There are a little bit of hodgepodge, but GoM is a little bit different than Goldeneye. Goldeneye, we have been talking about for two or three years and it holds up and it's held up in all the analysis that we have done subsequent to it.

Tom Cooke

The GoM ones, we will have to wait for the Central Gulf of Mexico lease sale, which was two weeks ago to get past us, because all the interested parties were preoccupied with that sale, so now that's behind us. That [seller] has its surveys done, where we are re-launching full steam with that.

John Polcari - Mutual of America

Give me your best estimate. When would you think you would be able to have some initial JV, or at least another MOU without actual formal agreement, just we've actually got - at what timeline do you think you would be able to hit?

Tom Cooke

Well, other than the GoM leases that which are term leases with the Fed, the Goldeneye, for instance, in those deeper projects are all HBP. It probably wouldn't be wise for me to give a specific timeline, because they are HBP. We are starting our efforts and we hope to be drilling in both by the end of the year and that's really all I feel comfortable disclosing.

John Polcari - Mutual of America

Okay. All right. That's it. Thank you, gentlemen.

Tom Cooke

Thank you, John.

Operator

Thank you. Our next question will be coming from the line of Hassan Ahmad from Imperial Capital. Your line is open.

Hassan Ahmad - Imperial Capital

Hi, guys. Just one quick question for you, what's the value of the PDP [tender] value, I want to see what the value of the PDP is.

Andy Clifford

You have it?

Tom Cooke

[Hold on] Hassan.

Hassan Ahmad - Imperial Capital

Okay. No worries. I guess, while I got you, what's sort of the plan on the horizontal well? I heard you guys speak to it, but just want a little more clarity on timing and what have you guys kind of seen from the existing horizontal wells that you drilled in the past 12 months in terms of like decline rates?

Andy Clifford

Yes. Good results. I mean, I think, there was perception out there that because we stopped drilling up after Zeke, we were planning to go to Charlie, and we kind of reengineered Charlie for another target, so we held back and our lack of continuing to drill wasn't aimed to do with disappointing results or lack of cash to keep drilling. It's basically, where we in turn redesigning our wells and instead of doing a lot of the fault traces and adding infill wells in Grand Bay, individual reservoirs you are talking 50 to 100 MBOs and you are stacking them up and they are good from conversion, but at the end of the you are going to like a 70 barrel a day well once it steadies out.

We decided, we wanted more horizontals and high angle wells in Grand Bay as well as Breton Sound 32. Now some of that design of those wells is going to wait for the results of reservoir simulation, where we think we have got a lot of un-swept oil in many of these reservoirs, but they are doing well. I mean, Rocky's last test was doing over 200 barrels a day 90 MCF a day, so hanging in well on unrestricted choke. Zeke, we are doing some testing on it and we had to treat some and emulsion in that well, but they are doing very well.

As I said, we are finalizing a contract with Parker in the next few weeks to do Rocky 2. Actually, with only Rocky 3 internally, because there is another Rocky 2 kind of track as well, but we decided there Rocky 3, which is really extending the ridge. A decent part of that Breton Sound 32 to the east and we are very excited by that, but we are going to use runways drillbit this time, so we can actually log at the drillbit. We never do PUD a hole like we did with Rocky. We think we can get the drilling completion cost significantly by $2 million, so I think we did the wells, Zeke and Rocky for about $5 million to $7 million a piece, but that was with some lightening strike and doing pilot wells and all sorts of thing, so we think currently Rocky AFE is $2 million than we did Rocky 1, but we think we can get substantially under that too, so we got a lot of opportunities for horizontal drilling and not always horizontal. Zeke was 82 degree angle well. Basically just about increasing [interval] in your reservoir. In terms of the horizontals, 300-foot is probably sufficient over lateral length, anything between 300 or 1,000 feet and the to get the horizontal portion of the well.

Tom Cooke

Well, the reason we did those two, one of them high angle and one of them horizontal is even though there were good historical evidence on the horizontal being getting higher rates and higher recoveries, we wanted to see what the effect of just doing a high angel well.

There wasn't a lot of monetary benefit. It wasn't any cheaper and the results certainly aren't any better. In fact, I think, ultimately you are going to have higher recoveries in the two horizontal, so specific to that 5,800 foot sand, we have learned a lot and we anticipate that we will get a whole lot more information from the reservoirs simulation studies that we will be undertaking, so I think that these wells performed true to expectations.

Now, one of was drilled through the section with water and the other was a oil base and we see a difference in those two. We have had some emulsion issues and seek, because we think because of the old base completion technique, so we learned something about it and we think that we can treat that well and that get it up to expectations, but early analysis is horizontal looks better than high angle at least from the 5,800 foot sand and Rocky 2 that Andy referred to will be a horizontal well and we should spudding that well within 30 days.

Hassan Ahmad - Imperial Capital

That's it besides the PDP.

Andy Clifford

Yes. That's on the SEC PV10 of our PDP is $126.2 million.

Hassan Ahmad - Imperial Capital

Okay. Great. Thank you so much guys.

Operator

Thank you. Our next question will be coming from the line of Owen Douglas from Baird. Your line is open.

Owen Douglas - Baird

Hi, guys. Thanks for taking my question. I wanted to better understand a little bit, you mentioned there were few production problems in 2013 that severely impacted your production, what were the timing on those, because I think I see that the daily rates were falling throughout 2013, so wanted to better understand how you guys approach that and how do we get to where we are today?

Tom Cooke

Well, some of it was just natural decline obviously and some of these wells just strictly underperform relative to than what we saw on the log, so if we go back and look at that, here again I think we've, also looking at the completion approach that were using, it is kind of an all the above, but production issues in the field are not be underestimated. It's something that you know hate to go in and start making changes, but that's what it took.

We continue to see problems bring - Main Pass 25 online. I can go on and on. I really shouldn't say a lot more than that, because it's an ongoing process but it's something that we have seen we can go back now and start to identify the impact and I had spent more time in the field personally trying to get a handle on this and we have got consultants in the field now as well so.

Owen Douglas - Baird

When did you guys bring on that consulting team and do that bottom-up analysis? When did you guys start that process?

Andy Clifford

I would just assume not say, but I think you'll see it reflected in the changes and that will be reflected in the production levels.

Owen Douglas - Baird

Okay.

Tom Cooke

In terms of the production, it really started to drop off mid last year, the later half last year really more dramatic and that was due to gas lift gas impact on runtime.

Owen Douglas - Baird

Okay. As I look at Q4 versus Q3, the daily production rates weren't - I mean, Q3 was down sequentially, but the production rates were not down that dramatically, but I saw that the Q4 unit cost, LOE cost, was up very significantly. Could you guys explain a little bit about what's that number and that LOE build?

Tom Cooke

I think in the fourth quarter there was definitely concerted effort in the field to bring back our gas lift, so there is more and more attention in detail in the field in the fourth quarter, which we probably haven't broken that down in any great detail yet, but there was obviously a very focused effort to bring their production back and gas lifts back in the fourth quarter and coming over into the first quarter and was probably why the LOE was up during the fourth quarter.

Owen Douglas - Baird

Are you referring to the cost of third-party gas lifts?

Tom Cooke

Just referring to the [attention] of people we have in field addressing the problems.

Andy Clifford

There's also tropical storm was effects in the fourth quarter too.

Owen Douglas - Baird

Okay. Now, in terms of thinking about the cost of third-party gas lift going forward to your LOE, how should we attempt to model that out?

Tom Cooke

Well, you should, because we are not using it. We just got it set up as a safety net. We are not using it, but we now have a contract and we have it set up in the event that there is any, for any reason an interruption, we have got an adequate supply as a backup, so as far as the cost of the gas on the buyback, it's probably about 20% higher than what we sell it for. Keep in mind, on gas lift gas, you are recycling the gas, so you have to have gas chart system. It's not like you burned it. You have some loss, but not a lot.

With, what we are doing now, we are hoping in short-term with the additional 3.3 million cubic feet coming on along with the 2 billion cubic feet that we have been able to reestablish or bring on through behind five recompletions at fairly low cost, we should have adequate gas supply, or even get to the point, knock on wood, that we could sell some gas. We are selling a little bit, but not - we are keeping it pretty choked back, so we are sure that we don't have an interruption.

If you start to look at what MCF of gas and the value of an MFC of gas to lift one barrel of oil is, it's like $300 an MCF, so it's precious to make sure that your gas lift is always available, because all of our fields and all of our wells at some point are going to go on gas lift, so without gas lift out here, we got a real sobering experience when we started seeing some of our key gas lift well go down concurrently, kind of almost - we had to really scratch our heads while we lost so much so fast from the same place, but we are addressing that as well, but I don't want to say much more than that.

Owen Douglas - Baird

Okay. Now, you guys mentioned that you start to see some improvements, and I believe it's March. What is that relative to? These are relative to the quarterly results we have already seen or was that relative to the levels in the earlier portion of first quarter.

Tom Cooke

Runtime and gas lift and water disposable capacity, it's just blocking and tackling. Nothing fancy, no big recompletion. We did complete some gas zones that have been successful, but we are producing them very conservatively. It's just runtime really.

Owen Douglas - Baird

Okay, but in terms of thinking about production. I mean it sounds as though you guys are hoping to get back to that earlier portion of 2013 levels. When are you guys hoping to get that back online and what would it take to get you there?

Tom Cooke

Well, we are very close to the fourth quarter 2012 currently, but we've seen it dramatically ramp up just with the addressing our gas lift issues.

Owen Douglas - Baird

Really that's 4 to 12 when you guys were doing about 3,300 BOE per day?

Tom Cooke

No. I believe that the fourth quarter was, I think, 2,200 was our average for the year and about 1,850 is where we were in the fourth quarter.

Owen Douglas - Baird

Are you referring to 4Q '13 right and 4Q '12?

Tom Cooke

Yes.

Owen Douglas - Baird

Okay. I understand. All right.

Andy Clifford

…with gas lift being gone and that's , like I said that's being resolved and it dramatically increased concurrent with the replacement of personnel in the field.

Owen Douglas - Baird

I see. Now in terms of one of the prior callers that mentioned that you guys have a significant amount of proved reserves, which is true, and given that right now you have fairly expensive capital costs, how do you guys think about your ability to develop those assets either independently or using JVs versus then monetizing some of those assets through sale, the divestitures that allow you guys to improve your liquidity position and redirect capital to other projects.

Tom Cooke

I think, we were always looking for acquisitions probably more than we are looking to sell assets, but in the oil and gas business you are always interested in monetizing the asset, but you are not going to see us in the market trying to do so. When people come to us with an unsolicited offer and that happens from time-to-time, obviously when they see the production coming down, that's when they want to come in try to buy it, so you can't see us doing anything in the foreseeable future, because we believe in our assets.

Owen Douglas - Baird

Okay, and the way we would see arrangements, would this be JV arrangements where they would help cover the drilling carry in return for some of the economics and the output or you are thinking of a cash infusion into search of other resources. Can you walk through a little bit about how you think the JV agreement would work?

Tom Cooke

Well, I would be mistaken to even to even go into that on a conference call.

Owen Douglas - Baird

Okay.

Tom Cooke

You can assume that it will add the economic benefits to Saratoga Resources, because these are in HBP leases and we have got infrastructure, especially on the Grand Bay prospects, so you never really know how that's going to turned out at the end of the day, but no doubt we are looking for exposure to more wells as opposed to (Inaudible) rather than trying pull cash off the table, but cash is great, but that's not our motivation right now. We feel like that we are amply capitalized to continue our drilling and development program.

We think we have got to work smarter and we got to take a more comprehensive view on some of these things, some of the low-hanging fruit has not been quite as low-hanging as we would have liked for or two of them, so I have been instructed not to use that term. We think that there's plenty of opportunity here, because it's just so deep and that's one of the reasons that we are beefing up the G&G side and we have hired a geologist and will be bring on another reservoir engineer and John Ebert is reservoir engineer, but that's not his charge. He is more about evaluation and opportunities that we are looking at.

Andy Clifford

We hired two completion engineers to other completion engineers. I just want to mention one thing, when you look at our five, seven-year drilling schedule, it's always in our slides. You could see there's plenty of scope to JV and to - 100% of everything which is kind of unusual, but we don't have to dig into a PUDs to partner with people.

What we are targeting for the joint venture is a probables and possibles and our probables are SEC probables. In most cases, it's low pay, it's sizable cause which shows it hasn't produced that particular full block, very, very low risk probables. Here's the same thing from EPL, [21] from various other companies around us as well, but these low-risk probables that we can joint venture with.

Tom Cooke

Our success rate and our problem was as good as it is on the proven and this was third-party analysis.

Owen Douglas - Baird

Okay. Final question if I could. What drilling cost per well are you seeing currently or targeting?

Tom Cooke

It's different. We know it's we are not a single reservoir like in a resource play, where it's just repeatable. You know, it is repeatable let's say for Breton Sound 32 and the 5,800 foot sand, we are choosing between high angle and horizontal that we think those horizontal prices should come down just because of our experience level, so we think that we should be in and around $4 million for those horizontal wells.

We are not trying to set any drilling record as far as lateral extent of the wellbore. We then can we can do with 750 feet, the same thing we could do with the 1,000-feet. These are not frac. It's pretty much routine, we would like to get those prices down, but then you go move over in Grand Bay, where you got 64 stack reservoirs. It comes in every color. It's hard to characterize what a typical well cost would be.

Andy Clifford

The last well we drilled that was just over $3 million complete and we could have done that as a horizontal with an extra three days and done a horizontal [gravel pack] completion, but Goldeneye, you can have single completion, but Goldeneye you got to have 16,000 foot you are looking at the $10 million or more, but our range of well cost is $3 million to $7 million, so I think will see the same our participation than any one of these joint venture wells will be within that range as well, so whatever well we drill 100% ourselves or in JV, our net interest in any wells could be in that $3 million to $7 million range, probably the lower end $3 million to $5 million more alike.

Owen Douglas - Baird

Okay. Thank you very much guys.

Tom Cooke

Thank you.

Operator

Thank you. Our next question will be coming from the line of Joe Dancy from LSGI Advisors. Your line is open.

Joe Dancy - LSGI Advisors

What do you think is going on with the ultra deep wells that have impact us lately? I haven't kept track the last six months as to what other operators are doing. Can you sort of fill me in on that?

Tom Cooke

Yes. Joe. Good morning. I have stayed pretty close to some people in around McMoRan Energy XXI and I know that they are very excited by the success they have had - success over north, in the highlander prospect on the shore, where they have locked a 200 feet of pay section in the lower in Tuscaloosa and they were drilling ahead some more, but apparently they got coals with some liquids as well and good possibility and probability, so they are optimistic about that. That has impact, because we are at the same section in our Long John Silver prospect, also. Also people at McMoRan just forked out a few million dollars in leases adjacent to us at Long John Silver, just - last lease-out few weeks ago, obviously we still have strong interest there and I think Davy Jones.

We hopefully get some news in next few months on Davy Jones too, whether it's going to be - I think at Tuscaloosa, they are going to be trying to get that to flow.

Joe Dancy - LSGI Advisors

I was just curious, it sounds…

Andy Clifford

All these Lineham Creek to the northwest of us, I think that you got some section, shallower different section and they call that on the sidetrack well, so they are waiting on Chevron to development that.

Joe Dancy - LSGI Advisors

Okay. All my other questions have been answered. Thank you.

Andy Clifford

Thank you.

Operator

Thank you. Our next question will be coming from the line of Julia (Inaudible) from Stifel. Your line is open.

Unidentified Analyst

Hi. Gentlemen. If I could sort of rephrase the question of the prior caller. In your last call, I believe that you were able to say with regard to your potential joint ventures that you hope to retain majority interest and high level of revenue interest. Can you perhaps just comment on that and whether you think that is still the case with regard to the discussions you have had thus far?

Tom Cooke

Well, now that we are really getting in the marketing, I'd rather not go into any kind of detail relative to any kind of joint venture. We will participate to a certain degree on a heads up basis and then we will have a promote on a portion of the sale down, so without getting into specifics you know we are anticipating having 50% of the prospect.

Andy Clifford

Grand Bay is a little different and we would certainly want to have a controlling stake at Grand Bay, where we have the infrastructure, Goldeneye, where we would lease 50% maybe a little bit more than 50%. We've got Mexico leases, we aim to try and keep 50 % as those critical to us, but we like what we have there. If someone comes in and wants more then, we will make that decision at that time.

Unidentified Analyst

Sure. Thank you. That was the only question I had.

Tom Cooke

Okay.

Andy Clifford

Thank you.

Operator

Thank you (Operator Instructions). At this time, I am not showing any further questions. I would now like to turn the call back over to Tom Cooke for any closing remarks.

Tom Cooke

Thank you all for your time. As I mentioned, it's been challenging. I really feel like we are getting our arms around this and it is comprehensive and we are taking it very seriously and we look forward to a good year. We are going out of the shoe, we are kind of making a slow start. I am getting tired of saying that, but I can tell you that the production is coming back up and our one time is coming back up and our completion and production strategy has vastly improved, and I think with the new personnel that we brought in to give us a little more comprehensive view of it and I think we have got great things to look forward to and we can operate well within our cash flow and our available cash or cash position remain strong, so we think we are still here for the long run.

With that, I will say good bye. Thank you.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a great day.

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