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Stone Energy Corporation (NYSE:SGY)

Q2 2014 Results Earnings Conference Call

August 06, 2014 10:00 AM ET

Executives

David Welch - Chairman, President and CEO

Ken Beer - CFO and Executive Vice President

Analysts

Jeffrey Campbell - Tuohy Brother Investment

Michael Glick - Johnson Rice

Patrick Rigamer - Global Hunter Securities

Andy Peterson - Simmons & Company

Doug Dyer - Heartland Advisors

Curtis Trimble - Brean Capital

Operator

Good morning ladies and gentlemen, thank you for standing by. At this time, I would like to welcome everyone to the Second Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Later, there will be a question-and-answer session. (Operator Instructions). Thank you.

I would now like to turn the call over to Mr. David Welch to begin. Please go ahead, sir.

David Welch

Okay. Thank you, [Teresa] and welcome everyone to the Stone Energy’s second quarter conference call. Ken Beer, our CFO and Executive Vice President will begin the meeting this morning with our Safe Harbor statement and a review of our financial performance for the quarter while also update guidance for the remainder of the year. He will then turn it back over to me for some additional comments on how we're doing executing our five-year plan. So, Ken take it.

Ken Beer

Great, thanks Dave. And I will first start with the forward-looking statements. 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 the risks and uncertainties normally incident to the exploration foreign development production and sales oil and gas.

We urge you to read our 2013 Annual Report on Form 10-K and the most recent 10-Q for 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 financial measures and the most directly comparable GAAP financial measures.

And with that, I'll move to the comments, we'll assume everyone has seen the press release and attached financials. Our second quarter earnings came in at around little over $4 million or $0.08 per share, there are few items which let us to be below the first call, earnings estimates including lower NGL and gas price realizations production falling within the lower end of guidance a much higher DD&A rate which is non-cash which certainly hit earnings and some smaller items that were mostly non-cash such as derivative expense and slightly higher reported interest expense.

Our discretionary cash flow for the quarter was just over $117 million or $2.25 per share. Production for the quarter was 44,000 Boe per day or 264 million cubic feet equivalent per day which was just under the midpoint of our second quarter guidance. There were several small negative impacts to production in the second quarter. First we had third party pipeline downtime in Appalachia about 7 million cubic feet per day for a week which impacted volumes by about 4 million cubic feet per day for the quarter, additionally we had a delay in hooking up pad in our Heather field, so there were really no new wells in Appalachia that was brought online in the second quarter.

In the Gulf of Mexico our production at Main Pass 288 which is now producing about 1,500 barrel equivalent per day was down for a month due to paraffin plug and the export line. And additionally we had scheduled downtown at (inaudible) which put over 5,000 barrel equivalents per day offline for about a week in the second quarter and another week in the third quarter.

As we look at the third quarter production guidance obviously the biggest adjustment will be in the recently complete sale of the non-core shelf properties which produced around 55 million cubic feet a day in the second quarter and produced just under 50 million cubic feet per day in July. Additionally, the scheduled downtime at Amberjack that stretched about three weeks in July and kept around 4,000 barrel equivalents offline as well as the previously mentioned week of downtime at Pompano.

However, on positive side, we’re adding 10 Marcellus wells from the Howell pad in our Mary field during the third quarter which should provide a significant boost in our Appalachian volumes. Additionally, we're getting about a 1,000 barrels equivalent per day from our recently completed Tomcat well, mostly common.

Currently, we’re producing in excess of 100 million cubic feet a day up in Appalachia. And in the fourth quarter, we expect to bring on another 20 new wells in our Mary field with incremental volumes also expected from our Heather field.

In fact, the incremental Appalachian volumes expected to be brought on line via the end of the year, should replace the 48 million cubic feet per day July volumes produced by the non-core shelf assets that sold just sold on July 31st.

So, after accounting for the roughly 50 million cubic feet equivalents per day drop from the non-core shelf asset sale, we expect to be between 222 million cubic feet and 234 million cubic feet equivalent per day around 38,000 barrels equivalent per day for the third quarter.

For the fourth quarter, we would expect to be back up in the 250 million cubic feet to 280 million cubic feet equivalent range as we add Appalachian volumes. As noted in the press release guidance section, without the property sale, our original production guidance would have been reaffirmed.

Also, as we look ahead to 2015, with the Cardona oil volumes coming on line early in the first quarter, we would expect our gas to liquids percentage flip-flop with our higher margin and NGLs being over 50% of our volumes in 2015. Interestingly when the projected volumes of the combined Cardona wells come on line, we would expect that these two wells would also substantially replace the volumes from the divested non-core shelf properties and the margins should be substantially higher. So we’re executing our strategy of replacing conventional shelf reserves in production with the longer life Appalachian and deep water reserves in production.

Regarding pricing, our quarterly oil price realizations were just under -- or just around $96.15 per barrel, with about 7% of the oil volumes coming from Appalachia which does pull down that weighted average price. However, the LLS premium over WTI which we’re getting on the Gulf Coast added about $3 per barrel to our GOM barrels for the quarter.

In the second quarter, our realized NGL prices averaged around $34 per barrel, a big, big drop from the $54 per barrel that we’ve got in the first quarter, which had a very strong product pricing because of the cold month benefited the first quarter NGL price. This NGL price difference is a big part of the earnings variance versus the first quarter. Henry Hub gas prices also dropped from the first quarter which combined with the widening Appalachian differentials caused our overall gas price realizations to settle at $3.77 per Mcf. Both gas prices and Appalachian differentials continued to be soft in July and into August as well.

We also experienced about 2.5 million in derivative expense during the quarter which runs through the income statement but it's mostly non-cash. This was largely due to accounting requirement which tied our non-core asset sale, tie to our non-core asset sales that caused us to record a larger derivative expense in the quarter about $0.03 per share.

On the cost side, our LOE was around $49 million for the quarter, pretty flattish but with the first quarter with the sale of a non-core shelf properties, we would expect LOE to decrease and have reduced our full year LOE guidance to a range of $175 million to $195 million.

The transportation process and gathering expense for quarter was $14 million, pretty flat with the first quarter, although we would expect this to increase in the third and fourth quarters with increased Appalachian volumes. Our DD&A rate for the quarter is jumped to around $3.82 per Mcfe from the first quarter rate of $3.38 per Mcfe, a major increase and the big part of the variance the first quarter of non-cash.

We had noted in our first quarter 10-Q in conference call the DD&A rate was expected to rise in the second quarter as we move to good portion of our unevaluated costs about $250 million from Amethyst, Tomcat, Cardona, Cardona South and Mica Deep prospects into the full cost pool. These Gulf of Mexico projects caused an increase in the overall DD&A rate. We would expect the DD&A rate to trend back down to the original guidance in the third and fourth quarters, especially as more Appalachian reserves added in overall lower finding costs.

The DD&A rate will also have a slight benefit from the sale of the non-core shelf assets. Accordingly as I've mentioned, our initial DD&A guidance remains intact somewhat of an anomaly in the second quarter. Our base G&A before incentive comp came in at just over $16 million for the quarter flattish with the first quarter and then reported interest for the quarter was around $10 million, a $2 million rise versus the first quarter of around $8 million due to a lower unevaluated property figure, a figure which determines the amount of interest expense to be capitalized.

Capitalized interest dropped to 11 million down from 13 million in the first quarter, which mirrored the rise in the reported interest. Also remember about $4 million of the reported interest expense is non-cash tied to the convertible notes accretion. Our total cash interest is still running at around $16 million per quarter. Regarding taxes we came in at a 40% reported tax rate for the quarter with all of it been deferred, however this was a small number so we still expect the annual reported tax rate to be around 37%.

Our CapEx for the quarter was just over $250 million. This included capital for the completion operations for both Cardona wells continued spending on the Cardona loop tie back systems, capital for the Mica Deep exploration well and completion and facilities capital for Tomcat. As we follow-up with development spending in Amethyst with a 100% working interest potentially spudding other deep gas well and drilling our Utica test well as well as adding to push additional Appalachian acreage. We would expect some pressure on our original $825 million CapEx budget.

On June 30th, we announced the purchase and sale agreement with Talos Energy to sell our non-core shelf assets for $200 million. This transaction was completed on July 1st at an adjusted purchase price of $178 million and allows us to further focus on our core growth areas. We’re down to two core operated shelf properties at Ship Shoal 113 and Main Pass 288 both of which have opportunities that our technical teams have been working. These two fields are producing approximately 6,500 barrel of equivalents per day substantially all the well.

During the quarter we also renewed our credit facility with more favorable terms and an increase in our borrowing base from 400 million to 500 million. The facility remains undrawn except for 21 million in LCs and at August 5th after our July 31st close from the sale of the non-core shelf properties we had about $445 million in cash, so plenty of liquidity. We believe that this liquidity will fund this well into 2015 and provide the balance sheet strength and flexibility to move forward on a long-term deep water rig commitment accelerated development of Amethyst and a potential Utica drilling program.

We did add a couple of more 2015 oil hedges to further protect our cash flow and CapEx program and have included our updated hedge position in the press release.

I believe that wraps it up with the financial overview and that I will turn it back over to Dave for additional comments.

David Welch

Okay, thank you Ken. And as Ken said just to reiterate that our production was slightly below midpoint of guidance, but that our future guidance which is adjusted for the shelf sale would have been reaffirmed have we not concluded the non-core shelf property sale.

The quarter was filled with several important achievements that we believe indicate future value creation ahead. We are continuing to pursue our strategy to take advantage of the two technology breakthroughs at our industry deepwater and horizontal drilling and hydraulic fracturing. And we are still very well positioned to take advantage of both of these technologies owning a 107 deepwater leases, two deepwater hubs in the Gulf along with an approximate 35,000 net acres position in the super rich portion of the Marcellus shale and 28,500 net acres in the dry gas Utica in Appalachia. And both of these areas have material production and reserves are ready as well as significant and near-term development exploration potential.

In the deepwater area, we have sanctioned the development of the Amethyst discovery that was announced in the first quarter. We own a 100% working interest in Amethyst and are targeting to be online by the middle of 2016. This well is expected to be a high rate completion, potentially exceeding 40 million cubic feet of gas plus an associated liquids of 60 to 80 barrels per million cubic feet.

During the quarter, we developed a plan to build the flexible flow line subsea tieback to our Pompano hub. We have generated a project expectation timeline and are currently on track to deliver the project as planned. We placed the order for long lead time items such as the flow lines and umbilical in July.

One of our most important development discoveries are earlier in the year are also progressing well to our production and these are the Cardona and Cardona South wells. The Cardona project is a dual flow line subsea development for these two wells with capacity for an additional two wells. The project is presently running below budget and ahead of schedule.

We have a very light hurricane season. It's possible that we can deliver the project for about $20 million less than budgeted and maybe even come online a bit earlier. We have expected and guided first production towards the first quarter of ‘15 and with the work that's completed so far, we now have increased the probability that we'll be able to meet or even beat that target.

Both of the wells have been drilled and completed. The rig’s been released. The Cardona and Cardona South wells were completed in text book fashion. The umbilical has been installed and we expect to begin laying the flow lines in September.

Flow line construction will start shortly, when we begin welding a 30 foot long insulated flow line pipe joints together into two 8 mile strings and then spill them on to the installation vessel. These lines will then be laid on the seafloor and connected to the well on one end and the platform on the other. Once this is done, we will begin the commissioning of system and then go through our production start up procedure.

It's an exciting project for us. This is our first company operated deepwater subsea tieback. We own 65% working interest in the project and expect the gross total of about 12,000 barrels a day when it’s ramped up to full production.

The anticipated rate exceeds 50% of our current companywide daily oil production rate. And in addition, the production handling fees that we received from processing our partners’ production are higher than the incremental LOE expense of producing the wells at Pompano. Our margin is expected to be higher than the price of oil for these two wells. So, you may recall that the Cardona South well found over 275 feet of net pay in three sand intervals. We believe the reserves here are large enough to support the drilling of another low risk development well and possibly even a third one.

We're working on these prospects right now and the Cardona flow line loop and control system would allow us to put two additional wells on production shortly after the drilling in completion. The next Cardona well beyond the two that are drilled now could be drilled in late 2015 or 2016.

In addition to the Cardona development program, we also plan to commence a platform development drilling program at Amberjack around year-end this year then at Pompano late next year.

One of the best features of the platform drilling program is that there is very little delay in getting the wells on production once they are drilled and completed. This helps to underpin the economic return of the program as well as our projected production growth. We plan to start the Amberjack program where we expect to drill either four, five wells and move to Pompano to drill four additional wells there with a separate rig once all of our Cardona and Amethyst tieback 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 flow over the next few years. The next potential deepwater exploratory well to be drilled is our former 21 prospect now known as Harrier, and operated by our joint venture partner ConocoPhillips. We currently have a promoter right to a 37% working interest in the block with the 20% cost interest in the well which is a Miocene test. This well is likely the spud in the first quarter of 2015. The prospect is adjacent to a block Chevron won in last year sale with a bid of over $50 million. So it’s possible that a joint well could be drilled covering both blocks and with differing costs, different working interest and different timing.

Nonetheless, this is an exciting prospect sought after by many exploration companies and we’re very anxious to get it drilled. It now looks like the other non-operated prospect that has been on the horizon Goodfellow will be drilled in 2015 and not 2014. Goodfellow is the prospect offsetting the Giant Shenandoah discovery and is operated by E&I. We hold the 13% working interest in this potentially large geologic structure which we've estimated a P90 to P10 range of around 80 million to 800 million barrels of gross potential resources if it works. We’re currently in negotiations to join the drilling of two additional deepwater exploration prospects expected to spud in the next several months.

All we can say about these right now is that they’re in the Mississippi Canyon area and similar in concept to discoveries being made in the area. One of these could potentially be a to tie back to Pompano. Our deepwater lease base now comprises a 107 blocks, 60 Stone operated blocks and 47 non-operated blocks. If we participate in these two additional exploration wells, we'd earn an interest in another four blocks.

In addition, we now believe that we have enough company-operated exploration prospects, well completions and development drilling prospects to keep a deepwater rig busy for two to three years. Since the deepwater rig is softened, we've tendered to the market for a versatile rig which we expect to sign for a two to three year term at an attractive rate. We’re currently in discussions with the two top rig contractors to select one of those that we believe will be our best partner and we could be in a position to sign a contract on a deepwater rig later this year for use mid next year in our robust portfolio of company operated properties.

In our deep gas area, we now have placed a 100% owned Tomcat discovery at West Cam 176 owned production. It looks like Tomcat has turned out to be more of an oil well than a gas well. We are producing about 750 barrels a day and a couple of million cubic feet of gas. This reduces our equivalent production but obviously oil is more valuable than gas. In deep gas exploration, we have acquired a rig contract to drill two onshore Louisiana wells. We operate and will likely drill La Montana prospect starting early next year and be followed by the Cayenne prospect later in the year.

We currently own a 100% working interest in La Montana but expect to bring in a partner for 25% and own a 50% working interest in Cayenne. Both prospects are targeting potential gross reserve resource range of P90 to P10 in the range of 10 Bcf to 200 Bcf of liquids rich gas.

If one or both of these are successful, we should have another quick to market source of cash flow. The sand is being tested are similar in age and hopefully quality as those in our La Cantera discovery whose wells are each capable of delivering growth rates in the range of 40 million cubic feet natural gas per day plus associated liquids. The conventional shelf continues to provide us with excellent production and cash flow, thanks to an active and very successful work over schedule and despite no drilling this year.

We have now completed the sale of all of our non-core Gulf Coast properties to just under $300 million which includes the onshore component in cash and the transfer of about $150 million of abandonment liabilities to the purchasers. This leaves us with two core oil fields on the shelf Ship Shoal 113 unit area in the Main Pass 288 field, we see further development drilling opportunities in each of these areas and may choose to resume this drilling in 2015. These two fields are still providing us with about 6,500 barrels of oil equivalents per day. And after the sale the Gulf Coast comprises less than 5% of our total proved reserves. We did retain an option for 50% of the Deep rights, in case we find additional deeper prospects on some of our current acreage.

Finally, our last growth area is Appalachia. The Marcellus and West Virginia continues to grow, our proved liquid rich Marcellus reserves now make up over half of our proved reserves at approximately 0.5 Tcf of natural gas equivalents, and our net probable, possible and prospective resources for the Marcellus could aggregate to over an additional 1 Tcf.

Our drilling performance continues to improve as we now around pace to drill over 34 wells this year with our one top hole and one horizontal rig program. We are continuing this dependable predictable Marcellus program now focused exclusively in our Mary field and West Virginia.

We've just completed fracking the Howell pad, which is a 10 well pad in the Mary field and that is beginning to come online now. On this pad, we have optimized our completion in frac design and could see some higher well results than our past practice had provided. We'll have an update on that on our next call.

Nonetheless, even though we had a third party pipeline slip and some curtailment in the second and early third quarter, we still anticipate delivering our original forecasted annual production from the Marcellus. We expect to average a 100 million cubic feet a day of production from the Marcellus this year, which is an important target and milestone for the company.

We believe we’ve developed a competitive infrastructure advantage in our Mary area of operations consisting of proprietary road system, water handling system, gathering system and to capture of most of the viable pad locations with our perimeter. So this infrastructure will be particular help if we’re successful with our exploration test on the potentially large resources in the Utica Shale at Mary. Only a few miles from our Mary field multiple Utica wells have recently tested with initial production rates exceeding $20 million in over 35 million cubic feet per day of dry gas. Production has been established on the Northern Western and South Western edges of our acreage and our wells are planed to the east of the acreage in Mary as well where we own about 28,500 net Utica acres.

We’ve begun operations on our own Utica exploration well at the triple pad in the Mary field, in Wetzel County, West Virginia. We’re drilling the final section of the vertical portion of the well and we’ll be taking course and capturing other geologic and engineering data to better understand the rock and fluid properties before we drill the horizontal well.

We will know shortly whether we found pay and are targeting about 90 to 95 feet of potentially productive Utica Shale. On our acreage at Mary, the Utica is about twice as thick and higher pressure than the Marcellus, so we’d expect greater gas storage volumes in the reservoir and more energy to push the gas out of the rock, thus significantly higher production rates and recoveries per well than the Marcellus. After we capture the needed data, the large rig is actually on the well and we’ll commence with the drilling of a 3,750 foot horizontal leg. We’re also designing the plant completion and expect to frac the well and test it later this year. The frac will probably contain about 15 to 20 stages. We do not believe that this will be the optimal horizontal link for Utica development well where we had an existing permit that allowed us to drill 3,750 feet and we wanted to get the well drilled and get some data we could use to quickly access our potential and to help design an optimal development program.

So, we are presently considering the best option for potential Utica development plan and a potential combination, Utica and Marcellus development plan. Both of these options would take advantage of the infrastructure already owned at Mary if the exploration test is successful and the economics are compelling, execution of a Utica or joint Utica and Marcellus developments could potentially commence in 2015.

We believe the Utica potential on our acreage is high and this success could have material implications on our future production reserves and value creation in Appalachia. The balance sheet is in excellent shape. We ended the quarter with over $330 million in cash and approximately $160 million in additional proceeds from the shelf non-core property sale have been deposited since quarter end. We also have an increased borrowing base of $500 million, which is up from $400 million on our revolving credit facility.

As Ken mentioned, the revolver is undrawn with $479 million available after $21 million of letters of credit outstanding. We feel that we now have the financial flexibility to execute our business plan. Our $825 million capital program has yielded positive dividends for us this year and in light of our success with the drill bit we will likely seek Board approval to increase that a bit to cover completion and other development costs such as long lead items Amethyst. This should enable us to bring production online in accordance with our five year plan. Our investment capital is majority weighted toward lower risk development prospects than already successfully discovered deepwater such as Amethyst, Cardona and Cardona South, platform development, drilling at Amberjack and Pompano and deepwater in the Marcellus and Appalachia.

Hopefully this group will soon include the Utica and Appalachia. We're in the midst of an exciting successful year even with a couple of minor production issues which cause us to be below the mid-point of guidance in the second quarter. We believe, we're still on track to deliver or exceed our full year plan.

It’s still possible that we will be able to organically grow our reserve this year even after selling off our non-core conventional Gulf Coast properties and we expect production to comeback strong later this year or early next year. In addition, we have the number of exciting exploration opportunities to execute and we'll hopefully lead to an ever improving five year plan.

So with this we will be happy to take your questions. And Teresa I'll turn it back to you for the question in queue.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And your first question comes from the line of Jeffrey Campbell of Tuohy Brother Investment.

Jeffrey Campbell - Tuohy Brother Investment

Good morning.

David Welch

Good morning.

Jeffrey Campbell - Tuohy Brother Investment

Let me, I apologize in advance I missed the dollar figure as came on to the call. But I did hear you discussing your deepwater rig here in the negotiation say, back in the Analyst Day, you were talking about maybe being able to procure something for around 375 day rate. And I haven't seen any publicly announced contracts since that time that indicate that degree of softening. So just wondering are you still hopeful to get those kind of terms I think you modified your goals?

David Welch

We're still hopeful, we don't have any ink on paper yet. But we're still in some good and serious discussion with two separate companies and I think we'll have a good chance to meet our original target.

Jeffrey Campbell - Tuohy Brother Investment

Okay. That’s fine. Thank you. In yesterday’s press release you mentioned Cardona and Cardona South coming online at approximately 12,000 Boe per day. At the Analyst Day, I thought you were guiding 10,000 Boe per day expectation, did I misunderstand or have you upwardly revised your expectations? And if it’s latter what’s behind the higher number?

Ken Beer

Yes Jeff this is Ken. I think at the Analyst Day we really were suggesting and we have been pretty constant on this that both of these well we have kind of as suggested that the productions could be somewhere around 6,000 a day on per well. And so really we just putting them together and assuming somewhere around that 12,000 barrels a day, obviously we won’t know the exact number so we would bring them on, but that’s at least our estimate or projection and we have been pretty consistent with those numbers.

David Welch

And I will give a little piece of color on that. If we had a 10,000 number floating around before, we have now competed the wells. And as I mentioned in my comments that the completions went off in textbook fashion meaning that we have really, what we think a really good completion. So I think we feel pretty confident, 12,000 barrels a day is a pretty good number.

Jeffrey Campbell - Tuohy Brother Investment

Okay. Good. Always none of it positive here one way or the other. The last question I will ask is are you still on track to doing upper zone perforation in Tomcat, you mentioned how which you have gotten so far is oilier than expected. Is this still going to take place sometime late summer or early fall and what kind of production uplift are you looking for?

David Welch

Yes. No I think basically what we have at Tomcat is what we have got. It turns out we got a little oilier well, when you translate that to equivalent production it’s not as high but obviously oil is more valuable. We’re going to do a shut in the well, do a build up test and kind of get an idea of reservoir volume and that will tell us whether or not we are connected to a large volume or just kind of an average volume. And if we are connected to something large there may be an opportunity to a couple of offset wells, if not than we are probably done at Tomcat.

Jeffrey Campbell - Tuohy Brother Investment

Okay great. Thank you.

Operator

And your next question is from the line of Michael Glick of Johnson Rice.

Michael Glick - Johnson Rice

Good morning. Just a couple of questions on Cardona. Once the loop system is installed, how long should the commissioning process take?

David Welch

Well, the commissioning itself is probably a month or so. And then the ramp up is probably another month Michael. So, we're looking at a couple of months overall. We're not going to just try to bring these wells on it for a rate on day one. We'll bring them up slowly and let the -- both of these wells are frac pack. So if you bring them on slowly the frac, the sand and the frac pack or the gravel pack is kind of like a lock cab in house you know that settles a little bit after it’s, put in a dynamic situation and if you do that kind of on a slow and general inclining draw down basis, it settles in pretty nicely and generally they last long, long time. So, that's we're going to do with them. But I would count on a couple of months.

Michael Glick - Johnson Rice

Got you. And then I guess what type of production profile should we expect for 2015?

David Welch

Ken, have you got anything on that?

Ken Beer

You mean the Cardona?

Michael Glick - Johnson Rice

Yes, Cardona.

David Welch

Typically, these wells if they come on about 12,000 barrels a day combined like we were talking about, you would expect to have constant production period for maybe six months or so and then start a little bit of a decline, that would be typical, I don't have the specific Cardona profiles in front of me to mark on.

Michael Glick - Johnson Rice

Got you. And then just jumping over to Appalachian real quick. On the helipad you mentioned you are changing the completion on those wells versus the other wells in the area. What exactly are you doing differently there?

David Welch

We just gone to a little bit denser stage spacing and maybe a little bit more dense profit.

Michael Glick - Johnson Rice

Okay, got it. Thank you.

Ken Beer

Thank you, Mike.

Operator

The next question is from the line of [Tom Nowak of Advent Capital].

Unidentified Analyst

Hey good morning.

Ken Beer

Good morning, [Tom].

Unidentified Analyst

Sorry, if I missed this. But given the moving parts of Tomcat, Marcellus wells, Cardona, can you give us the evolution of the gas mix over the second half of the year and then through ‘15?

Ken Beer

Yes, Tom. I think you’ll see obviously the properties that we sold, the non-core shelf properties were almost 60% gas, 40% liquids. But the volumes that we’re bringing on are primarily the Appalachian volumes which tend to be about 70% gas and 30% liquids. So, I think you’ll continue to see from the second quarter which I think was 51% gas. So, I think you’ll see a slight rise in gas as a percent of the total. As I alluded to on my comments, as the Cardona wells come on and kind of net to Stone would be somewhere around 7,000 plus barrels a day something like that, because we’ve got a 65% working interest. I think you’ll see a flip-flop where you should have slightly more oil and then NGL places liquids than natural gas in 2015.

Unidentified Analyst

Okay. Fair enough. And then you’ve got a lot of projects in-house which is great and I do have even in ‘15 with okay liquidity cushion, but it does look like maybe towards the back half of ‘15 you’ll probably need to be considering additional funding. Any thoughts to that yet; is it selling down any projects that you have or you look for additional external capital?

Ken Beer

Really, we're kind of entering the back half of this year and really the first half of next year, obviously in very good position. It allows us to really step back and evaluate a lot of different financial options whether it’s selling down some assets, selling some assets, bringing joint venture partners. We've talked about this in the past and we do feel it's important to keep our liquidity and flexibility, especially as we do have a number of different projects that are requiring capital; certainly we got a lot of time to evaluate different options.

So, I think as I’d mentioned earlier, we’re certainly in good position now through to certainly well into 2015 and we'll evaluate the different options as we kind of roll into 2015.

Unidentified Analyst

Okay.

David Welch

I’ll just add to that. But our main focus is getting our cash flow up, getting production growing, hitting the good -- a better oil mix as you asked on the previous question.

Unidentified Analyst

Okay, great. Thank you.

Operator

The next question is from the line of Patrick Rigamer of Global Hunter Securities.

Ken Beer

Good morning, Patrick

Operator

Go ahead Patrick, your line is open

Patrick Rigamer - Global Hunter Securities

I am sorry. I had on you mute. Following the shelf sale, it looks like you guys have escrowed the funds potentially for a light kind exchange. You talked about potentially coring up some acreage in the Utica within the Mary Field, can you just talk about what that market is looking like these days and how that might play out with the [Lycon] exchange; is that eligible for [Lycon] exchange or?

Ken Beer

Yes, kind of two separate questions. First on the 1031, thought there was effectively a free option; as always, we continue just to kind of look at different opportunities; gives us kind of a 45 day window for few thousand dollars. We can park it as we evaluate different potential opportunities on the acquisition side.

So, it just seemed like for few thousand dollars to have what potentially could to be tens of million dollars of tax shield seems like an appropriate financial move. And we’ll continue to evaluate those opportunities over the next month and half. As it relates to acreage, acquisition up in the Wetzel County area and our core area, we do continue to look at adding acreage; it’s very difficult up there, as I think you’re well aware. There is very few larger tracks available, so we just continue within our parameter to try to add on to our four position.

David Welch

Yes, the other thing I would just add to that is that our strategy is basically organic growth, but we are opportunistic and if an acquisition comes along, this is suggest the tax efficient way to take advantage of it.

Patrick Rigamer - Global Hunter Securities

Okay. And then on the initial Utica well, you are going to drill vertical section log and core and then drill the horizontal. It sounds like production is not expected until the fourth quarter. Do you think you release any interim data or how should we think about the data flow coming out of this well?

Ken Beer

Again, we'll probably truly play that by year, try to get a sense as to the timing of it, does it dovetail for instance with our third quarter release. So again, we will -- when we have that information and that data, we will internally kind of have those discussions. And if go is appropriate, we will move forward with a separate press release.

Patrick Rigamer - Global Hunter Securities

Okay. And then the last one from me is at the Analyst Day, I believe you talked about some infrastructure upgrades in the Marcellus that could have a positive impact on realizations. Could you give us an update on that? And just kind of what’s going on in terms of the pricing situation there?

Ken Beer

Sure Patrick. And on the midstream side, particularly as it relates to capturing better pricing out of the liquid side of that stream, those projects are continuing and have continued. Unfortunately obviously any sort of gains we are getting on cash and higher liquids realizations have been unfortunately negatively offset by gas price differentials up in the Appalachian region. So, I don’t -- unfortunately pricing is very dynamic and so we are taking effectively a small step forward but the gas pricing is causing us to take couple of steps back.

Patrick Rigamer - Global Hunter Securities

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

Ken Beer

Thank you.

Operator

The next question is from the line of Andy Peterson with Simmons & Company.

Andy Peterson - Simmons & Company

Good morning.

Ken Beer

Good morning, Andy.

Andy Peterson - Simmons & Company

Taking David’s comments about trying to raise cash flow, should we think about you guys accelerating some of your shorter cycle assets like the Marcellus and depending on how this Utica well is tested, the Utica as well?

David Welch

What I was really talking about is more along the lines of just executing on time, on budget and that sort of thing. And so, I wasn't really talking about bringing anything new into the equation just doing maybe sure, we don't have any delays in production and bringing online the things we've already articulated to you.

Ken Beer

Having said that, Andy one of the things I'll add is as we look at our portfolio of projects, we do take into account those projects that have a shorter cycle time versus longer. So we want to make sure that we don't have a bunch of big bets on very long cycle time projects as opposed to what we think is a more appropriate mix. We'll have some deep gas projects which have shorter cycles, we will take some bigger swings such as the Goodfellow type projects. But as Dave pointed out, we want to make sure is that we do execute projects like Cardona where we're able to finish drilling and hopefully that would bring this online within a six months time period is very quick cycle time, if we move forward with the Amethyst project and get that on as quickly as possible, obviously that's where cash flow comes in a little earlier and our net out of pocket capital is just lessened.

Andy Peterson - Simmons & Company

That make sense. Thanks guys. And then also you talked about denser stage spacing and a little bit more propane in the Marcellus wells. What inning are we in as far as tweaking the completion design, and could you talk to the other things that you guys are thinking about doing in the Marcellus in the Appalachian region?

David Welch

Sure. I’ll take a stab at this is a little bit speculative, but there is some interesting technology that’s been applied in some of the other resource plays, where in cross-linked fibers have been used to keep the propane vertically suspended better to try to get a better frac. That technology has not yet available in the Marcellus because the temperature is too cool in the Marcellus. But they’re working on those fibers now so that’s a possibility. Then there is also the possibility of adding a fiber pad kind of as you instead of a put in many stages the pump a set of frac, you pump a frac, then you would pump some fibers to seal off that frac, pump another frac, so you effectively increase the number of stages by putting this fiber pills in there and the fibers act as permeability barriers of course won’t flow through them but they dissolve with time and temperature. And so once they dissolved then you have a better frac than you have before. That’s been used in the Eagle Ford and then some of these other oil areas around the country, as soon as its available temperature-wise we’ll test it out in the Marcellus whether that’s going to result in a 2% improvement or a 20% improvement obviously it’s too early to tell.

But I think we’re -- I think the industry is probably in the mid innings on technology we’ve learned a lot but there is still maybe some new things that come down in the pipe.

Andy Peterson - Simmons & Company

Perfect, thank you for that. And then one last quick one for me on the NGL realizations, how should we think about going into the second half of the year, obviously Stone isn’t the only operator who has seen degradation in NGL realizations. But do you guys think that we won’t see an uplift until we start getting into the solar season in the winter months and just if you could provide any color on that, that will be really helpful?

David Welch

I think you just said and I think as we look at the summer months in that low to mid 30s is probably the place that we will continue to see pricing fallout for NGL pricing, I think it will take us getting back into the winter months to have a bit of a rebound on that pricing.

Andy Peterson - Simmons & Company

Excellent. Thank you guys, I really appreciate it.

Operator

The next question is from the line of Doug Dyer of Heartland Advisors.

Doug Dyer - Heartland Advisors

Good morning gentlemen. Could you please tell me what the circumstances are led to Goodfella being pushed out for drilling into 2015?

David Welch

It’s just a rig schedule thing with ENI there, they are the operator and they’ve got rig schedule the projects that they want to execute and it was their decision, it wasn’t anything that we had an impact on.

Ken Beer

And Doug I think there is also the bone came back with a second request on their EP that cause a little bit of delay even from Eni standpoint.

Doug Dyer - Heartland Advisors

Okay. And going back to Pompano and where you're going to be processing your partners or you are coming on Cardona, should I assume into your accounting for that is just straight forward, there won't be any type of offsetting that close to in your income statement when it comes to LOE?

Ken Beer

Yeah. Now, you should assume that it is a direct offset to LOE and as Dave made the comment, effectively the dollars that we will get from our partner will be effectively a negative LOE and that's why our LOEs will stay roughly flat, if not down slightly relative to the barrels that we're bringing on for ourselves. So from accounting standpoint, you're not going to see that in the revenue line, you'll see it the contra expense to LOE.

Doug Dyer - Heartland Advisors

Okay, alright. That's what I was looking to find out. And then when I run the numbers here with your new guidance and going into next year using today's prices, I'm coming up with an EBITDA number where you can do 6.75 next year, it doesn't look like it will take any heroic efforts to get there and I'm not even giving full credit for the production that comes on. And if that’s the case we are trading up four times price by the EBITDA. Do you think that's reasonable number that I'm coming up with 2015?

David Welch

Yes, we've really stayed away from coming out with any blessing on cash flow or EBITDA certainly a lot of it always depend upon pricing. But certainly to your point Doug we certainly would expect in 2015 to have EBITDA moving up even despite the sale of non-core shelf properties. We do expect that EBITDA number to step up versus 2014.

Doug Dyer - Heartland Advisors

Alright. Thank you.

David Welch

Thank you, Doug.

Operator

And your next question is from the line of Curtis Trimble of Brean Capital.

Curtis Trimble - Brean Capital

Thank you. Good morning, everyone. Just skiing an off of the little detail on the Amberjack platform potentially the initiate activity in 2014. I was hoping you could remind me of well profile and what you expected to define there with the four to six development wells that potentially could start drilling like to share early next year?

David Welch

Yes let me think we have about four wells maybe five well planned there. These are wells that are in the neighborhood of a 1,000, 2,000 barrel a day type wells, so they will have a positive impact they won’t all layer in at exactly the same time because as soon as we drill one, we’ll put it on production. But it will be a good positive for us and help underpin our base. Ken, anything you want to add?

Ken Beer

Yes I think in some of these wells will be under 1,000 barrels a day and you will see some decline as Dave pointed out there will obviously be sequential this is more to provide a good offset to just natural decline more than anything else, this isn’t going to dramatically increase production but provides good stability and particularly good oil production of the Amberjack platform.

Curtis Trimble - Brean Capital

Sure…

David Welch

I think in aggregate, we are going to spend around $75 million there and we are expecting about 2,400 barrels of oil equivalent from the Amberjack program, the Pompano program is a little bigger so about $125 million program and we are expecting a peak rate of around 5,500 barrel a day for it, but Pompano won’t get started until the end of next year.

Curtis Trimble - Brean Capital

Right and that just has to do with the availability of the platforms that are capable of drilling off each platform, excuse me, are capable of drilling of each platforms.

David Welch

Yes two things, one we have some platform modifications underway for both Amethyst and for Cardona, the Cardona will be long finish, but we will be working on the platform a little bit for Amethyst. So we want to get that work finished before we put a rig on there. And then the second is just the availability of the rigs and we expect to have the Amberjack rig available end of this year and Pompano before the end of next year.

Ken Beer

Yes. To Dave’s point, I mean the Silver Lining, obviously we would love to have that Pompano platform rig as soon as possible but the Silver Lining has been, our guys have been able to make those platform modifications for both Cardona as well as importantly Amethyst. So, we’ve be given some extra time to do that with the pushback in that rig coming available.

So, that would be the Silver Lining as we’ve been able to move forward, particularly with Amethyst.

Curtis Trimble - Brean Capital

Very good. Looking up in the Marcellus, can you tell me the number of Utica locations that you permitted? And as you are looking towards that, what you think optimal lateral lengths maybe and the number of frac stages prospectively that you would look to create over that optimal lateral length?

David Welch

Sure. I’ll give you kind of our early view of it. We have probably less than a handful permits in hand right now. We are working on a development plan, which will drive our permitting schedule. And so, we expect that if our well works this year, sometime next year, mid-year to beyond, we might be in a position to start doing some Utica development.

Ultimately, we think it’s going to probably be well over 5,000 feet of our horizontal need there, maybe even longer. So, I mean we’re drilling, I think 5,600 foot laterals in the Marcellus. I would expect that we’ll drill at least that or longer in the Utica if it works, just because you have a deeper zone, you have more expense on the verticals, so to keep the ratio of vertical to horizontal cost and to get the results per well. But that's going to have to be refined over time as we get a little data on what works the best before a program is settled in on.

The good news is though, there probably, I don't know there will probably be a dozen or so Utica dry gas wells drilled in the area that will have some entail on not just what we do but what others are doing with respect to horizontal length and completion techniques.

Curtis Trimble - Brean Capital

Sure. And prospectively 32 to 35 stages over that 5,600 foot lateral give or take?

David Welch

I think we’re doing something in neighborhood of 200 to 250 foot stages right now. So if you just divide that in there, give you the stays length, I am not sure exactly what they will work out to.

Curtis Trimble - Brean Capital

Very good. I appreciate the detail.

Ken Beer

Thanks.

David Welch

Thanks Curtis.

Operator

And there are no further questions at this time.

David Welch

Okay. Well, thank you very much everyone for joining the call. A little bit of a pick up on the quarter I realize but I think long-term our plans are still intact and that we’re very excited about moving forward. And thank you for your patience and interest in the company so long.

Ken Beer

Thank you.

Operator

This concludes today’s conference call. You may now disconnect.

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Source: Stone Energy's (SGY) CEO David Welch on Q2 2014 Results - Earnings Call Transcript
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