PetroQuest Energy Inc. (NYSE:PQ) Q2 2016 Earnings Conference Call August 2, 2016 9:30 AM ET
Matt Quantz - Manager of Investor Relations
Charles Goodson - President and Chief Executive Officer
Bond Clement - Chief Financial Officer
Art Mixon - Executive Vice Presdident of Operations and Production
Richard Tullis - Capital One Securities
Ronald Mills - Johnson Rice
Joseph Bachman - Scotia Howard Weil
Michael Kelly - Seaport Global
John White - ROTH Capital
Good morning and welcome to the PetroQuest Energy Second Quarter Earnings Release Conference Call. All participants will be in a listen-only mode [Operator Instructions]. After today’s presentation, there will be an opportunity to ask questions [Operator Instructions]. Please note that this event is being recorded.
I would now like to turn the conference over to Manager of Investor Relations, Matt Quantz. Please go ahead.
Thank you. Good morning, everyone. We would like to welcome you to our second 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 would like to make our Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Statements made today regarding PetroQuest’s business which are not historical facts are 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 in 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 will 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 yesterday.
With that, Charlie will get us started with an overview of the quarter.
Thanks , appreciate it. During the second quarter, we produced 6 Bcfe or applications 66 million cubic feet of gas equivalent per day to 66 million cubic feet equivalent per day was comprised of approximately 47 million cubic feet of gas, 1,300 barrels of oil and 1,900 barrels of NGLs. The second quarter production volumes exceeded our original midpoint guidance by 5%.
This is the second consecutive quarter that we surpassed our initial quarterly guidance range particularly [indiscernible] this performance have been our lower than expected decline rates in East Texas relative to consistent production profiles. At Thunder Bayou, [indiscernible] and other Gulf Coast and Gulf of Mexico properties.
Revenues for the second quarter were approximately $16 million of product price realizations averaging approximately $43 per barrel of oil and $2.07 per Mcf of gas. NGL product price realizations averaged approximately $12 a barrel. [Indiscernible] the third quarter production guidance but we are guiding down volume sequentially keep in mind this once again includes forecasted production climbs at Thunder Bayou.
Obviously at these projected declines are now materialized we continue some upside to our third quarter guidance as we did in the first two quarters of 2016. Also, it's worth mentioning that we divested our East Hoss properties at the end of April. Those assets had a run rate of approximately 10 million cubic feet equivalent per day in March and contributed approximately 3 million cubic feet equivalent per day to our second quarter production volumes.
Finally, we are factoring in that we have only drilled two wells this year our corporate production has held up beyond expectations. In summary, while our CapEx budget last year thus meeting the top line growth, we have continued our efforts companywide to substantially improve the bottom line, which is reflected in the balance sheet.
While 2016 has been relatively quiet year on the operational side of things, we have been diligently working on reducing cash costs throughout the entire organization. Our second quarter 2016 numbers highlight these accomplishments in total when comparing our second quarter 2016 cash costs to the second quarter of 2015.
We have seen 36% reduction of this comparable period G&A, interest driven, lifting costs were down 25%, 44% and 34% respectively. This decline in gas cost versus the year ago quarter total $10.8 million for a $1.80 per Mcf of margin benefit on our second quarter production volumes.
We will continue to run this way seek out additional cost savings opportunities by understanding that we cannot control price of our product. We can continue to positively influence the cost out of equation.
In addition to our cost cutting efforts, we are actively in discussions with future partners of our joint venture opportunities in East Texas and continue to evaluate options to achieve maturity of our 2017 notes. We discussed in these projects to engage invested bank that’s highlighted in our press release yesterday.
Due to the materiality of these items, we will not be able to elaborate on these projects and topic this morning or as anytime until we have finalized agreement in place. So we please refrain from asking question on these topics during our Q&A session today.
Quickly turning to operations where Thunder Bayou continues to flow at approximately 30 million cubic feet equivalent per day. As of June 30, 2016, we achieved 11.7 Bcfe, which means we have officially reached our original maximum bottom [indiscernible] 3P number of 11.8 Bcfe and produced 36% more reserves than the original 1P number of 8.6 Bcfe.
As result of this continued outperformance, we once again have pushed out the recompletion day into the upper low and now are projecting this event to a current December 2016. While this resilient production performance has made forecasting production guidance somewhat challenging, we have welcomed the reoccurring positive production volumes.
Moving to the Gulf of Mexico where just finished our 2016 ship sold 72 recompletion program which part on came in underwriting through the total net cost of approximately $600,000 and resulted in additional 360 barrels of oil per day of new net production, but in another way, it equates to $1700 per full barrel which is not bad economics.
With that, I will turn it over to Bond to go over financials.
Okay. Thanks, Charlie. We are pleased with the second quarter results as they relate to cost cutting efforts. LOE totaled $6.9 million or $1.14 per Mcfe, which is below our original guidance primarily due to the continued our performance on the production site, which setting our third quarter current unit LOE guidance range at $1.25 to $1.35 which does account for the lower third quarter forecasted production volume.
G&A cost in second quarter totaled 3.9 million and included 500,000 of non-cash stock comp. Total G&A costs were 1.7 million lower than the year ago quarter reflecting the hard work we have done to cut overhead costs in response to prolong commodity price downturn.
Interest expense from the quarter totaled 6.5 million, which was within our guidance range. This was the first full quarter to benefit from February debt exchange, as we were able to decrease interest cost by almost $2 million sequentially.
As Charley mentioned, we lowered our cash cost by 36% versus the second quarter of 2015 internally our goal has always been this year to achieve a 25% reduction in overall cost from last year. Based upon actual results through midyear and forecasted cost for the balance of the year, we believe we are on-track to meet this goal.
Looking at CapEx for the quarter, we invested about $4 million, the breakout of the capital for the second quarter was approximately $2.2 million of direct CapEx and $1.8 million of capitalized overhead and interest. Through June 30, our capital expenditures totaled about 10.6 million which puts on right on-track towards reselling well over 2016 CapEx guidance range of 15 million to 20 million.
During the second quarter, our shareholders debt approved to one to four reverse stock split and we will continue to work with the NYSE on our business plans to maintain our listing performance.
With that, I’ll turn it back over to Charlie to wrap up.
Thanks. And as we enter the back half 2016, we find ourselves in a strengthening gas price environment, which continues to gain momentum with the record hot summer and falling U.S. production profile. Clearly, the lack of capital investments is starting to have an impact on the industry’s production and the [indiscernible] low oil prices is once again proven to be true.
Even more encouraging is the fact that we haven’t seen a corresponding rig count increase to 12 month gas strip price now above $3 million. As we sit here today, we are near an all time low of approximately 86 gas rigs working in the U.S. with new demand sources consistently coming on line.
[indiscernible] on the walls and natural gas will experience significant growth as a fuel source over the next decade, we believe that our asset base is well positioned to participate in this recovery. With our bottom line improvements and the possibility of the joint venture that start once we resolve our debt maturity issue we feel we can be competitive within the U.S. basins.
With that, we will turn it over to questions.
We will now be conducting a question-and-answer session [Operator Instructions]. Our first question is from Richard Tullis from Capital One Securities. Please go ahead.
Hey thank you good morning. Just going back to the 3Q guidance a little bit, Charlie. So you have mentioned East Hoss accounted for about 3 million a day in the second quarter and then you have the [indiscernible] 72 recomplete, I guess that equates to about 2 million of new production in third quarter. How much decline is built in for Thunder Bayou and also do 1you have any storm at that time factored into the 3Q guidance?
Richard this is Bond. I’ll try to help you with that one. Yes, obviously the easier one is the East Hoss sales and that backs out on a pro forma basis about 3 million a day to the second quarter run rate. We do as we have normally do have some storms lifting on our Gulf of Mexico assets.
And when you look at Thunder Bayou specifically, we have that well at currently around 30 million a day gross on equivalent basis, declining throughout the quarter to around 20 million a day by the end of the quarter and then a consistent decline in the fourth quarter to where the well is offline completely.
In December of this year we bring the well back on in January of 2017 and that’s when you will see the big jump through the production volumes in the first quarter 2017 . That’s how we have it modeled. In addition to that, you have declines in East Texas.
Obviously, we haven’t bought on a new well in six months. So when you look at sequential decline in East Texas just relative to those assets is about 10% to 15% and that production now based up about 40% of our run rate. So you are looking on a sequential basis in East Texas with no new add somewhere around 5% sequential decline for the total Company’s overall volumes.
Okay that’s helpful and we should expect that to continue going forward assuming a similar investment pace like you have had year-to-date?
Yes, it's pretty apparent we don’t drill wells in East Texas, you are going to see decline. So it's imperative that we get back to work in East Texas [indiscernible] and have some resolution on the balance sheet side and get back to growing production in East Texas.
And then looking at it another way Bond. Which sort of investment would be required next year to keep the non-Thunder Bayou production base flat assuming not Cotton Valley JV just kind of [indiscernible].
Well we can't really talk to that Richard the level of investment is going to be highly dependent upon the JV that we have in place in terms of what our ultimate working interest is and what the ost sharing arrangements are. So if you don't mind, I'll just defer that to we have some resolution on that front.
Okay and then just lastly Charlie our bond, looking at the Cotton Valley horizontal program, I know you are not drilling that, but what do you think you can drill a typical well for today?
The last well we drilled, we talked about planning to get under $4 million [indiscernible] complete. I think we have talked to the market that we had to rent 3.9. I think the field level costs have come in about 3.653. And so that's a substantial improvement on everything out there and we feel like that somewhere in that $3.6 million to $4 million range for a 4,500 foot lateral is very accomplishable and the fact that we haven't had drilled yet, that could add some additional savings. So I think just safely saying under $4 million is a very achievable number.
All right. Well thank you, I appreciate it.
The next question comes from Ron Mills with Johnson Rice. Please go ahead.
Hey guys. Just a follow-on to that last question and Charlie you mentioned that the strip is over three bucks for the next three years and given your cash position, how do you go about thinking about getting started in Cotton Valley or is really the joint venture the first step in that process before you get going again?
Yes, Ron it's all about persevering liquidity right. We need to get some resolution on the maturity and then that obviously opens up a lot of things operationally for us once we have some clarity in that regard.
Okay and then when you get going just from a development standpoint, Charlie, you just mentioned 4,500 foot laterals. Is this also an area where given the contiguous nature of your position that you could end up also doing what others have done in other place in terms of getting units formed [indiscernible] the long laterals and what are your thoughts on what that could do?
Yes, we have some forecasted 6,000 to possibly 7,000 for lateral for your where you cross unit lines and that's very achievable. We didn't have any problem at all with whole stability in drilling these 4,000 to 5,000 foot laterals. So drilling up 6,000 plus lateral is very achievable on our minds.
Hey Ron, sorry just as a follow-up, as we have modeled out how we think the drill program could go once we get back to work, our expectations would be to test long laterals in the first six months of the program.
Okay and then just under Thunder Bayou, just to make sure I understood when you now talk about fourth quarter recompletion, you are now really at least as you are currently guiding that the recompletion occurs in December and you start to see the impact in January, is that what you said?
Yes. The well and our models can be offline completely in the month of December. And there is probably a little upside to that Art, I don’t know if it’s a four week process or three week…
Yes, there is a little bit upside. I would say, we have four weeks modeling but it could be two to three weeks.
And so then you will have - we will walk the rate up probably fairly slowly in January. And then you should be at full rate by - certain by the end of January, that’s how the timing goes.
Okay, great. I appreciate you guys.
Our next question is from Joe Bachman with Scotia Howard Weil. Please go ahead.
Just had a quick one follow-up on Thunder Bayou, just wondering what is the minimum production level or I guess maximum I should say that the state will allow you to go up or recomplete? Just trying to get an understanding if we could see another quarter where the well is outperforming and keeping above that level?
No, there is no real minimum that the state has. The bigger picture for that is us working with our partners to come up with the economic rate to go up and do the recompletions.
Yes, we look at water volumes and since you are really producing one reservoir. Our goal was to deplete as much as we could in the bottom perforations and so then it becomes a decision once a work is [indiscernible] it's what volumes you won’t let water get up to and then when you are recomplete.
Okay, so there is no plan I guess to try and comingle or you are going to plug that bottom zone and move up whole for that recomplete?
Yes, we are evaluating that right now, there are some intermediate options between some isolation or partial isolation of the bottom zone and perforating the top zone and we are working with our partners on that plan. We don’t have a definitive answer to that right now.
But keep in mind Joe, that well is producing somewhere around 8,000 barrels of water a day. So ideally you would like to get up on the structure and get away from that water.
Okay great. I appreciate it guys.
Our next question is from Mike Kelly with Seaport Global. Please go ahead.
Hey guys good morning. Your current slide deck shows 67% IRR and $3 gas in the Cotton Valley and the assumptions there Charlie already alluded to the fact that you are under that $4 million well cost. And I was hoping to get your thoughts on your assumptions on the EURs there too. It's showing 8.6 Bcf well, but that does seem to be, if look like you look like its honing in on what you did in 2014 with IP rates and you have only gotten a lot better since then [indiscernible] better on the IP front. So just curious if you can talk about the potential to see the EUR uplift occur as well? Thanks.
Well I think that as we learn more and more about what your production per lateral put say the 1.7 which we have achieved and we are seeing higher numbers in that, which indicates we are actually producing more out of sales [indiscernible] than we thought originally and longer laterals.
We think the longer laterals will help us in many ways on our EURs and our returns. So we are ready to get back to work out there and I think that pretty much summarizes the things that we have right now that will continue to improve, but we surely don’t see them going down.
This is Art, Mike. And the other things we will also be looking at [indiscernible] density and types of fracs and all the different things that we have been able to do and also hone that in raising our EUR and improving the profitability. And the focus of course will be on the profitability and rates of return not necessarily just the EUR. Instead a whole bunch of money maybe get a little bit higher EURs, but it still wouldn’t be as economic. So we got a balance all those parameters as we get back to work.
And the last thing I would say is we have only basically produced in two benches up here and we have basically five more to go. And those are some pretty impressive look in sand as you get up in the middle part of the Cotton Valley. And we have been pretty [indiscernible] on what we think those were going to get. So hopefully when we get to back drilling and start testing these other benches, where we see some upside from some of these other benches outperforming those numbers also.
Okay great and just so I kind of have it cleared from my head here too, the path that gets you to increased activity levels. I mean how do you really kind of lay this out, you have the JV done first or is the debt maturities or how do you kind of think of the steps to ultimately get you to the point where you are increasing activity level and maybe timing on it if you can? Thanks.
Well, in line, I think the area is pretty clear that we don’t want to start anything until we resolve the maturity issues. We have [indiscernible] to the stands of wanting to maintain liquidity and that basically is a reduction of liquidity. But we are continuing to talk to people about the joint venture. And so we feel they are parallel paths, but we want to make it clear that we are not intending to just flat and start drilling before we resolve these issue which I think is a good business practice.
Okay, thanks guys.
Our next question is from John White with ROTH Capital. Please go ahead.
Good morning men and congratulations on the good production numbers and the cash cost reductions. On Thunder Bayou, what is it you are seeing at the wellhead that’s causing the out performance, is it higher than anticipated slowing pressures or is it lower than expected water, can you give us a little more color?
Well basically it’s that we took the most negative case on the thickness of sands as they move away from wellbore and so what it's doing, it's showing you that as you move down dip away from the wellbore where you are selling the gas column.
The sands are commingling and clinging up and it's just potentially a larger reservoir. Because if you go back and look at some our presentations, the down dip well we are [indiscernible] off of is about 500 feet of solid sand, with very little interference between the different lobes.
Where as you get up on top of the structure, we had some - I guess get you call it degradation at the wellbore where there was more shale and as you move away from that pretty quickly, obviously you are clinging the sand up. So at point out there all of the sand will mingle together and that's just the best way its proving have to be.
Okay, thanks very much. I appreciate that.
All right John. See you.
I’m showing no more questions. So this concludes our question-and-answer session. I would now like to turn the conference back over to Matt Quantz for any closing remark.
Yes, thank you everybody for the time this morning. And please follow-up again if you have any additional questions.
The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.
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