PetroQuest Energy's (PQ) CEO Charles Goodson on Q3 2017 Results - Earnings Call Transcript
PetroQuest Energy Inc.'s (NYSE:PQ) Q3 2017 Results Conference Call November 2, 2017 9:30 AM ET
Matt Quantz - Manager of IR
Charles Goodson - Chairman, President and CEO
Bond Clement - CFO
Art Mixon - EVP of Operations and Production
John Aschenbeck - Seaport Global
Ron Mills - Johnson Rice
John White - Roth Capital
Good morning, and welcome to the PetroQuest Energy Inc. Third Quarter 2017 Conference Call. All participants will be in a listen only mode. [Operator Instructions] Please note, this event is being recorded. I'd now like to turn the conference over to Matt Quantz, Manager of Investor Relations. Please go ahead.
Thank you. Good morning, everyone. We like to welcome you to our third quarter conference call and webcast. Participating with me today on the call are Charles Goodson, Chairman, CEO and President; Bond Clement, CFO; and Art Mixon, EVP of Operations and Production.
Before we get started, we'd like to make our safe harbor statement under Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest's business, which are not historical facts or forward-looking statements that involve risks and uncertainties. For a discussion of such risks and uncertainties, which could cause actual results to differ from those contained in the forward-looking statements, see Risk Factors on our annual and quarterly SEC filings and in forward-looking statements in our press release. We assume no obligation to update our forward-looking statements.
Please also note that on today's call, we'll be referring to non-GAAP financial measures, including discretionary cash flow. Historical non-GAAP financial measures are reconciled to the most directly comparable GAAP measures in our press release included in the Form 8-K filed with the SEC.
With that, Charlie will get it started with an overview of the quarter.
Good morning. During the third quarter, we produced 7.5 Bcfe or approximately 81 million cubic feet equivalent per day. The 81 million cubic feet equivalent per day was comprised of approximately 58 million cubic feet of gas, 1,600 barrels of oil, and 2,300 barrels of NGLs. Our third quarter production was 18% higher than our second quarter's volumes and represents a 63% increase of over our 2016 fourth quarter average data production rate of 50 million cubic feet equivalent per day. In addition, since the fourth quarter of 2016, we've reinitiated our each section drilling program. Our production from this asset has gone over 60%, which speaks to the quality of property, especially when considering the only drill to complete eight wells this year is been $34 million.
During early October, we achieved one of our main 2017 goals, which was to have our production reach 1,080 cubic feet equivalent per day, thereby exceeding the doubling of our fourth quarter of 2016 production rate. This [indiscernible] occurred earlier than we forecasted a stronger well performance and faster drilling completion time. As a result of more efficient operations of 2017 drilling program, which completed ahead of schedule with great year production growth already, we felt it was more important to defer the remaining two completions on PQ 29 and PQ 30, until 2018 in order to better align our capital budget with estimated cash flows.
Looking out to the fourth quarter of 2017, we're guiding 91 million to 95 million cubic feet equivalent per day. It's worth noting that our fourth quarter projected growth rate would have been even higher if it were not for proxy one-month of downtime that rushed out to 89 due to third-party pipeline maintenance as well as shut-ins of all the company's Gulf of Mexico fields for a portion of October results of Hurricane May. However, the midpoint of our current fourth quarter guidance represents approximately 86% increase from the fourth quarter of 2016. In addition, this represents a highest quarterly production since the second quarter of 2015. It sells the majority of our mutual assets.
Now turning to our operations, where we recently announced three new Cotton Valley wells. In title, these wells achieved initial 24-hour gross production rate of approximately 41 million cubic feet equivalent per day. Our PQ number 26 and PQ number 27 wells were completed in Eberry bench on the northern portion of JD acreage. It hosted a 24-hour rates of 12.7 and 13.3 million cubic equivalent per day, respectively.
Our PQ number 28 well, which was completed in E4 Bench achieved a maximum 24-hour rate of 15.3 million cubic feet equivalent per day. This is the second highest rate in the company's Cotton valley program. The PQ number 27 and PQ number 28 were completed using a significant higher density completion design and were comprised to above greater than 1,000 pounds of profit per lateral foot versus our traditional 7,800 pounds of profit per lateral foot. Even with its higher density completion design, our cost per lateral foot was $893, which was approximately 10% lower than the 2017 part of 1,000 per lateral foot, which is still early in production life. We're encouraged by what we're seeing in terms of higher output and shower declines associated with the second-generation completion design.
Since the beginning of the year, we have been opportunistically increasing our JV acreage footprint in East Texas. In total, we've added over 2,000 acres. In majority today, we acquired through strengths of our patent rights in isobutanes. In addition to our successful culmination of program that tested down spacing to less than 1,000 feet combined, the results from micro thousand data has refined in estimate of how many drilling locations, our day will be hoping to efficiently recover the resources in place.
We now believe 1,200 spacing is more appropriate versus our original 1,500 spacing estimate. And this provides less than the longer -- the additional 2,000 acres increases our drilling locations from 601 to 838 location. We plan to outline and revise location count, mentioned in our next presentation in San Francisco in mid-November. When considering the 2018 eight well program, was the most active horizontal well here in, we clearly have more than toward the immediate [Indiscernible] to develop on our own. That being said, we're evaluating potential drill codes and other JV structures as could bringing a significant portion of the value forward while conserving our future capital outlays.
Our 55,000 mix of position in East Texas is a unique asset. It's nearly 100% HBP and sits on the point of prolific Carthage field, where 4 Bcf of gas has been produced. And unlike the main Carthage field, we have drilled and completed only 28 horizontal wells through almost all of the resource potential remains undeveloped. In addition, we have hundreds of vertical points to control and several cores that de-risk future development.
Finally, the closed proximity to the growing Gulf Coast PetroChemical demands that allow for premium natural gas pricing for the foreseeable future. These characteristics are difficult to replicate in any asset is why we're confident in our belief that there will be significant value created from this property.
Lastly, touching on Thunder Bayou where the well continues to flow at approximately 60 million cubic feet equivalent per day. Since the well was recompleted into the upper section of Cris R2 sand in early February, it has [Indiscernible] over 13 Bcfe. For the third quarter of 2017, the well generated approximately $7 million of field-level cash flow net to PetroQuest or greater than $1 per share on annualized basis compared to our current stock price of less than $2 per share.
With that, I'll turn it over to Bond to go over our financials.
Thanks, Charlie. As Charlie mentioned earlier, we executed our East Texas joint program faster than expected. And we even decided to defer the remaining two Cotton Valley completions until early 2018. I think the first completion is actually scheduled for January 3. And that's done to better align our anticipated cash flow and CapEx for 2017.
We're getting CapEx for the quarter, we spend about $22 million, the break out of the capital to the third quarter is approximately $20.8 million of direct CapEx and the bottom $1.5 million of capitalized overhead interest.
CapEx of the first 9-month of 2017, net of cash received from asset sales, totaled about $48 million relative to our $34 million discretionary cash flow. However, with $2.7 million of additional JV set on proceeds expected in November, our strong quarter of cash flow expected during the fourth quarter and the Cotton Valley program that has concluded in October, we expect to fairly balance budget in 2017 on an annual basis.
Turning to our expenses for the third quarter, our LOE totaled $8.9 million or $1.19 per M, which was in line with our guidance range. Reducing our fourth cap -- quarter per unit LOE guidance to $1.05 to $1.10 to account for our continued higher forecasted production volumes.
G&A cost for the third quarter came down to $3.4 million relative to the second quarter, which was below our guidance range. For the fourth quarter, we'll be guiding to $3.4 million to $3.9 million range.
Interest expense during the quarter totaled $7.4 million, which was right within our guidance range. Again, for the fourth quarter, we're guiding similarly on interest expense to $7.3 million to $7.5 million of which we're forecasting about $6 million of that would be noncash PIK interest.
Finally, on the hedging front. As most of you've seen, we recently put in our first oil hedge for 2018, it was a 250 barrel per day slot at $55.
On the GAAP side, we remain patient. I think there's more upside than downside risk as we move into winter. Looking at the current 2018 strip, particularly, that March to April gap. That being said, during the early part of this year or late this -- early part of next year or late this year, when gas could be trading in more favorable levels, we'll look to monitor supply and demand fundamentals and look for opportunities to add to that 2018 gas hedge program.
With that, I'll turn it back over to Charlie.
Thanks. As we approach the end of the year, we have, essentially, accomplished all of our 2017 goals that we laid out in our business plan. While we are many [indiscernible] to how [indiscernible] I'll touch on our production average goals, which have posted remarkable improvements since the fourth quarter of 2016. Our production goal of reaching 100 million cubic feet equivalent per day was a top priority as we wanted to demonstrate our ability to organically grow into the leverage. We realized this production goal last month ahead of schedule, which speaks to the quality of our assets and team.
Simply put, there are not many companies that have doubled their production while spending approximately $50 million in drilling or recompleting only kiln wells. This production growth coupled with stronger pricing compared to 2016 and translated to a much improved leverage profile. We exited 2016 with approximately 13 times leverage ratio and based on an annualized third quarter run rate, we have reduced to debt with approximately 5 times with higher production projections for next quarter, we can see another full turn lower using estimated fourth quarter annualized EBITDA. It is possible that our fourth quarter EBITDA could exceed that generated the entire year of 2016.
With that, we'll open it up to questions.
[Operator Instructions] The first question will come from John Aschenbeck of Seaport Global. Please go ahead.
Wanted to follow up on your comments on the potential JV in the Cotton Valley, which I found interesting. I was curious to get a feel for what that JV would look like? Would it be something similar to the agreement you currently have in place in the Cotton Valley? Or would it, perhaps, have a larger terry feature from your partner?
Probably, approximately -- I mean there's cash components that we have in there because of the JV partners are hiring. And interest in acreage in -- under a JV and which benefits. And then there would be some talk of a -- just, of course, sharing the cost. And I'd mention is that the JV that we've put in place also has cash partnership. And depending on what the tax looks like, the advantage of the [indiscernible] fees is very attractive to that type of a partner.
And then kind of a follow up there as you look at capital allocation as you head into 2018, assuming gas prices do, indeed, cooperate and if you do indeed sign this additional JV, what type of activity levels should we expect next year both on your 100% acreage and then the 50% acreage? Is it still reasonable to expect a rig on each? Or would you, perhaps, have two rigs on the 100% acreage? Or just -- how should we think about capital allocation if you do have the additional JV?
On that question, we're still working a lot of avenues, as Charlie alluded to in his comments, we are evaluating not only an additional JV on that acreage that we control outright, but also potentially a drill code construction in some form or fashion. So it's -- ideally we'd like to have two rigs running during the year, next year. Can't tell you exactly where those rigs are going to be. But we're working a lot of different fronts to get the most activity we can recognizing that we're going to have to have a fully balanced budget next year and get the most activity out of every dollar we have available.
The next question comes from Ron Mills of Johnson Rice. Please go ahead.
Couple of questions. Just -- Bond, maybe a follow-up on that last comment. You talked about a potential drill code. Is it fair to assume that it wouldn't necessarily just be on -- upon 100% acreage? But could you also structure one that could go across the whole position, including the share around acreage? Or what can that look like?
No, that's definitely possible, Ron. Again, we're trying -- first off, we've got to get some transactions captured before we can start thinking about where these rigs are going to show up. But certainly, under the assumption that a drill code would be in place, we would prefer to have that rig drilling on the Chevron acreage and begin to see some results on that side of the fence, if you will.
And then when you -- in the press release, I think you talked about growing your JV acreage -- your adjusting JV acreage where you have that 100% ventures from 6,000 to 8,200. And you had a similar increase in your drilling inventory. Sounds like your spacings moved from 1,500 to 1,200 feet but can you talk a little bit more about that increase in net acreage? And what that does for you in terms of -- how much of that drill over the increase inventory, how much of it was spacing?
Yes, a big chunk of what we were able to pick up relative to the JV acreage was done with trades of our deep Haynesville rights in certain units for shallow or Cotton Valley rights with others and other units. So we were able to increase that acreage position when you add in the trades somewhere around $600 an acre, all in. We were able to add a couple of thousand acres. As it relates to spacing, really, during the '17 campaign, a lot of the things that we were trying to do was to optimize what the spacing would ultimately be.
So if you guys will remember early on in the program, we tested a well down to around 900 foot spacing through our micro-seismic. We've confirmed when you look at the spacing and the well results that 1,200 feet is probably a more appropriate spacing to avoid any kind of interference versus the 1,500. I can't give you a breakdown of what percentage gives new acreage versus what percentage down spacing. But it is a combination of both with probably the majority leaning on just a new acreage.
Okay, and then lastly for me, on the deferral of the Cotton Valley completions, Charlie, was that fairly to manage cash flow in CapEx? Is some of it awaiting potential JV? Or is some of it just service-related in terms of being able to get trackers on a timely basis?
No, it was simply, just like Bond said, in line CapEx to cash flow. We believe we've doubled our production in [indiscernible] and at some point in time, you say enough's enough. We've gotten our leverage ratio down. And so, really, I think it still allows us to take a breath and look at the results of these wells' flowbacks, how they're doing, the different track spacing, things like that. And then getting distortion. Like from January 1, the JV partners and in other things we've been very thankful and move forward in really, really, kind of, front load 2018.
So it was nothing problematic about it, it was simply just -- we accomplished so much faster in 2017 than we anticipated in. Also, part of that too is we were flowing back our first few wells and continuing which -- we couldn't get any side of that area because those are the first wells up there and derisk a lot of locations that we can move in and there are in and we can drill, probably, six well pads in the future. And so, underlining all that up, things are ready for 2018, and hope we have another great year next year watching gas price.
And is that where you just drilled the most recent wells you reported last week up in the Northeast portion?
The next question comes from John White of Roth Capital. Please go ahead.
I noticed you highlighted the leasing activity in your press release, added about 2,200 net acres. Is that leasing activity ongoing?
It's -- yes, that's -- on the JV acreage, it is. There's a lot of -- I actually call them stranded traps where somebody might have 648 acres and really cannot afford drilling campaign on it. And so it really coming to us, are we going to them and that will derisk 10 or 12 locations. And it's -- we're taking advantage of the situation that are advantageous to us. And then in others that are focused on Haynesville. And we really never had stable position, we could have [Indiscernible] out there so we have a -- 25 acres here or a 100 acres there, that would only be a partial [Indiscernible] in Haynesville. We really -- that's not kind of our plan. And so we would transfer or trade diesel rights for Cotton Valley rights that would gross up and [Indiscernible].
And John, just to be clear -- this is Bond. This is something that's been ongoing throughout the year. We just felt we wanted to update our inventory slide before the end of the year so we felt like this was the right time to do this. But if you look at our maps in our presentation and generally our JV acreage is highlighted in yellow, you can see what we're trying to do pretty easily. There's little small gaps and holes as we try to link up positions and generate operational efficiencies in terms of using salt water disposal and existing infrastructure. So we're just sort of filling in the gaps there, very small positions at a time. When you look at the total 2,000 acres, we've probably done 10 separate deals to get there. So just very small little bolt-on block -- blocking and tackling and filling the position to generate better economics of scale and also in a lot of cases to help us grow longer laterals.
Okay, thanks, that all sounds good. And to clarify some of the earlier discussion, depending on the moving parts with a drill co or a JV, underlying plan is to wind up with a two rig program in 2018? Is that correct?
Yes, that's where we want to be. I think in a minimum that's where we want to be.
Okay. Possibility of a third rig depending on your negotiation?
Yes, we'll just have to see how it all shapes up. Like I said, we need to execute and capture some deals. We've been very successful in doing that in the path, as everyone knows particularly on the joint venture front. So let's just -- let's get our work done and we'll have a more definitive CapEx plan and capital allocation plan, call it early 2018.
And this concludes our question-and-answer session. I would now like to turn the conference back over to Matt Quantz for any closing remarks.
Yes, thank you, everybody, for your time this morning. And please follow-up with any additional questions that you may have.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.
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