Stone Energy's (SGY) CEO David Welch on Q1 2014 Results - Earnings Call Transcript

May.11.14 | About: Stone Energy (SGY)

Stone Energy Corporation (NYSE:SGY)

Q1 2014 Earnings Conference Call

May 8, 2014 10:00 ET

Executives

David Welch - Chairman and Chief Executive Officer

Ken Beer - Executive Vice President and Chief Financial Officer

Analysts

Michael Glick - Johnson Rice

Jeb Bachmann - Howard Weil

Doug Dyer - Heartland Advisors

Adam Fackler - MLV & Company

Richard Tullis - Capital One

Operator

Good morning. My name is Stephanie and I will be your conference operator today. At this time, I would like to welcome everyone to the First Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. David Welch, Chairman and CEO of Stone Energy, you may begin your conference.

David Welch - Chairman and Chief Executive Officer

Okay. Thank you very much, Stephanie and welcome everyone to our first quarter call. Ken Beer, our Executive Vice President and Chief Financial Officer will begin the meeting this morning with our Safe Harbor statement and a review of our recent financial performance for the quarter and guidance for the remainder of the year. He will then turn it back over to me for an operations update and additional comments on the execution of our five-year plan. So, Ken to you?

Ken Beer - Executive Vice President and Chief Financial Officer

Thank you, Dave. Let me first start with the forward-looking statement. In this conference call, we may make forward-looking statements within the meanings of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all of the risks and uncertainties normally incident to the exploration of foreign development production and sale of oil and natural gas. We urge you to read our 2013 Annual Report on Form 10-K and our most recent 10-Q that was filed last evening and a discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements we make today.

In addition in this call, we may refer to financial measures that maybe deemed non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday, which is posted on our website for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures.

And with that, let me go into the 2014 results. I won’t go in great detail. I’ll assume everyone has seen the press release and the first quarter although an active quarter with the drill bit, was really fairly vanilla financially, so with no significant adjustments or non-recurring items. Accordingly, I will just focus on some selected items on the call.

Our discretionary cash flow for the quarter was $138 million or about $2.75 per share and the earnings for the quarter were just under $26 million or $0.52 per share both above first call estimates. Our production for the quarter was just under 45,000 BOE per day or just under 270 million cubit feet a day equivalents, which at the upper end of guidance, this despite a couple of negative impacts to production.

First, heavy snow conditions in Appalachia for the quarter made roads impassable at times, restricting our ability to truck out condensate and forcing sporadic shut-ins when the onsite storage facilities became full. Second, volumes from the Main Pass 288 were shut-in for most of the first quarter and into the second quarter due to a paraffin plug in the oil pipeline. Although this issue has finally been resolved, it impacted the quarter by approximately 5,900 barrel equivalents a day. And then finally, we sold our onshore cutoff Clovelly field in early January, which was producing roughly 1,000 barrel equivalents per day.

Also remember in the fourth quarter of 2013, we benefited from two positive one-time adjustments totaling just over 10 million cubic feet equivalents a day. First, the recapture of previously paid royalties, which qualified for royalty relief from us in deepwater production and second, we benefited from some upward adjustments to our working interest in the Mary field as the units were finalized. So, if one adjusts the non-recurring items with the property sales and shut-in volumes, our first quarter volumes were actually fairly flat with the fourth quarter volumes in 2013. We would expect the volumes to remain relatively flat in the second quarter with the June exit volume boosted we believe by initial production from Tomcat.

As you can see, we are maintaining our full year 2014 guidance at the original range of 43,000 to 47,000 barrel equivalents or 258 million to 282 million cubic feet a day equivalents. As you can see our quarterly price realizations was just under $100 a barrel with about 9% of the oil volumes now coming from Appalachia, which does actually pull down the weighted average. However, the LOS premium over WTI expanded during the fourth quarter versus the fourth quarter, which added about $3.50 per barrel.

Our realized NGL prices averaged over $54 per barrel a bit higher than expected. This was primarily due to first – an adjustment in the first quarter which added from the fourth quarter an accrual which added about $2 per barrel and then very strong product pricing during the cold winter months where some of the products within the NGL barrel were highly priced. And then the fact that the pricing for Appalachia NGLs are boosted by being blended slightly with a small portion of the higher priced condensate. We would expect the NGL pricing and to trend down a little bit from the first quarter.

Overall gas prices were stronger than expected and benefited from a higher Henry Hub pricing, a reduced Appalachia differential during the cold winter months and some very high spot prices for a number of the days during the quarter. On the cost side our LOE was around $47 million for the quarter, slightly lower than the fourth quarter 2013. We would expect to keep LOE pretty flat with 2014 with the guidance still in that $195 million to $210 million range. The transportation processing and gathering expenses was just under $15 million for the quarter, it’s as greater volumes from Appalachia are coming, we will continue to have higher incremental gas NGL and condensate transportation and processing fees. As noted in the 2014 guidance, we would expect this transportation processing and gathering expense to increase over 2013 as the greater percent of the production should be coming from Appalachia, which has that higher percent in this line item and we would expect higher unit transportation fees in the Gulf.

Our DD&A for the quarter averaged $3.38 per Mcfe, a little under guidance. However, we expect this rate to increase in the second quarter as we move some of our unevaluated cost into the full cost pool. Specifically, at 3/31/14, we have about $350 million in our unevaluated properties category for Amethyst, Tomcat, Cardona, and Cardona South and a little bit of Mica Deep all of which is expected to move into the full cost pool over the next one or two quarters. This is projected to increase the overall DD&A rate and therefore that’s why we are keeping our original DD&A guidance the same.

Our base G&A before incentive comp came in at just over $16 million for the quarter and incentive compensation increase was around $3 million for the quarter. As discussed before base G&A for 2014 is expected to rise due to added staff, higher salaries and higher non-cash stock compensation expense. The reported interest expense for the quarter was just over $8 million with about $4 million of that in non-cash interest primarily tied to the convertible notes accretion. Our capitalized interest was about $13 million with actually the cash interest running at about $16 million per quarter.

Regarding taxes we came in about 37% reported tax rate all of which were deferred. Just a quick comment on the convertible notes, remember our convertible notes have a strike price of $42.65 per share, but we purchased a call spread which effectively pushes up the strike price to $55.91. However, GAAP accounting ignores our call option and only looks towards the original strike price and therefore we would look to have some small earning dilution based upon $42.65 strike price, there will be no impact to cash flow or absolute earnings, but there maybe a slight really $0.01 or so dilution at the current stock price just on the reported EPS figure, again more of a heads up.

Our CapEx for the quarter was approximately $254 million. The first quarter recognized shouldered the daily drilling expenditure for Amethyst at 100% working interest and Cardona at 65% working interest for most of the quarter. We would also – we would expect a slight reduction in the second quarter although development dollars for the Cardona South wells and in the Cardona looped pipeline project will certainly impact the CapEx for the second quarter. During the quarter, we also completed a couple of small divestitures, including the sale of our cutoff Clovelly fields and our holdings in our Cane Creek play in Utah. Total proceeds for these sales, was about $55 million. Our $400 million borrowing base on our bank facility remains un-drawn except for the $21 million in LOCs. And we would expect to have a new facility in place to have before the end of the quarter. We have about $203 million in cash on hand at quarter end. We did add a couple more hedges to further protect cash flow and CapEx and it included the updated hedge position in the press release.

I believe that wraps up the financial overview. I did want to remind investors and analysts that we will be having an Investor Day in New Orleans on the morning of May 20, that’s Tuesday, May 20. And that this session will be webcast, although we would certainly hope that folks can make it in person. Again, that’s Tuesday, May 20 in New Orleans.

And with that, I will turn it over to Dave for his comments.

David Welch - Chairman and Chief Executive Officer

Okay, thank you Ken. We feel like the first quarter was an excellent value-adding period for the company and its investors. Our common stock prices performing well over the last few quarters and we achieved many important milestones for the future during the quarter. Our production and cash flow were comfortably toward the upper end of guidance even though we experienced some minor speed bumps relating to weather and pipeline issues in both the Gulf and Appalachia. Of course, our full year guidance is reaffirmed.

We also achieved several important milestones that we believe indicates further value creation ahead. There have been two industry transforming technological breakthroughs in the last 30 years, deepwater exploration and production and technology and horizontal drilling with hydraulic fracturing. And Stone is well-positioned to take advantage of both of these technologies owning over 120 deepwater leases and 2 deepwater hubs in the Gulf along with an approximate 35,000 net acre position in the super-rich portion of the Marcellus shale in Appalachia. Both of these areas have material production and reserves already as well as significant and near-term development and exploration potential.

The first quarter and in fact the whole first half has started the year on an excellent note for the company as we drilled four discoveries out of five wells in the Gulf area giving us a nice lift to discoveries to underpin the next couple of years of production and growth. First, in our deep gas area, we announced in the quarter of 100% owned Tomcat discovery at West Cameron 176. We have been able to reclaim one of our existing platforms to shorten the cycle time to first production and now expect to have Tomcat flowing to sales by June and maybe even this month with an estimated rate of 10 to 15 million cubic feet of natural gas and 60 barrels to 80 barrels per million of liquids.

In the deepwater area, we have made three discoveries out of the four wells we drilled so far this year. The one well that’s not found hydrocarbons is Mica Deep. The well has found high-quality wet sands and we are in the process of gathering additional data now to determine the potential of the prospect to perhaps evaluate again at a later date. Our 50% working interest carried a 35% cost interest, that means that our net exposure is expected to be in the $30 million to Mica Deep. Importantly, the discoveries we have made are all at higher working interest with two development discovery wells at 65% working interest and two exploration discovery wells at a 100% working interest. Of the deepwater discoveries, the first was our February announced discovery of the 100% working interest. And with this exploration prospects, this would be Canyon 26. We found about 90 feet of liquids-rich gas in a structure that’s estimated to cover over 4,000 acres. This well is expected to yield a high rate completion exceeding 50 million cubic feet a day of gas plus an associated liquids of 60 to 80 barrels per million cubic feet.

We are currently developing a plan to tie back to our Pompano hub. We will likely sanction this development and then if so expect to be able to get Amethyst on production in 2016. The second discovery at our Cardona development prospect was made public in February. We announced 8 more feet of net oil pay in Miocene-age sands. And although further deepening didn’t yield any additional pay, substitute data and balances have now increased the estimated original zone net pay by about 15% to 9060. We also just recently made a third deepwater discovery this year at the Cardona South developed location. The Cardona South wells found over 275 net feet of pay in three sand intervals. We believe to reserve they are large enough to support the drilling of another low-risk development well and possibly even a third one. We are in mid process of building a flow line that extends from the Pompano hub to both Cardona and Cardona South locations.

Project execution is currently on the projected timeline and below authorized cost. And we hope to keep it that way through the completion and commissioning. There are important discoveries for us. We are in the owned and operated 65% working interest. We expect to have the Cardona and Cardona South wells both online in the first quarter of 2015, if not sooner. These two wells together are expected to net us about 10,000 barrels of oil per day which exceeds 50% of our current company wide daily oil production rate. In addition, since the production handling fees we earned from processing our Cardona’s production are higher than the incremental leased operating expense of producing the wells at Pompano our margin is expected to be higher than the price of oil for these few wells.

In addition to the Cardona development program, we also plan to commence a platform development drilling program at Amberjack later this year and at Pompano next year. One of the best features of the platform drilling is that there is virtually no delay in getting the wells on production once they are drilled and completed. This helps to underpin both the economic returns of the program and the short-term cash flow of our company. We plan to start with the Amberjack program where we expect to drill the four (to five) wells and then move to Pompano to drill another four wells with a separate rig as soon as it’s available and once all of our Cardona and Amethyst tie back platform modifications are complete. We expect these programs to be high return and fairly low risk projects which will help support our production growth and cash flows over the next couple of years. The next potential 2014 or early 2015 exploratory well is our former 21 prospect now known as Harrier, and operated by our joint venture partner ConocoPhillips.

We currently have a promoted rise to 37% working interest in the block with only a 20% cost interest in the well which is also a Miocene test. This prospect is adjacent to a block that Chevron won in last year sales of a bid of over $50 million. So it’s possible a joint well could be drilled covering both blocks and then with differing costs, working interest and timing. Nonetheless, this is an exciting prospect sought after by many exploration companies. We may also see another non-operated prospects such as Goodfellow well drilled sometime in 2014. Goodfellow was a prospect offsetting the Giant Shenandoah discovery and is operated by E&I. We hold about 13% working interest in this potentially large geological structure which we have estimated at P90 to P10 range of 80 million to 800 million barrels of gross potential if successful. Our deepwater lease base sits at 119 leases with three more upon which we are high-bidder in the last sale, but which have not yet been awarded. If those leases are granted our portfolio would comprise 70 Stone operated blocks and 52 non-operated blocks.

We feel that we now have enough company operated exploration well completion and development drilling work to keep deepwater rig busy for two to three years. We also experienced a little softness in the deepwater rig market and feel this is a good time to test the market to see if we may be able to capture a versatile deepwater rig on attractive terms. We could be in a position to potentially sign a contract on a deepwater rig later this year for use in our robust portfolio of company operated opportunities.

In our deep gas exploration area, we plan to drill the onshore high-end prospect located near Avery Island, Louisiana later this year or early in 2015. We own a 50% working interest in this prospect which is targeting a potential P90 to P10 resource range of 20 Bcf 200 Bcf of liquids rich gas. If successful this should be another quick to market source of cash flow for us. The sands being tested are similar in age and hopefully in quality as those in our La Cantera discovery whose wells are each delivering growth rates in the range of 40 million cubic feet of natural gas per day plus associated liquids.

We may also participate in the drilling of the deeper test at our South Erath discovery and/or drill the La Montana prospect later this year. Both of these are in the same geological mini basin, so we have already made two discoveries at South Erath and La Cantera and both are targeting liquids rich gas. The conventional shelf continues to provide us with excellent production and cash flow and thanks to an active work over schedule and despite new drilling in the quarter and the pipeline issue at Main Pass 288 that lasted almost three months. The pipeline issue has been resolved and we are back on production as Ken mentioned earlier.

Also in February, we completed the sale of our onshore portion of our shelf market test for approximately $95 million. We remained in the market test process for the other non-core shelf properties. In the meantime these properties have performed well and are still contributing. We continue our efforts to market the package, but are content to retain the properties if we don’t get a good price for them. We believe our decommissioning team is among the best in the business. So, there is no compelling reason for us to sell at a discount.

Finally, our last growth area is Appalachia. Our crude Marcellus reserves now make up over half of our crude reserves at approximately 0.5 trillion cubic feet of natural gas equivalents and our net probable, possible and prospective resources for the Marcellus aggregate is significantly more. We are continuing our dependable predictable Marcellus drilling program with an expected 30 wells to be drilled at our Mary field again this year. We are presently fracking a 10-well pad in the Mary field, which should come online in the third quarter. We are also fracking an 8-well 50% working interest pad in Heather and anticipate production there in the third quarter as well.

We expect to average about 100 million cubic feet a day of production from the Marcellus this year, which is an important milestone. We believe that we developed a competitive advantage in our Mary area of operations comprising of proprietary road system, water handling system, gathering systems, and they capture the most viable pad locations within our perimeter. This will help us with an exciting new opportunity evolving at Mary and that is the potential for the existence of the large resource in the Utica shale, only a few miles from our Mary field. Multiple beautiful wells have been recently tested with initial production rates between 20 and 30 million cubic feet per day in dry gas. We already own about 28,500 net Utica acres in our Mary field.

We expect to spud our own mid-link horizontal Utica exploration test well late in the second quarter or early in the third and to complete the test and test the well later in the year. We are presently considering the best option for a potential Utica development plan. This would take advantage of the acreage and infrastructure already owned at Mary. If the exploration test is successful and the economics are compelling, execution of the Utica development could potentially commence as early as 2015. On our acreage at Mary, the Utica is believed to be twice as thick as the Marcellus, higher pressure and so we would expect higher rates and higher recoveries per well than the Marcellus. The Utica potential on our acreage is very high and we are anxious to test this opportunity later this year. If successful, we could have material implications for our future production reserves and value creation in Appalachia.

Finally, the balance sheet is in excellent shape. We ended the quarter with over $200 million in cash and now have an undrawn $400 million borrowing base on our revolving credit facility. We feel like we have the financial flexibility to execute our plan. Our $825 million capital program appears to be yielding very positive dividends for us and in light of our success with the drill bit may need to increase the cover completion and another development cost to bring the discoveries online.

Our investment capital is heavily weighted toward lower risk development in projects already successfully discovered in deepwater such as Cardona and Cardona South, Tomcat and deep gas and the Marcellus and Appalachia. The higher risk exploration program this year started very well with the discoveries at Amethyst and Tomcat in the Utica test yet to come. This portion of our capital represents about 30% of our dollars and about two-thirds of that 30% is actually planned for drilling exploration wells. We are in the midst of a very exciting and so far successful year.

As mentioned earlier, there have been two E&P transformational technologies, deepwater exploration and production and horizontal drilling with hydraulic fracturing. Stone has the acreage, the execution capability and confidence in both of these areas. We continue to believe we have the teams in place to prospects and inventory and the access to capital we need to execute or meet our five-year plan. Just a quick remainder again of our Analyst Day in New Orleans on May 20, hope to see you there.

And so with this, we will now be happy to take your questions. Stephanie, back to you?

Question-and-Answer Session

Operator

(Operator Instructions) And your first question comes from the line of Michael Glick [Johnson Rice]. Your line is open.

Michael Glick - Johnson Rice

Just a question on Cardona, how would you characterize the rock quality between Cardona, the TB-9 well and Cardona South?

David Welch

Just qualitatively, it progresses from north to south in a better form. So, the Cardona well is a good well, TB-9 slightly better and the Cardona south well is quite a bit better rock quality. So, we expect to have a fairly high rate well out of the Cardona South prospect and very good wells out of Cardona in Cardona and the TB-9.

Michael Glick - Johnson Rice

Okay. What are kind of the key variables associated with the timing of first production there?

David Welch

Cardona?

Michael Glick - Johnson Rice

Yes.

David Welch

Well, the key variables are just execution of getting the flow lines installed and getting the umbilicals installed and connected. The key variables are once you get that done without any hitch and number two is just frankly the weather. We are going to be doing that this summer. And so depending upon how the weather cooperates or doesn’t, those are the main variables since we now have the wells drilled.

Michael Glick - Johnson Rice

Okay. And then what will the timing be associated with the second or third well at Cardona South?

David Welch

That’s really tied up and our plan to potentially pickup the deepwater rig. And so I think if we are able to capture a rig, the timing of the availability of the rig will probably drive the timing, but it couldn’t be sometime next year.

Michael Glick - Johnson Rice

Got it, that’s it from me. Thank you very much.

David Welch

Yes, hey, Mike, let me also add on the third, if there is a third well at Cardona South, that would certainly wait until after we have some production history from the first well at Cardona South, so whereas the second well actually would be going after the shallow zone that was identified. The third well would just hold off and get some production history before we bring on a third well. So, I want to make sure kind of they are somewhat independent that second well can move forward quite a bit quicker, because it is not so dependant upon production history, because they are going after different zones.

Michael Glick - Johnson Rice

Okay, alright. Thank you.

Operator

And our next question comes from Jeb Bachmann with Howard Weil. Your line is open.

Jeb Bachmann - Howard Weil

Good morning guys. Just had a few questions. Starting with Mica Deep, just wondering if you guys could give us the sand thickness in that well that you saw that was wet?

David Welch

Well, we are actually still logging the well right now, Jeb. We have some MWD stuff, but it’s not completely reliable, but the sands were very thick and wet and we will be able to give you that info by our Analyst Day.

Jeb Bachmann - Howard Weil

And Dave, do you think that possibly any kind of up-dip potential could be a sidetrack from this wellbore or at this point is it too early to know that?

David Welch

It’s a little early to know it. We are gathering pressure data and all sorts of other information to help us determine if there is still a target of structure. We do have a lot of room up there from where this well is drilled. So, it’s possible that we want to see some pressure data to try to determine what it might be tied into on a regional sense before we would be willing to commit additional dollars to a sidetrack. And I think the well is going to be in all likelihood will probably abandon the well, but it’s likely to be left in a condition where we could reenter it in the future if we decided to sidetrack.

Jeb Bachmann - Howard Weil

Okay. And then – and just looking at Pompano, the facility itself and I think you guys said you had some work to do there to upgrade the facilities. Just wondering when the last time Pompano was producing as much as you would expect to be brought online within the next call it 9 to 12 months?

David Welch

Yes. It’s probably been a few years since it produced those volumes, but we have gone through cleaned out all the vessels on the facility already, did that in a safe and efficient manner. We have made the modifications to the platform that are just about complete for Cardona. So, we are not really worried about the platform being able to handle the platform is in good shape and should be able to handle it easily.

Jeb Bachmann - Howard Weil

Okay. And last one from one, any update on firm transport out of Appalachia?

David Welch

Yes, I will jump in. Really no update there, Jeb, I mean we continue to look at it as I think I have at least highlighted before you certainly have had some negative differential and yet in terms of access out of this area, besides the TETCO or Texas Eastern line that we flow into, you do have Dominion, Columbia, even the Transco line just to the east. So, you’ve got some major trunk lines coming through the area, all with at least some sort of expansion plans on the horizon, but for the moment we have got just the transportation into the TETCO line but no firm transportation out of the what we call the M2 interconnect, so that’s how we continue to look at though.

Jeb Bachmann - Howard Weil

Okay. I had one more on Utica development plan does that include potentially a JV to help accelerate development of that shale or was that not on the table?

David Welch

Yes, I think the options are wide open there. We got to look at everything to try to create as much value as we can.

Jeb Bachmann - Howard Weil

Great thanks guys.

David Welch

Thank you.

Operator

And your next question comes from Doug Dyer with Heartland Advisors. Your line is open.

Doug Dyer - Heartland Advisors

Good morning, just a little bit more of a follow up from the last question on JVs with the discoveries that we have had so far this year, are we in a position where those can provide some future cash through JV or are we going to wait for some further discoveries this year before we get to that kind of discussion?

Ken Beer

Yes. Doug again what we are currently looking at the various options and one of the things I guess we have noted before is it is nice to have the options. We will continue to try to evaluate one versus the other kind of JV and Appalachia versus a JV and the Gulf versus public markets private markets. I think as Dave alluded to you I mean we do have success which does call for incremental capital, but it’s nice to have some different options to look hard at. We also right now still have cash on the balance sheet and the undrawn facility. So we feel like we have got some not only options but are able to step back and not feel forced into one option versus the other.

Doug Dyer - Heartland Advisors

Alright. Thank you very much.

Operator

And your next question comes from Adam Fackler with MLV & Company. Your line is open.

Adam Fackler - MLV & Company

Good morning. I know you touched on it on your opening statements, but I was just hoping you might be able to provide some additional color around any predrilled expectations for that Utica well in terms of lateral lengths, fracs stages or well cost recoveries? Thank you.

David Welch

Yes, I think we are planning on about a 3600 foot lateral, so it’s not a full length lateral, but it should give us all the information that we need. I don’t have any detail right now on what our frac design is going to be in terms of the stages or overall amount of proppant that we are going to be injecting per stage, but that should be the summer and hopefully we will be able to discuss that in more detail when we have our Analyst Meeting as well.

Adam Fackler - MLV & Company

Alright. Thank you very much. That’s it for me.

David Welch

Okay.

Operator

(Operator Instructions) Your next question comes from Richard Tullis with Capital One. Your line is open.

Richard Tullis - Capital One

Hey, thanks. Good morning everyone. Dave if you could go over the net volumes expected for the Cardona wells and if you could talk a little bit about the timing of the ramp up there?

David Welch

Yes. The ramp up, we will generally ramp those wells up over a couple of months period of time. But we think that between the two wells we will end up with about 10,000 barrels a day net to Stone and how that’s split out is not exactly known at this point, although we do believe that the Southern well is going to be a higher rate producer than the Northern well.

Richard Tullis - Capital One

Okay. And how do you think that the 10,000 splits up between oil and gas?

David Welch

Yes, that’s mostly oil, it’s almost I think that’s our oil rate, isn’t it, Ken?

Ken Beer

That’s correct. No actually that should be pretty sure that we most of it is oil, but there might be some associated gas.

Richard Tullis - Capital One

Okay, and just kind of ballparking it, Dave what do you think your dollar per margin or your margin per barrel is going to be on those Cardona wells using say current commodity prices?

David Welch

Yeah, but well the margins should actually be a little bit higher than the price of oil because our incremental lease operating expense is expected to be around $2.5 million. And our incremental production handling fees that we will be capturing for processing our partners 35% will be around $4 million. So that difference will actually be a negative cost and so the margin will actually be a little bit higher than the price of oil maybe $1 or $2 a barrel.

Richard Tullis - Capital One

Okay.

David Welch

So there will be very good high margin production for us once we get it online.

Richard Tullis - Capital One

And then if you were to go back and drill another well at Mica Deep, what would be the payment arrangement? Would you still have to promote there or you would have to pay your full share?

David Welch

No, if we were to do a sidetrack or go back and later reenter the well and do a sidetrack, it would be kind of, if we did with our current partner, it would be 50-50.

Richard Tullis - Capital One

Okay.

David Welch

If Stone decided not to do it, then it will be whatever the market would bare.

Richard Tullis - Capital One

Okay, well that’s all from me. Thank you.

David Welch

Okay.

Operator

And there are no further questions in the queue at this time. I will turn the call back over to the presenters.

David Welch - Chairman and Chief Executive Officer

Okay. Let me just thank everyone for joining the call and remind you that you have a lot of good, exciting things coming up and please stay tuned for our future calls and hope to see you on our Analyst Day. Thank you everyone.

Operator

And this concludes today’s conference call. You may now disconnect.

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