Talos Energy Inc. (TALO) Q1 2015 Earnings Report, Transcript and Summary

Good morning. My name is John and I will be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy first quarter 2015 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

Thank you, John. Good morning and welcome once again everyone to our first quarter 2015 earnings conference call. This morning we’re joined by Ken Beer, our Executive Vice President and Chief Financial Officer. Ken will read our cautionary statement and review our financial performance for the quarter, then turn it back over to me to provide you with some color on our strategy operations update and a status report on our response low price environment. Ken, to you?

Thank you, David. Let me first start off with just this forward-looking statement. In this conference call, we may make forward-looking statements within the meaning 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 exploration, development, production and sales, of oil and natural gas. We urge you to read our 2014 annual report on Form 10-K and the soon to be filed first quarter 10-Q, for discussion of the risks that could cause our actual results to differ materially from any of those made in the forward-looking statements we may make today. In addition, in this call we may refer to financial measures that may be deemed to be non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday for a reconciliation of the differences between these financial measures and the most directly comparable GAAP financial measures. With this we’ll assume people would have seen the press release and the attached financials, additionally our focus on some of the financial and operational highlights. Our first quarter results showed an adjusted $13 million loss or a loss of $0.23 per share before and after tax noncash impairment charge of $314 million, which brought the reported loss to $327 million. Our discretionary cash flow for the quarter was around $85 million or about $1.50 per share which was above the first call consensus driven primarily by greater than expected production and lower cost. As results were discussed in last quarter’s conference call, the noncash ceiling test impairment was primarily to lower net oil and gas and NGL prices, which were calculated using a rolling twelve month trailing average. The prices continued to stay at a lower level, compared to last year, we’ve made this subject to another noncash ceiling test impairment charge in the second quarter. No impact on cash flow, but a potential reported earnings impact. Production for the quarter was just above the upper end of our quarterly guidance at 46,000 barrel equivalent per day or 278 million cubic feet equivalents per day. Volumes from the Cardona project and the Gulf of Mexico and in the Appalachia were above plan, contributing to a 9% jump in overall production versus the fourth quarter. With the added production from the oily Cardona wells, liquids totaled 55% of our first quarter volumes, with gas at 45%. Our Cardona system volumes have remained stable at around 10,000 gross Boe per day and the Cardona 6 well to be drilled this year could add another roughly 5,000 gross barrel equivalent per day by the fourth quarter of this year. Stone has a 65% working interest in the Cardona well. In the first quarter averaged just over 130 million cubic feet equivalents in Appalachia, although we would expect these volumes to decline throughout the year as we don’t expect any new wells to be drilled and completed in 2015. However, we project the average Appalachian volumes for 2015 to be around 115 million to 120 million cubic feet equivalents per day, which would be a 15% to 20% increase over 2014 Appalachian volumes. Additionally we have 25 wells on three pads where we’ve drilled, but not completed the wells, are just awaiting for pricing [ph]. Overall we’re maintaining our 2015 production guidance of 39,000 to 43,000 barrel equivalents per day or 234 million or 258 million cubic feet equivalents per day, which is around a 10% increase over 2014, when you preform after the property sales last year. We’ve also provided guidance for the second quarter of 2015 of 41,000 to 43,000 Boe’s per day or the 246 million to 258 million cubic feet equivalents per day. After the first quarter, the second and third quarter production will be subject to our overall natural decline, until the Cardona number 6 well provides incremental volumes in the fourth quarter. And then volumes from Amethyst and Pompano platform rig program are projected to kick in during 2016. Additionally as we noted in the press release there is some plan downtime on Destine pipeline system during the second quarter, which will restrict and negatively impact our volumes at Pompano for about three or four week by approximately 10,000 net Boe per day during this downtime. This has been incorporated in our guidance. Regarding pricing, our quarterly oil price realization before hedging was around $45 per barrel, which is down over a $50 per barrel from a year ago. Our oil hedges at $92 per barrel, pulled up our first quarter realized price to just over $66 per barrel, but the oil price drop was obviously a significant hit to our revenues for the quarter. Similarly, our gas price realization even after hedging dipped to under $2.55 per Mcf for the first quarter, due to both weak Henry Hub benchmark prices as well as the negative Appalachian differential. We’re hopeful that the expansion programs for the midstream and pipeline companies in the Appalachian area will increase the access out of the base and then reduce the negative differentials over the next 12 to 18 months. We have secured sales arrangements through the year, which provides us for a market for our gas, but we’re still subject to the pricing at the M2 index. In the first quarter our realized NGL prices averaged around $18 per barrel, down 65% versus a year ago as NGL pricing suffered a severe discount in already low product pricing environment. Fortunately we are seeing some recent positive upward movement in both oil and gas pricing relative to the first quarter and hope that this trend continues for a while. On the cost side, we had some very good news with our LOE dropping to about $28 million for the quarter versus $47 million in LOE in the first quarter 2014 and a drop even from $37 million in the fourth quarter of 2014. The sale of the noncore shell properties in the third quarter of last year was the primary driver for the year-to-year decline, but we’re also pushing down ongoing LOE cost as it’s evidenced by the quarter –to-quarter drop. On a per unit basis, we’re down to an impressive $6.60 per Boe or $1.10 per Mcfe, as the Cardona volumes added no net incremental LOE and the Appalachian LOE comes in at under $0.40 per Mcfe. The transportation, processing and gathering expense dropped from $19.5 million for the fourth quarter ‘14, down to $17.7 million in the first quarter of 2015 despite a quarterly increase in Appalachian volumes and this is just due to a lower cost in two efficiencies that are finally kicking in. Our DD&A rate for the quarter was $3.41 per Mcfe, due to the ceiling test impairment we would now expect the DD&A rate to be down in the $3.30 per Mcfe for 2015, although any future potential ceiling test impairment may indeed impact this ratio. Our base G&A before incentive comp came in at $17 million for the quarter. We would expect this area to trend down slightly during 2015, as we’ve had staff and cost reduction and the first quarter did have some small charges that were tied to this reduction. Reported interest for the quarter, which is just over $10 million again flat versus the fourth quarter. Once again, also remember that $4 million of this reported interest expense for the quarter is noncash interest tied to the convertible note accretion. Our total cash interest is still running at around $16 million per quarter. Regarding taxes, our reported income tax were negative due to net loss for the quarter and we do not expect to pay any cash taxes for 2015. Our CapEx for the first quarter was approximately$114 million. As previously disclosed, our board has authorized the 2015 capital budget at $450 million dollars, although this does assume a sell down of some minority work interest in certain - at targeted assets. At 03-31-15, we had just over $150 million in cash and last week our banks reaffirmed our $500 million borrowing base, which remains undrawn except for about $19 million in LCs, so we have plenty of near term liquidity. Our 2015 hedge position is included in the press release and shows about 50%, a little over a 50% of our expected oil and gas volumes hedged at prices of almost $92 per barrel and $4.15 per Mcfe. I believe that wraps it up for the financial overview and with that I’ll turn it back over to you Dave.

Okay, thank you very much, Ken. No doubt our industry is facing some major headwinds, but we’re adjusting to the current reality while believing in the longer term viability of the exploration and production business and are still excited about our prospects for the future. Our short term response has been a reduced capital as much as 50%, a reduced lease operating expense by up to 40% and lower our SG&A by 10%, while at the same time positioning ourselves for the future by being almost exclusively [ph] invested in two of the lowest non-OPEC oil and gas supply basins, the deep water of Gulf of Mexico and Appalachia. We’re temporarily surveying [ph] our Appalachian investment are waiting to reduce differentials in allocating most of our capital right now to the deep water of Gulf, where we expect to shortly commence drilling operations with the Ensco 8503 deep water drilling in completion rig. We were fortunate to complete the divestiture of essentially all of our noncore properties by the summer of 2014, before prices dropped and this helped to restructure our company into a much lower cost operation. We also issued equity in May of last year, which improved our liquidity such that we’re in a relatively strong position having significant cash on the balance sheet and an undrawn $0.5 billion revolver. Thirdly, we’ve made a huge discovery in the Utica, Appalachia at the end of 2014, which should position us for over a decade of low risk development investment in growth, once the differential between Appalachia and Henry Hub begin to obey. Finally, we’ve also now proven that we can successfully explore development and produce in the deep water of Gulf of Mexico, having discovered Amethyst and Cardona in 2014, then constructed and brought on line early and under budget the Cardona subsea pipeline tie-back with the Amethyst tie-back currently on schedule and budget. Here’s some additional color on our projects and our prospects. During the first quarter of ‘15, we obtained production results from the Cardona 4 and 5 wells tie-back to our Pompano field and the Utica shale number 6 well, at our Mary Field and Appalachia, which confirmed the success of these investments. We also drilled six successful wells in the Marcellus shale and one unsuccessful exploration prospect in the deep water. As projected and as Ken mentioned, the Cardona 4 and 5 wells have been producing approximately 10,000 barrels of oil equivalent per day. We’ve already produced over a million barrels from these two wells since they came on line. Additionally, the non-operated portion of production is expected to generate production handling fees of approximately $3 million this year, which exceeds the incremental lease operating cost for the two wells. Along with the cost cutting efforts and increasing production, the production handling fees helped to reduce the unit operating cost in our Pompano field. Unit operating expenses at Pompano are expected to drop from over $16 a barrel in 2014 to under $8 a barrel this year. As a result of our planned develop drilling and the production startup of the Amethyst discovery, next year unit operating cost in the Pompano field is expected to decline another 40% to under $4.50 a barrel in 2016. Since this is a significant portion of overall production, we expect to be able to reduce companywide lease operating from over $200 million before our portfolio structuring to about $120 million or less this year with similar productions. The installation of tie-back facilities for the Amethyst well is currently progressing on time and at budgeted cost. We’ll use the reasonably contracted Ensco 8503 deep water rig, to complete the discovery well in late 2015 and expect first production in the first quarter of 2016. This is an equation two years from the date of discovery and the initial production rate from the Amethyst well is expected to be 25 million to 75 million cubic feet of gas equivalent per day. The Harrier exploration prospect in which we participated with Conoco as the operator was unsuccessful. The prospect was a three-way geologic closure and while the reservoir sand was present that does not have the carbon barring. Stone had a 20% cost interest in this as well and we spent approximately $28 million on the test. Our next and likely only other significant exploration well this year is the Vernaccia prospect in Mississippi Canyon Block 35, operated by Eni. This well is being drilled to test a four-way geologic closure and if successful may go back to our Pompano platform. The well is scheduled to spud in the second half of 2015 and is expected to take about three months to drill. We own a 32% working interest in the production and reserves, but have only a 25% cost obligation in the exploration well. The estimated net cost for Stone to test Vernaccia is projected to be $29 million. Net production from the Gulf of Mexico averaged approximately 25,000 barrels of oil equivalent per day in the first quarter of this year. This represents 15% increase in production compared to the fourth quarter of 2014. Additionally, when production rates were adjusted for the noncore asset sale, production in the first quarter this year for the Gulf increased 3,600 barrels of oil equivalent per day or 18% from the first quarter of 2014. We anticipate another increase in Gulf of Mexico production in 2016, with Amethyst, the drilling and completion of Cardona number 6 well and the execution of the Pompano rig program. Cardona number 6 is expected to produce about 5,000 barrels of oil equivalent per day and peak production from the Pompano platform program is expected to be around 6,000 barrels a day in 2016. Stone also has geographically strong position in both the Marcellus and Utica shale’s in Appalachia. Our position in the Marcellus is located in the heart of the ultra-wet portion of the play, with high condensate yields and ever improving ultimate recoveries. Significant drilling by other operators combined with the results of our own Pribble number 6 well, indicate that we’re in one of the most desirable positions in the dry gas portion of the Utica shale. Our position in Appalachia represents our gas supply area and these stacked-pays provide us with expected low cost reserves several times larger than our current Appalachia proved reserve base. This should provide us with over a decade of drilling opportunities in Appalachia. In the first quarter of this year, we drilled six wells prior to releasing the Marcellus rig. We also currently have 25 Marcellus horizontal wells drilled and awaiting completion. The Marcellus rig program itself has been a tremendous execution success, with over a 40% increase in drilling efficiency over the last three years. The rig went from drilling 27 wells in 2011, to drilling 38 wells in 2014. This was accomplished even while increasing the lateral lengths from under 4,000 feet to around 5,600 feet. We laid down the Marcellus rig as a result of high differentials leading to low commodity prices at the wellhead and the lack of flexibility for this rig to draw both Utica and Marcellus wells. We have contracted a fit for purpose walking rig, capable of drilling both Marcellus and Utica and expect to accept this new rig late in 2015 or sometime in 2016. The Pribble number 6 Utica well, has already produced approximately 1.3 Bcf, billion cubic feet has been brought on line in December of 2014. The well which was a short 3,600 foot lateral is currently producing about 5 million cubic feet of gas per day. The success of the Utica shale is expected to greatly increase the resources in our acreage position. Net production from Appalachia, currently exceeds 130 million cubic feet of gas equivalents per day and first quarter was a 50% increase from the first quarter of 2014. Overall, company net production exceeded 46,000 barrels of equivalent per day in the first quarter. This is a slight increase compared to the first quarter of ‘14. However, adjusting for the noncore asset sales, production increased 31% from the first quarter of ‘14 to the first quarter of this year. Through the first quarter we’re also ahead of pace to deliver on our 35% reduction year-on-year lease operating expense. First quarter LOE was $28 million or 41% reduction compared to the first quarter of ‘14 and a 25% reduction compared to the fourth quarter of last year. We believe that further reductions may be possible as vendor pricing continues to adjust to the low price environment. We’re also on target to deliver as stated 10% reduction in SG&A. In addition, we continue toward our $450 million capital budget, a 50% reduction when compared to 2014. The budget includes the temporary pull back in Appalachia drilling, the Amethyst tie-back, development drilling at Pompano and the drilling of two deep water exploration wells. We’re in a healthy liquidity position with an undrawn line of credit, recently reaffirmed at $500 million and a $162 million of cash at the end of the first quarter. For 2015, we have approximately 51% of our oil hedged above $90 a barrel and 55% of our gas hedged our $4. So we’re positioned to take advantage of the prospect portfolio we built in the deep water over the last several years. We have high quality prospects with high enough working interest to allow Stone to leverage its exploration efforts and disproportionally dilute successes. Both of these steps should make it possible for us to maintain significant positions in the deep water prospects we own. Three of the company operated prospects, we currently plan to drill over the next 18 to 24 months are Lamprey, Derbio and Apple. We currently own a 100% working interest in each of these prospects, which in aggregate represent an expected T90 to T10 distribution which ranges from a 150 million to over a billion barrels of oil equivalent. We’ll obviously seek partners to reduce our interest in these prospects. However, even once diluted success could be very significant for the company. With the current oil reserve base of 42 million barrels, it’s easy to see just how impactful success in one or more of these prospects could be for our company. Strategically we’re committed to staying financially sound, protecting the balance sheet and keeping a diversified portfolio across commodities and low cost basins. We positioned ourselves in two of the lowest cost of supply oil and gas basins outside of Opec. Both of our areas have significant upside of which Stone is well positioned to take advantage. It’s this combination of focus on low cost basins and exposure to significant upside that we believe will benefit shareholders in the future. With this we’ll now be happy to take your questions. John back to you.

[Operator Instructions] Our first question comes from the line of Doug Dyer of Heartland Advisors.

And good morning, gentlemen. Looking out into the rest of the year, what would you anticipate the breakdown in CapEx to be with regard to development, exploratory and infrastructure?

Mostly development and we have only one more exploration well, which is about a $29 million investment and I think our remaining CapEx is about 300 or so candidate.

I think just under 350, so Doug it will mostly go to the Cardona number 6, Amethyst though drilling completion, those so far are the two biggest ones. We’ll also be receiving the Pompano platform rig in the fourth quarter. So a great data is pointed out. A majority of the CapEx is targeted really for development projects. I think exploration dollars is more when you get into 2016, where we have more of exploration line up, but some of that CapEx can be adjusted depending upon what working interest we target in the various projects for 2016.

Alright, thank you very much.

Thank you, Doug.

Our next question comes from the line of Michael Glick from Johnson Rice.

Hey, guys. Just looking towards ‘16 in terms of your exploratory program, do you guys have - I know that’s probably a very small prospect, [ph] do you guys kind of have a targeted working interest that you would like to have?

I think that’s going to vary from project to project Michael. We’re generally in the range of 30% to 50%, particularly with prospects if we can end up get a promote on there, which just to give a little color on that. We have had quite a bit of industry interest in those three prospects I mentioned, Derbio, Apple and Lamprey.

Okay, and then just quickly on Appalachia, I mean it looks like you guys have 25 drilled, but uncompleted wells. Can you walk us through the thought process relative to ultimately completing those wells?

Sure, the only reason we didn’t complete on this is just to conserve capital in this low cost environment and because the differentials between Henry Hub and the M2 market are so high right now. We see a lot of pipes that are proposed and are being constructed up there, so we think the differentials are likely to come down significantly over the next couple of years. And as the differentials start dropping, that will make the projects more attractive than will - depending upon what the price of completion is, we’ll probably start considering completing those wells when the market conditions indicate that we can actually create value by doing so.

And Mike, it’s Ken. Those are - we’ve got 25 wells on three separate pads, so it doesn’t necessarily have to be all or nothing. We may just let complete eight of the one pad and see how prices hold out and then look to move forward or not with the other two pads. So it’s in the inventory as David’s pointing out. The wells have been drilled, but the go forward decision is probably more tied - but it’s really tied on the combination of where do we think the realized price will be for gas and the liquids? And also with the cost of the fracking extras will be and obviously the cost has certainly come down and we’re seeing there is some increase in pricing or be it small up in Appalachia, but we kind of see that as a good inventory on kind of future production.

Okay, then maybe just kind of expand on the cost side. What do you all seen in the Gulf, kind of outside of rig day rates in terms of cost reductions from peak?

Yeah, I think we’re looking at rain and it varies widely by category, but overall it’s probably in the neighborhood of 10% to 20%, Michael.

Okay, got it. Alright, thank you very much.

Thanks, Mike.

[Operator Instructions] And we have no additional audio questions at this time.

Okay. Well, thanks everyone for joining the call. We’d look forward to seeing you in person sometimes then. Thank you, bye.

Bye, bye.

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