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Saratoga Resources (NYSEMKT:SARA)

Q4 2012 Earnings Call

March 27, 2013 10:30 am ET

Executives

Brad Holmes

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

Andrew C. Clifford - President and Director

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

Analysts

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

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

Jeffrey Connolly - Brean Capital LLC, Research Division

Richard Safranek - Wafra Investment Advisory Group, Inc.

Richard Dearnley

Steve Emerson

Eric B. Anderson - Hartford Financial Management, Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Saratoga Resources 2012 Year End Results Operations Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the call over to Brad Holmes, Investor Relations. You may begin.

Brad Holmes

Good morning, everyone, and thanks for joining us for the year end 2012 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 Section 27A of the Securities Act of 1933, as amended, and Section 21E 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 belief as to the future results or events, such expectations or belief is expressed in good faith and believed to have 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?

Thomas F. Cooke

Thank you, Brad. Good morning, and thanks for joining us this morning as we discuss the results of operations for 2012. We will also discuss our current operations and take a brief look at what we expect to accomplish for the remainder of 2013. I'll begin by providing management's high-level view of 2012 operations. Andy Clifford and Mike Aldridge will follow and will discuss our operation and financial results and financial position in more detail.

Entering 2012, our focus was on production growth, while continually keeping an eye on opportunities to grow and upgrade our prospect inventory. To that end, in spite of some major challenges, we were able to grow production as our accelerated development program produced 18% growth in production volumes. Other notable achievements during 2012 included reinstitution of our hedging program to reduce our exposure to commodity price risk and the reinitiation of our field reserve studies to maximize and optimize drilling opportunities. However, as you may have noted from our earnings release, the progress we made in 2012 in accelerating our development program and upgrading our asset base was overshadowed in many regards by the effects of Hurricane Isaac. As we stated in our Q3 2012 conference call, the shut-in and production delays in completions and deferral of projects caused by Isaac had a material impact on production revenue, earnings and cash flow that is reflected in our year-end results. Combined with increasing operation cost reflecting investments and legacy P&A projects, increased workovers, increased investments in our development program and some reductions in our natural gas reserves, our bottom line results were not where we wanted them to be in 2012. Fortunately, our properties are resilient as evidenced by the relative minimal damage inflicted by the hurricane, and our dedicated team worked hard to bring all of our production back online by year-end and in resuming our development program. Despite the challenges faced during the year, we are encouraged by the gains made with our developmental program, which Andy will discuss in more detail. These accomplishments were highlighted by, as I mentioned, our 18% increase in production over 2011, our 8% increase in oil and gas revenues, our generation of $1 per share in discretionary cash flow and our year-end NAV per share of approximately $9 per share. What did not change is the inherent quality and value of our assets in South Louisiana. We have a high-value asset base again with approximately $9 per share net asset value, in proved reserves and a deep inventory of relatively low-risk PDNP and PUD conversion opportunities. We continue to believe that the quality and location of our properties reduce our development risk and promote operating efficiencies, as well as serving as a platform for accretive acquisitions. We are also positioned to participate in what we believe is an exciting ultra-deep trend with multiple exploratory targets already identified in the trend. These prospects are mature in their development and their analysis. We control over 32,000 acres in state and parish leases in shallow water of South Louisiana, and virtually all of our acreage is held by production. 25% of our proved reserves are proved developed, and we believe our properties hold substantial additional behind pipe reserves beyond the amounts qualified in the proved reserve categories and provide us with significant number of exploration prospects. We're positioned to add to that acreage inventory with the recent apparent high bids on 4 blocks covering 19,814 acres in the shallow Gulf of Mexico shelf. These water depths have a maximum of 77 feet and the shallow is 13 feet, so it's very compatible with what we've been doing in our current inventory. Andy will go into more detail on why this is a meaningful to Saratoga, and to our shareholders, but suffice to say, that we expect these leases to be immediately accretive and to add proved reserves at a favorable price.

Highlights of these blocks, which Andy will go into more detail on, as I previously said, shallow water in depths between 13 and 77 feet, up to 51 million gross BOEs of 3P reserves and 5.4 million gross BOEs as potential PUDs based on our initial estimates. Excellent prospect economics with lease bonus payments of $880,000 in the first year. These are 100% working interest, 77% net revenue interest leases as they will be coming to us.

Before turning the call over to Andy, I wanted to point out a couple of initiatives we have begun at Grand Bay and Main Pass 25 that we expect will supplement our production and profitability above and beyond our program of drilling recompletions and workovers.

At Grand Bay, approximately 20 wells have been identified that appear to be candidates for tubing replacement and resumption of production. These wells were all producing over 20 barrels a day and as much as 50 barrels a day when they were shut-in. The tubing replacement program involves mounting a pulling unit on the shallow water barge at an estimated cost of $200,000 per well. If successful for an approximate cost of $4 million, and up to 400 BOE or barrels of oil, this is primarily all oil, barrels of oil per day might be added to our production, representing a payout of less than 6 months.

We like to bundle these projects together to reduce the cost because the mob and the demob costs are a significant portion of the overall cost, so by doing these things -- you don't want to be doing these things on a knee-jerk or as they happen. You want to try to bundle these up. So we would like to have started this a little bit earlier, but we anticipate that to come to fruition by the end of the second quarter.

At Main Pass 25, we are undertaking efforts to both increase production and improve economics and also reduce dependence on third-party production handling. This is the only field where that situation still exists. We handle all of our production handling internally, and this will give us a little bit more independence in that regard and it will also lower our lease operating cost. In that regard, we successfully recompleted the 7,900-foot sand because of a need for gas lift gas. We had to get a permit from the state which caused some delays to co-mingle that well, but that will give us gas going forward. Now these efforts are just now starting to come together in our Main Pass 25.

We've got the sand that we did recomplete as showing excellent pressure and much resilience so the wells are now unloading and coming back on. Separately, we believe verbal agreements -- we have verbally agreed with a third-party operator to jointly upgrade our facilities and capacity at Main Pass 25 to accommodate handling of increased capacities, including production from a new discovery by that operator. As presently contemplated, the operator will provide an oil storage barge, a new separator and heater treater. And by upgrading our Main Pass 25, we expect to be able to bring our facilities production presently handled at the third-party facility. Lowering our monthly operating cost by an estimated $100,000 a month for this facility alone and eliminating our dependence -- our dependence from any third-party, and eliminating the bottleneck, which resulted in shut-in of the field during much of the first quarter of '13.

We expect that we will also be able to reduce line pressure that will give us some additional 200 barrels a day uplift while adding a potential source of additional gas lift gas and production handling fees.

I'll turn the call over to our President, Andy Clifford, to more fully discuss operations, after which Mike Aldridge, our CFO, will discuss the financial results, then we will take your questions, and I appreciate your time this morning. Andy?

Andrew C. Clifford

Thank you, Tom. Good morning, everyone. I'm glad to be able to say that in spite of the negative impact of Isaac, we were able to bring the majority of our production back on before year-end and we did some of the fruits -- we did see some of the fruits of our accelerated development program with production rising in 2012, despite being shut-in for an extended period following Isaac. We anticipate that 2013 will see continued production growth.

During 2012, we produced a total of 1.116 million BOEs, up 18% from 2011 production. 61% of our 2012 production is crude oil. During the year, we drilled and successfully completed 3 development wells. We had a fourth development well drilled and tested and awaiting completion at year-end for a total CapEx of $39.6 million. We also successfully completed 11 out of 12 recompletions during 2012 for total cost of $16.6 million and completed 16 successful workovers at a cost of $3.8 million.

We, like many other E&P companies, took a haircut on our reserves due in part to year-end 2012 crisis for natural gas. Our crude reserves as of December 31, 2012, is at 8.4 million barrels of oil and 52.9 billion cubic feet of natural gas, giving us a total of 17.23 million BOEs, which is down 9.2% from 2011 numbers. The vast majority of our reserve adjustment is from natural gas, which at this time is a relatively small percentage of our revenue stream and PV10 calculations. Crude oil represents 49% of our total proved reserves as we stand today, significantly up from 42% of the mix at year-end 2011. Gas reserves, and negative revisions to gas reserves, accounted for all of our reduction in reserves at year-end with our oil reserves being at -- with our oil reserves. Coming 25% of the reserve decrease and 177% of the negative revisions were gas, offset by net gains in oil and positive oil revisions.

It's important to note that gas pricing accounted for roughly 1/2 of our reduction reserves for the year with our 2012 SEC case reserves based on pricing of $94.71 per barrel of oil and $2.76 million BTU as benchmark pricing versus 2011 pricing of $96.19 per barrel and $4.11 per Mcf or 1 million BTU 2011.

Our average realized prices in 2012 were $110.06 per barrel and $3.36 per Mcf versus $106.51 per barrel in 2011 and $5.13 per Mcf. Now aside from pricing, the year-over-year changes in net reserves reflect the combination of production during the year, new reserve adds through the drillbit and revisions resulting from both drilling and field studies. For example, we had 950 MBOEs, 59% oil positive proved reserve revisions due to field studies of Breton Sound 32 and Grand Bay, plus a further 671 MBOEs in the probable and 348 MBOEs in the possible categories. We also had 517 MBOEs all oil positive proved reserve revisions due to drilling in North Tiger, Jupiter and Buddy, but offset by 2.637 million BOEs, 94% gas negative proved revisions due to thin sands and Mesa Verde at Vermilion 16. Now our field studies have continued to upgrade the quality of our reserves and replace more gassy reserves with more liquid-rich reserves, which are starting to be reflected in the 49% versus 42% oil mix. We expect this trend to continue. As an example, we've just identified a matte, a large new oily part opportunity in one of our Breton Sound fields, which we're quite excited about.

Now highlighting our development program during 2012, we had 3 successful development wells, the Jupiter, North Tiger and Mesa Verde wells and our Buddy well that was drilled during the year and awaiting completion at year-end, which we subsequently completed. The Jupiter well, for example in Grand Bay drilled to total depths of 9,688 feet, got 104 feet in net paying 15 sands. It was completed in August 2012 and tested at a net IP rate of 254 BOE per day. North Tiger well and Breton Sound 18 was drilled to a total depth of 9,300 feet and counted 59 feet in net pay in 6 sands and was completed as a dual in October 2012 after more than a month of delay following Isaac and tested at a combined net IP rate of 840 BOE per day. Mesa Verde well and Vermilion 16 was drilled to a total depth of 16,258 feet. The well is completed in October 2012 and tested at a net IP rate of 685 BOE per day. While Mesa Verde came in higher and thinner than expected accounting for the negative revision in reserves, the well did set up a sidetrack and numerous up hole opportunities.

Now let's look at some details of the full leases in the Gulf of Mexico where we were the apparent high bidder that Tom referred to earlier. These 4 blocks were all located in the shallower Gulf shelf with water depths between 13 and 77 feet. The combined -- the fall leases add 19,814 acres gross and net. Most important, our internal reserve estimates relative to these blocks as yet unaudited by third-party reserve engineers of 51.2 million gross BOE, of which we believe 5.4 million gross BOE will qualify as PUDs. We were attracted by the high liquid content of these reserves, which we estimate will exceed 8 million gross BOE and 3P reserves and all qualify by high-quality 3D seismic data and many of them were up dip from wells with log pay and production tests. Finalization of these leases remain subject to approval by BOEM, B-O-E-M, which we're hoping to receive during the second quarter and the several prospects already identified in the blocks. Lease bonus payments totaled $880,000. The first 2 rentals of $138,000. The price will be viewed very favorably relative to our estimate of resource potential for the prospects. The blocks include 100% working interest in each lease and will deliver a 77% net revenue interest. Our plan is to seek joint venture partners with first drilling not before 2014. These new leases incidentally, also potentially normally pressure target reservoirs shallower than 15,000 feet. With regards to the ultra-deep play that Tom briefly mentioned, we are encouraged by recent results announced relative to the shut-in operated line and creek well just 13 miles to the West Northwest on our Vermillion 16 acreage. I would note that the Mesa Verde well, in addition to adding production, further solidified our lease position in Vermilion 16 where we have a deep -- ultra-deep Long John Silver prospect sitting directly underneath it. We're looking at some more impactful wells this year including horizontal completions and deeper exploratory tells under our infield wells. New part development well opportunities added during 2012 include Rocky, at Breton Sound 32, a horizontal completion candidate and a 5,800-foot sand; Zeke, also in Breton Sound 32, another potential horizontal completion candidate; the Lilly well in Grand Bay with targets from the 19 Sand down through the 25, 30 and 43 Sands; and Nettawa [ph] and also in Grand Bay with 30 Sand objectives. Since year-end 2012, we have successfully completed the Buddy QQ209 well in the 3A Sand moving an additional 439 MBOEs, 70% oil, and drilled and completed the Roux 2 QQ-25 well, moving an additional 180 MBOEs, 34% oil from PUD to PDP. Other successful operations during the first quarter include the recompletion of the 29 M Sand in the Roux well and the recompletion of the 7,900 foot sand that Tom mentioned in Main Pass 25 field. The Buddy well in Grand Bay was drilled to a total depth of 6,820 feet and accounted 18 feet in net pay in the 3A Sand and tested at a net IP rate of 208 BOE per day, 97% oil. The Roux 2 well or QQ-25 was successfully completed as a dual completion with a net IP rate of 509 BOE per day.

Moving forward, during this year, we anticipate drilling up to 6 development wells, including our already completed Roux 2 well and in conducting 10 to 15 recompletions and workovers. Our total development budget for 2013 is approximately $40 million and is expected to be fully funded out of cash on hand and operating cash flow. Our drilling plans and budget are always subject to change based on our ongoing evaluation of well prospects, commodity prices, drilling results, field studies and other factors. With that, I'll turn the call over to our CFO, Michael Aldridge, to discuss the financials.

Michael O. Aldridge

Thanks, Andy, and welcome to those on the call. As in previous conference calls, I'm not going to go through the financials line by line, however, there are couple of things I do want to point out. The PV10 of our year-end 2012 reserves and our SEC case is $407 million and $443 million on the NYMEX case. As Tom mentioned, our NAV per share based on proved reserves alone is approximately $9 per share. As reported in third quarter and subsequent press releases, we took substantial steps late in 2012 and so far in 2013 to minimize our exposure to commodity price risk with the establishment of a hedging program. To date, our hedging program has focused solely on our oil production, but we're encouraged by recent natural gas price movements and are monitoring opportunities to lay in some gas hedges. We're continually looking at the hedging market and will layer in more hedges for second quarter of 2014 and beyond as we deem appropriate. For calendar 2013, we have hedged an average of 1,063 barrels of oil per day at an average price of $107.67. And for the first quarter of 2014, we have 500 barrels of oil per day hedged at $109.20 per barrel.

Regarding our financial performance during 2012 and financial position at year-end, I would note a few key takeaways. First, we were able to grow our production 18% and our oil and gas revenues by 8% from 2011, notwithstanding the effects of Hurricane Isaac. Unfortunately, the revenue and production gains were more than offset by an approximate 30% increase in operating expenses. The principal driver of the increase in operating expense during the year was an $11.8 million increase in DD&A associated with increased production volumes, additional investments in our development program, reductions in reserves previously discussed and an increase in estimated P&A expense. I would like to point out, of course, that DD&A is a noncash item although it does impact our net income.

On the positive side, we were able to reduce recurring LOE per BOE by more than 4%, and we continue to look at controlling costs and expect that some of the onetime events that negatively affected 2012 results will be behind us. While we no doubt faced challenges that hurt our operating results during 2012, we did manage to generate a respectable $29.3 million of discretionary cash flow or $1 per share during the year. Despite the operating challenges incurred during 2012, we ended the year in a solid cash position with $32.3 million of cash and $8.5 million in working cap -- positive working capital on hand at year-end, and we anticipate that we'll be able to fully fund our projected CapEx in 2013 from operating cash flow and cash on hand. With that, I'll turn the call back over to Tom for closing.

Thomas F. Cooke

Thank you, Mike, and thanks, Andy. As mentioned, it was challenging year overcoming the effects of Hurricane Isaac, the interruption in our production and the deferred drilling and development programs. Nonetheless, we remain excited about our holdings and we continue to view a substantial untapped potential from both development of our extensive inventory of conventional development well opportunities and the prospect of exploring our ultra-deep prospects at some time in the future and the prospects that we hope to gain once our GOM shelf bids are finalized. Again, I'd like to point to the success of our development program, and in spite of Hurricane Isaac, we produce an NAV per share of approximately $9, 18% production increase over 2011 and 8% increase in oil and gas revenues and a $1 per share in discretionary cash flow.

Finally, with reserve -- even though the reserves decreased, we booked net additions to oil reserves in 2012, and all in all, the reductions were in gas reserves. We were also optimistic about the potential to more than replace 2012 reduction through reserve additions associated with the GOM leases on which we're the apparent high bidder. Thanks for your attention, and we'll open it up for questions now.

Question-and-Answer Session

Operator

The first question is from Noel Parks of Ladenburg Thalmann.

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

Just a couple of things. For the upgrade in production facilities at Main Pass 25, do you have a sense of what the cost might look like on those you're pushing?

Thomas F. Cooke

Well, it's subject to the negotiations that we are ongoing where we do have a handshake agreement, but we haven't disclosed that. As far as the costs, they will be shared in part by a contribution of equipment. So I really don't want to get into putting up an exact number on that because it is in negotiations. Sorry, I can't go into it any further.

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

No problem. With the recompletion program you're looking at for Grand Bay, can you give a sense of what the incremental, I guess, maybe the fixed LOE cost or expense you think would come from that or on a per-unit basis once those all go online?

Michael O. Aldridge

Well, no, I just want to confirm, are you talking about the tubing replacement program of the roughly 20 wells in Grand Bay?

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

I'm sorry, yes, the tubing replacements.

Michael O. Aldridge

Yes, I mean, obviously that's going to be capitalized, I believe as far -- in terms of major equipment upgrade. And so I don't think that's going to impact direct LOE. Obviously, to the extent we increase production, that's going to reduce our LOE per BOE moving forward.

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

Okay. I didn't know if you just had maybe just sort of minimal electricity costs or something going forward that would kick in once those are online?

Thomas F. Cooke

No, no. These are all in field amongst a lot of other producing wells. The facilities are all in place, so we're just talking about wells that were no longer responding to gas lift where we're seeing gas flow around. Some of these wells were producing 50, 60 barrels a day, no less than 20 barrels a day. We just wait and gather those up and do them in bulk so we can lower the cost of doing the tubing replacements. And it's going to have a bit of a negative impact that's probably reflected in the results -- reserves, and I say probably reflected in the reserves because those wells went offline, and obviously, the declines would be considered. So we think actually it's going to have a positive impact on not only the cash flow, but across-the-board.

Michael O. Aldridge

So, if anything, from an LOE perspective, it provides the opportunity to realize some economies of scale here.

Thomas F. Cooke

In 5- to 6-month payout on those projects.

Operator

The next question is from Daren Oddenino of C. K. Cooper.

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

First question related to the new leases acquired. You guys talked about the potential of about 5 million barrels of PUD reserves associated with those properties. That would be a significant increase to your current reserves. Can you talk about kind of your confidence behind that and how you came about that -- those figures?

Andrew C. Clifford

Well, as I say, still it has to be qualified, but we have had at least some initial discussions with reserve engineers. But we're talking about one particular lease where 4 wells of log pay and one has had a significant high-flow rate, flow test of oil and gas. All stating another block where Contango is producing with amplitudes in the same 3D, so very good test. We've run economics, and it supports the cost of drilling in facilities and tiebacks. So it looks, for all intents and purposes, that we should get qualified as proved undeveloped reserves. So they are -- I just want to stress, that, that 5 million barrels is gross, it's 8 8s number, so take a 77% NRI on that basically to net it down. But we will start having discussions very soon with independent reserve engineers to get that qualified and studied in more detail.

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

And how far away is the Contango wells or well?

Andrew C. Clifford

Contango well is just 3 or 4 miles away, next block.

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

And then a couple others for modeling. DD&A was a little higher than past years. Just for modeling purposes, what can we expect going forward?

Thomas F. Cooke

I think we'll see that temper some, Daren. We did have the impact of adding a lot of capital costs this year. And so I'd like to believe you're going to see that, that back up because it came in at $24 million for the year, and I think something between our historical rate of $19 million and that rate of $24 million is where we're going to settle in.

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

Okay. And then also another modeling, that Main Pass 25, could you kind of give us any insight into kind of what the curtailment is for the first quarter due to those third-party takeaway issues?

Thomas F. Cooke

No, we're not giving any guidance relative to the first quarter numbers, but there was virtually no production off of that even going into the last part of the year. So we went through several scenarios. We started having some gas lift problems when we started going to our third-party operator. They had 3 failures of their compressors. They had the heater treater that they operate we own. The heating element burned out on it. It just kind of reaffirmed our commitment to move away from third-party operators, especially with the increase in LOE. But -- and then as I mentioned, we started having problems with our own gas lift supply, so we had to wait for a permit from the state of which we finally got, and then we perforated that zone and we've got great pressure. We've got our own gas lift supply, so we don't have to worry about third-party. And with the new discovery and the new production coming to that facility, not only lowering the cost of us building this thing out, it'll give us additional revenue. We'll operate that well more than likely as we work through this, but it'll give us an additional backup supply of gas lift gas. So we hope to see -- and then with the lowering of the line pressure, we're going to go -- be producing that into our own production facility where we're having to go through a long line, which is a hodgepodge of different pipe sizes. It's always been a problem. But the line pressure reduction, we think, will add another 200 barrels a day gross, and that may be a conservative number.

Operator

The next question is from Jeffrey Connolly of Brean Capital.

Jeffrey Connolly - Brean Capital LLC, Research Division

Can you give us some more detail about the CapEx program and when you expect to start drilling some of these PUD wells and the timing of that?

Thomas F. Cooke

Well, specifically, we haven't released the wells. I mean, it's always a work in progress, and especially with our field studies ongoing. As Andy alluded to, we're looking at the horizontal development, which we're looking at AFEs in the $7 million range. These are shallow zones. We're excited about what we see today.

Historically, we saw 2 to 3x production rates and recoveries of similar increases in offset wells. It's not unsimilar to what we see in Energy XXI and some of the results that they reported. But we're not going out experimenting in zones that haven't been completed horizontally. Kerr-McGee drilled some of these wells back in the late '90s with tremendous success. And some of those wells that we own today are still some of our best producers after 12 years. So we're pretty excited about the potential, but I do have to stress that, that's in the evaluation stage. We're really excited about the 170 and do an exploratory tail on that to the Tex W. Here, again, we're just kind of still juggling to see which one bubbles up to the top. So I can give you a well-by-well schedule that, of course, we use to create our own internal budgets, but as anybody that's been following us for any length of time knows that, especially when we're renewing the field studies and have a newly processed seismic, we'll be doing -- we'll be rejiggering that schedule, as always, trying to bring the best projects forward and drill more impactful projects in the future. So I hope that I answered your question. But like I said, it's always a work in progress and it's something that we're real proud of that we are able to rejigger our reschedule, and our inventory is deep. It's a good problem to have.

Jeffrey Connolly - Brean Capital LLC, Research Division

Okay. So about $7 million for the 4 PUD wells, or that's...

Thomas F. Cooke

No, no, no. This is a preliminary number, and I don't want to be held to it. But our early indications are that the horizontal wells will cost around $7 million, so -- but they should be giving us 2 or 3x the impact of the vertical wells.

Andrew C. Clifford

And that's including a pilot -- [ph] pilot first and then the horizontal. But, yes, we're looking at Breton Sound 32 and we're looking at Grand Bay, which [ph] we want to high-grade the top priority well in Breton Sound 32, which is probably at this time Rocky well; and then in Grand Bay, Tom said the 170, it's called Lily well. Those are 2 wells that we're really working up to try and high-grade those 2 as frontrunners.

Thomas F. Cooke

But I would like to add that our drilling program, since the first of the year and going into the last quarter, we've been underbudget and ahead of schedule on every project. So we are not building in additional contingency. We're actually looking at these things, and then putting a contingency on it. So when I say underbudget, I'm not talking about under a budget with a big contingency; I'm talking about underbudget with no contingency. So we're real proud of the fact that we're not taking a blind eye to even the workovers. We'll go in and we'll evaluate these workovers. If we see problems, we'll just move on to the next project before we start sinking a lot of money. And if you recall, we had kind of a nightmare scenario with the Tomahawk well, which we now affectionately call the hatchet job, where the prices really spiraled out of control and it was a workover. Successful, even though it cost $6 million. We're not going to do that again. We've got too many opportunities, too many places to go. We've got better places to spend our money, and we seem to have that focus now under control.

Jeffrey Connolly - Brean Capital LLC, Research Division

Great. And then is there -- what type of a success rate do you guys expect from the Grand Bay retubing program?

Thomas F. Cooke

Well, we anticipate that depending on the cost, we should have a 100% success rate. But you also have to consider if we go in and evaluate one of these wells when we start to move over on it, we'll just move to the next one. But we've identified 20 wells to-date that are candidates, so they're going through a second level of review. And of course, we always look at them and go, "Okay, what is the cost here, and then what do we have behind pipe up hole," so that's another part of the review. But I can tell you that we're at least 400 barrels a day offline due to tubing replacements. And I don't know how to risk that. We haven't done that internally yet. But obviously, there are more wells that will probably fit that scenario. Some of these wells gradually go down and then all of a sudden, they go down and then you do patch jobs to keep your gas lift effective. So some of the wells will probably get us -- the most bang for our buck will be wells that aren't on this list that may have been producing 10 barrels a day, that may have behind pipe recompletions, or once we replace the tubing on those wells, we could see substantial rates, especially those that hadn't been produced in a long time. So it all -- they always go down kind of slowly, and then all of a sudden, for no reason, your gas lift's blowing around and you realize that you can't do a patch job on that tubing. And you try to do that because the nature of the older fields and because the cost of doing these on a well -- on a well-by-well basis rather than in packages is probably 50% higher in cost.

Jeffrey Connolly - Brean Capital LLC, Research Division

Okay. And then one for Mike, can you update us on the revolving credit facility and what your thoughts are on that?

Michael O. Aldridge

Yes, we've received the first draft of indicative term sheet from the bank, and we're working that. And obviously, they were using an internal reserve report at 12 1. And now that we've got our year-end independent reserve report, that's back in their hands, and we're working further and tweaking some of the proposed covenants in the indicative term sheet. And so, progress is being made in that regard.

Thomas F. Cooke

But we're keeping a very close eye on our cash balances. And while we're not exactly where we were at year-end, we're close.

Operator

[Operator Instructions] The next question is from Richard Safranek of Wafra Investment.

Richard Safranek - Wafra Investment Advisory Group, Inc.

I sit here and I sort of am suffering some cognitive dissonance. We see natural gas -- spot natural gas prices at 52-week highs. We see Louisiana Light Sweet, Brent sitting at fairly healthy levels, yet your share price is hitting a new 52-week low. I mean, it sort of seems that you're writing a lot of that off to the Isaac interruption. And yes, that was a big impact, but it seems that there is some self-inflicted wounds from management in 2012 as well. I mean, one of them -- I was sort of curious to sort of hear the logic behind that, that S3 filing that you had in June that crushed the share price. What was the logic behind that, I mean, given the size of the filing relative to the market cap where you were at the time?

Thomas F. Cooke

I mean, we've seen many other companies file shelves that are relative to their market. Our market cap at the time was about $180 million, and we filed that shelf at $200 million. And the shelf is there to be used for accretive purposes. We've not -- you notice we've not pulled down on it, and it's something that a lot of public companies have in place. So I'm not sure that we can make the logic leap that, that filing of that shelf...

Michael O. Aldridge

I would say, you can't make that connection relative to the shelf registration.

Richard Safranek - Wafra Investment Advisory Group, Inc.

Shortly after you filed it, I mean, the share price just melted. And relative to peers -- and this is before Isaac, I mean, if you look at that window between your filing and when Isaac hit, you significantly underperformed all the shelf peers at that point, so the only thing I can connect was that shelf filing.

Thomas F. Cooke

Well, I will point to the fact that the micro cap B&P sector is down about 50%. And if you look at the micro cap E&P sector and then you move up to small cap and then you move up to mid cap and large cap, it's almost indicative at about 15% per market cap. And while the stock market's doing well, micro caps are not doing very well. And micro cap E&P companies are not doing very well. We have seen some uplift. But you also have to understand that we're thinly traded. The selling could be coming from some of the old shareholders that have been in the stock for a while. We'll try to do a better job on getting out, bringing in new shareholders to the stock. But as much research as we've done on the subject, we certainly can't identify it to the shelf registration. We think it's primarily because of the general market conditions. But we have been -- we are dedicated to redoubling our efforts on IRPR and doing more roadshows. And I think you've seen a lot of press releases from us to keep the market informed as to kind of where we are. As far as I'm aware of, no one has anything but a buy rating on independent research on the company.

Richard Safranek - Wafra Investment Advisory Group, Inc.

Yes, yes, they have a buy rating on it, I mean, particularly the sell-side because if you have financing needs and you've got that shelf registration out there, they want to participate in it. Just going on to the ultra-deep in terms of the way you've been talking about that, I mean, in retrospect, would you have been as aggressive touting your ultra-deep acreage given the risks associated with that? I mean, it seems pretty unlikely that we're going to see anything -- I mean, we clearly didn't see anything done in 2012 because of the delays at Davy Jones. It's -- we're not going to get anything done in 2013. Why continue to sort of really sort of tout that when that may not be anything? Because that was one of the things that jacked your share price up only to melt away. Why continue to promote that if that's just something that is not going to happen this year, unlikely to happen, I'm just sort of curious.

Thomas F. Cooke

Well, I'll answer this the best I can. As far as the ultra-deep, it's not in our reserves. We haven't been touting; it haven't been front and center. We continue to point to it, but we have no value. It's not in our net asset value per share. And we believe it has great potential, and we can only point to Lineham Creek that Chevron operates and their announcement of P3 reserves of 500 Bcf. And we also look at the fact that they also announced some proven reserves, which means that they had to have had a flow test. So we think it's a matter of timing, but we've always looked at this as kind of a call option. As long as we hold these leases, we'll wait for higher gas prices; it kind of puts us in the catbird seat as long we're in an HBP position. We believe all of these wells that have been drilled -- we don't think that they would've drilled 6 of them, I think anybody from the G&G perspective that has looked at the data will tell you that it's anything but pay. So while there are production issues in trying to figure it out, it's happening on somebody else's nickel. But I will remind you that we are not putting that front and center, and it's not even in resource on our reserves. So I would disagree with your analysis of that and our -- and the characterization of how we're pushing that forward. It's only part of our inventory. It's very much blue sky, but we appreciate the question, and I hope that answers your concern.

Richard Safranek - Wafra Investment Advisory Group, Inc.

My final question is just in terms of sort of, I guess, risk planning and stress testing. I mean, what would the situation be in 2013 for you given that you've increased your leverage a little bit if you had, say, another sort of similar Isaac-type event, I mean, in terms of your loan covenants, I mean, would you be in breach of anything if you, say, lost 20, 25 days worth of production [indiscernible]?

Thomas F. Cooke

I will tell you that as far as our loan covenants are concerned, we don't have anything there that would concern us other than missing a payment. And we keep deep cash balances, and we're focused on making sure we keep deep cash balances, so we're under no threat of any interruption. And I have to also point out that while a hurricane -- the resiliency of these assets, you have an interruption in your cash flow, which we're not concerned about that relative to covenants. We have an interruption in our cash flow, but those reserves are just not produced. I mean, you don't lose them. You're not losing the production. And the hurricane impact to us financially was $400,000, okay? So it was an interruption in our cash flow, in our business model, but it's not catastrophic by any stretch of the imagination.

Operator

The next question is from Richard Dearnley of Longport Partners.

Richard Dearnley

I'm new to your company. Is there a table somewhere in your filings that detail how you get to $9 a share of asset value?

Michael O. Aldridge

No, there is not a table. It's a non-GAAP measure. But most companies and the way we compute it is basically take your SEC PV10 and subtract from that your net debt position -- your outstanding debt net of cash and divide that by your diluted share count outstanding, and that would give you...

Richard Dearnley

Okay. And then did I get it right that in your debt deal back in midyear that the accrued interest -- the deal was done in December, but you paid interest from July 1?

Michael O. Aldridge

Actually that interest payment was made January 1, so that was accrued on the balance sheet at year-end and the cash actually went out the door. But, yes, that is correct. The interest payment went all the way back to July 1.

Richard Dearnley

And what caused that structure? It seems that's unusual, though I'm not a debt expert.

Michael O. Aldridge

Yes, that's standard. Basically, they front you the interest on the -- yes, I understand what you're asking now, they front you the interest on that piece between July 1 and December 4, the date we closed. And then you turn around and get that interest back to them on January 1, so it wasn't out of our pocket. Does that make sense? They literally front you the interest between -- we got an extra roughly $3 million covering that interest from July 1 on close date on December 4, and then you turn around and give that interest back to them on January 1.

Richard Dearnley

But you're paying interest on money you don't have for 6 months?

Michael O. Aldridge

No, you're not because they give you that $3 million on December 4 when you close. They put that cash in your cash account, and you turn around and give it back to them 1 month later.

Richard Dearnley

Oh, okay. And then you mentioned accretive acquisitions. If your stock is 1/3 of your purported NAV, and you're paying 12-ish percent debt, what -- how are you going to finance accretive acquisitions? Does the math work? I haven't tried to do this, but...

Thomas F. Cooke

Well, every deal is different. And obviously, we cannot -- we wouldn't get into any discussions that we're having. It took us a long time to find the Harvest properties. As I say, you got to kiss a lot of frogs to find one that works. But I can only tell you that we only consider things that are substantially accretive to the company. And without going into any deal structure, any specifics, we're very much aware of the fact that our stock is undervalued. And then you may look at potential relative valuations if you're using your stock. But I can only just reassure you that any acquisition that we get involved in will have to be materially accretive to the company.

Operator

The next question is from Steve Emerson of Emerson Investment.

Steve Emerson

As the last caller, I'm new to the story. You mentioned you're looking for covenant resets or renegotiations. I'm curious about risks and what -- under what conditions would you have to pay down your loan. And very typically, if reserves are down 12% as yours have been restated, you may have to pay down -- I'm looking for what covenants you may be bouncing against or violated.

Thomas F. Cooke

This is the Chairman, Tom Cooke, again, and I'm going to ask Mike to give you a little bit more detail on this. I want to make it very clear, we are in no violation of any covenants. And the only covenants that we have in our bond are pretty much typical to only a miss on the payment of interest. Now that may be a very general characterization. We do not have a revolver. We do not have a redetermination on the revolver. And one of the issues that we're looking at in putting a revolver in place is to make sure those covenants give us enough room to operate. But there's not going to be any readjustment of the terms. There's not going to be any foreclosure or acceleration. None of that's on the radar screen today. And it would really only occur if we missed an interest payment on our high-yield bonds. That's the only debt we have. So it's very simple for us to be able to track when we've got one set of covenants relative to the high-yield bonds. But I don't know where you've gotten the impression that there would be any kind of adjustment or we're under any kind of covenant violation, certainly not in the 10-K or any of the reports that we filed.

Steve Emerson

No, no. I just listened to your comment where you said that you're looking for -- I thought you said you're looking to renegotiate certain terms or readjust certain terms.

Michael O. Aldridge

Richard, what I had indicated was in our discussions with a commercial bank, we're trying to put a senior revolver in place and that they had floated an initial indicative term sheet to us. And as Tom mentioned, we want to make sure that those covenants are set at levels like our interest coverage ratio and our current ratio and debt to EBITDAX maximums, that those are all set at levels that we're comfortable with that give us some operating room. We do not, as we mentioned, have a senior revolver in place at this time. All we have are the senior secured high-yield notes, which do not have any maintenance covenants in them. They only have an incurrence test, and like Tom mentioned, payment of the interest payment. So we are not bumping up against any kind of covenants at this time, nor do we foresee doing that.

Thomas F. Cooke

Yes, that was in response to a question of Mike about what the status of us putting in place a revolver.

Steve Emerson

Okay, my apologies. How big or how much in reserves are uncommitted to your major credit line now? What possibly would you have available to secure a revolver?

Michael O. Aldridge

Well, we've got a debt incurrence test in the senior secured notes, and there's plenty of room under that, using our new year-end SEC PV10, to put a substantial revolver in place.

Steve Emerson

Can you comment on how big or how big a revolver or general range by standard industry formulas you might have available to you?

Michael O. Aldridge

Well, I mean, yes, if you go look at the indenture, it -- there's a -- basically, it allows you to -- there's a carve-out for a senior revolving credit facility at the higher $35 million or 15% of ACNTA, adjusted consolidated net changeable assets. And if you go through the mechanics there, you'll see that, that number's actually higher than the -- and you go through the debt incurrence test, both of those numbers are higher than the $35 million number.

Andrew C. Clifford

Steve, one more thing, I think you said 12% reserve revision, it was 9%.

Operator

The next question is from Eric Anderson of Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

I know that you don't -- you're not counting on any of the ultra-deep plays as near-term prospects, but since you referenced kind of results that Chevron has seen in the Lineham Creek well that they're getting, I guess, ready to finish up drilling. And I think you mentioned it's 13 or 15 miles away. Is there anything that you can infer from what you've been able to learn about that well in terms of if those sands are present in your Long John Silver prospect? Anything along those lines you can help us do some correlation would be helpful.

Andrew C. Clifford

By the way, Eric, it's 30 miles away, 3-0, not 13, to the West Northwest, and Davy Jones is 30 miles to the East Southeast of where we're at in Vermilion 16 also. We would expect the same sands to be present generally in that area, but I mean, it's speculation at this point until we know more in detail about -- I mean, as far as I understand, those [indiscernible] sands that they've logged and maybe tested, and apparently they've been quarrying in the Wilcox, those [indiscernible], that's the first ever [indiscernible] we encountered in that part of Louisiana. So it'll be pure speculation to say that they extended much further away than their structure until there's others wells down, until it's logged and paleo and other data supports it's the same. But we would expect -- I mean, the good thing about the McMoRan Energy XXI Chevron program is that it's not one sand, it's not up Wilcox, low Wilcox. They have talked about Tuscaloosa, Lower Cretaceous, now [indiscernible], Sparta, I mean, of all the 6, 7, 8 penetrations of the ultra-deep, there's play in all of them. So in a way, it really doesn't matter specifically until something's tested, until the reservoir characteristics are understood. Apparently, the reason they call it the Wilcox was to see the frac-ing -- the natural fractures in that rock to help with the Davy Jones test, that's the frac-ing that's due in several weeks. So yes, we'll see. There's plenty of target sands down there. It doesn't really necessarily matter if it's the same [indiscernible] or Sparta or [indiscernible], Wilcox, whatever.

Thomas F. Cooke

But what we do know is that we are sitting on top of a major structure that's halfway between Lineham Creek -- almost in a straight line between Lineham Creek and Davy Jones.

Eric B. Anderson - Hartford Financial Management, Inc.

And based on your seismic, you believe that there's a trap there and that you see multiple potential target zones?

Andrew C. Clifford

Absolutely, between 22,000 and 32,000 feet.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay, that's a lot of area of closure then, huh?

Andrew C. Clifford

It's a large structure; one of the largest in the Gulf of Mexico. And we sit in a crystal position on it, and we like where we sit. But as we said earlier, we're focused on maintaining shallow production. Our game plan hasn't changed. It's -- if you'd like, it's a call option on the ultra-deep wells. We have a very large structure on East Grand Bay that we're very proud of, too, that we haven't said too much about. We're just as excited about that.

Eric B. Anderson - Hartford Financial Management, Inc.

I mean, when you're able to think about drilling that well, is it possible that you'd be doing this with a barge rig, something that's much less costly than...

Andrew C. Clifford

There are 1 or 2 barge rigs which can drill in line with those depths with the top drive necessary. And so that's the good thing about considering the state borders is that -- I mean, at Grand Bay, we can even use the land rigs, but barge rigs will drill this. Everything in our portfolio, other than the new leases we picked up in federal and even one of those we think could be barge rigged, everything could be drilled with a barge rig.

Eric B. Anderson - Hartford Financial Management, Inc.

And like you say it's nothing but upside for the stock price, which is [ph] not in there?

Thomas F. Cooke

That's the way we look at it. We have not pushed our reserve engineers to try to include it. We believe that we probably could get qualified as a resource, but we just -- we don't want to overly emphasize that.

Andrew C. Clifford

Yes, one of the things that's kind of fairly unique we have found talking to the neighboring companies is, we have 100% working interest, all depths. A lot of the majors, the Chevrons, the Exxons, Conocos, kept the ultra-deep wells for themselves under a lot of these fields. But in our case, at Grand Bay, at Vermilion 16, we've got all the depths. So we've got all the ultra-deep potential, too. And we don't have salt domes. Any -- all our fields, none of them are salt domes. And the difference with the salt dome is the salt takes out the core of the structure and then we put the flanks around the outside and maybe sub-salt. But we don't have that. So we have 65 stack reservoirs at Grand Bay that have produced historically. We have projected in another 20, 25 from the North and [indiscernible] through our 3D data under Grand Bay that we think exists under Grand Bay. Vermilion 16 produce some 30 stack reservoirs. And who knows if you keep on drilling below 16,500-foot, you're going to find a stack -- bunch of other ones until you get to the ultra-deep. So it's all upside, and we managed to hold it all because we have all rights to all depths, and we've got HBP acreage of the shallow.

Eric B. Anderson - Hartford Financial Management, Inc.

Oh, that's the key.

Andrew C. Clifford

Yes.

Operator

The next question is from Damien Harness [ph].

Unknown Analyst

Just carrying on from the previous question from the gentleman who highlighted the Heavy Louisiana crude prices and the net gas prices, and exiting out the ultra-deep prospects, as you've said the market's doing, is there anything at the moment you can comment on that marks as a near-term catalyst to reverse the downward trend in the share price performance? It seems that the market's paying very little attention to the $9 per share now for the proved reserves that you mentioned. Obviously, it's -- you look at a 12-month [ph] stock price, and it's just one way. So is there anything that you can -- anything you could comment on that you can see reversing this move?

Thomas F. Cooke

Well, I've got to reiterate my observation and -- that micro cap E&P companies are not performing well on the market. In fact, they're down about 50%, so I think you got to start there. And then we're a relatively new company. It's getting on the radar screen. It's creating some buying. We think we're undervalued. We think we're significantly undervalued. So how do you turn around that market perception? We're thinly traded, and it doesn't take more sellers. If there's not enough buyers, that's what's going to happen. But we don't believe that the results are what are driving that because we just don't hear it, or we don't see it. So I don't know what the answer is. We'll do our best to make sure that the market understands what we're doing. We'll be doing all the major shows, explaining our business plan, and we'll be doing some roadshows here in the future, especially since we've been able to get the 10-K behind us. So it's a matter of getting out and beating the drum and letting people know what we are, who we are and where we are. And like I say, we're a relatively new story. We're relatively thinly traded. I think our average share per day is around 56,000 shares per day -- 56,000, 58,000 shares per day. Now that's not too bad. I mean, for an American Stock Exchange company, that would put you above kind of in the upper range of trading volume or at least above the 50 percentile. But I think it's a matter of getting the story out and continuing to make sure people are aware of what's going on.

Unknown Analyst

Are you seeing any kind of institutional interest in the pipeline over in the states?

Thomas F. Cooke

Well, I think probably, yes, we do. I mean, that's just a matter of continuing to get out there. I mean, we've only got research coverage, I think, about 4 companies currently, and we're talking to more. So it's getting that exposure out there, and trying to get results that get people's attention for new shareholders. And obviously, you have to continue to bring in the new guys.

Operator

There are no further questions at this time. I'll turn the call back over to Tom for closing remarks.

Thomas F. Cooke

Well, I just want to thank everybody for participating and calling in, and thank you for your questions. It always helps us to be in contact with the market, and believe me, we're all ears. And I want to extend this invitation to anybody that has a real interest in the company to try to contact us individually. We're hoping that this year is going to be an excellent year. We got off to a slow start. I think that we're starting to get our feet under us relative to that, and we've had some early good results with the drill bit, and we'll be looking towards more impactful projects that will move the needle a little bit and try to bring awareness our direction. So with that, I'll just say one more time, thank you for your questions, thank you for your time. And we remain very pro our stock and hopefully, we'll start to get market recognition as such. Andy, do you have anything in closing?

Andrew C. Clifford

I just want to say when Tom says more impactful wells without taking undue risk, I just want to emphasize that is we're not going to stop wildcatting when -- we're talking about putting some tails on at minimal incremental costs with bailouts in Grand Bay. And horizontal wells, Tom mentioned the fact there's been 4 previous horizontal wells in Breton Sound 32. We're basically doing what Kermit U [ph] did in '93 with better technology, shallow depths and 300-founder foot [ph] horizontal tails, Grand Bay being 1 horizontal well today, that's the best one in the field and still producing today, so...

Thomas F. Cooke

Yes 50, 80 barrels a day after 12, 13 years worth of production. So everything that we do is motivated by making sure that we've got the available cash to do it and cash reserves to do it so that we don't push the envelope and don't have a need to go back to the market for additional capital. Even the revolver that we're putting in place, it's a dry powder-type facility for any potential interruptions that we might have in production. But it's risk and risk management and controlling costs is where we're focused, and we're dedicated to that process. So with that, Mike, do you have anything to add?

Michael O. Aldridge

Thank you for your participation and interest.

Thomas F. Cooke

Thank you, guys.

Operator

Ladies and gentlemen, this concludes today's program. You may now disconnect. Good day.

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