Jones Energy, Inc. (NYSE:JONE)
Q2 2016 Earnings Conference Call
August 4, 2016 11:00 AM ET
Cathleen King – Investor Relations
Jonny Jones – Founder, Chairman & Chief Executive Officer
Robert Brooks – Chief Financial Officer & Executive Vice President
Will Derrick – SunTrust Robinson Humphrey, Inc.
Derrick Whitfield – GMP Securities
Good morning, everyone. Ms. Cathleen King, you may begin.
Thanks Nick. Ladies and gentlemen, thank you for standing by. Welcome to the Jones Energy 2016 Second Quarter Earnings Conference Call. The company's news release announcing its results was circulated yesterday and is also available in Investor Relations section of our website, at www.jonesnergy.com. During the formal remarks, all participants will be in listen-only mode. [Operator Instructions]
Following today's formal remarks, there will be an opportunity to ask questions. [Operator Instructions] As a reminder, this call is being recorded. The webcast replay and a downloadable audio file will be available shortly following the call through the Investor Relations section of the company's website.
I would like to remind everyone that today's conference call contains forward-looking statements. These statements are based on our current views, forecasts and assumptions, which we believe are reasonable. However, a number of factors could cause actual results to differ materially from what we discuss today. Additional information concerning certain risks and uncertainties relating to the company's business prospects and results are available in the company's filings with the SEC.
During the call, management will refer to certain non-GAAP financial measures. Reconciliation of these measures is provided in our second quarter 2016 earnings release filed yesterday and will also be provided in our Form 10-Q.
Participating with me on today's call will be Jonny Jones, Founder, Chairman and CEO; Mike McConnell, President; Robert Brooks, Executive Vice President and Chief Financial Officer; Eric Niccum, Executive Vice President and Chief Operating Officer; and Jeff Tanner, Executive Vice President of Geosciences and Business Development. After our formal remarks, we'll open up the call for questions.
I would now like to turn the call over to Jonny Jones.
Thanks, Cathleen. Good morning, everyone, and thank you for joining us today. We reported second quarter results at near expectations, largely due to our outperformance from our base business and the hard work of our operating team. As a reminder, we resumed drilling in April, and had three rigs running by June.
So far, our drilling performance has been outstanding. Production from these new wells only had a small impact on our second quarter results, but we expect the incremental production from our 2016 Cleveland development program to benefit our third and fourth quarter results. And even more so, impact our 2017 production.
For the second quarter, we reported production of 18,600 Boe per day, which is above our guidance of 17,300 Boe to 18,300 Boe per day. Oil production also exceeded our expectation at 4,400 barrels per day versus guidance of 4,000 barrels per day to 4,200 barrels per day. And finally, gas production of 50.6 million cubic feet per day was above our guidance range of 47 million cubic feet per day to 49.5 million cubic feet per day.
Lease operating expense or LOE was $7.5 million in the second quarter, which is down 12% from the first quarter and down 36% over the same quarter last year. Our operating team has had a laser focus on getting cost down and it shows in our results. There are over 30 line items that make up our LOE, and we continually review every single item to drive additional cost savings.
With our press release yesterday, we announced an acquisition of approximately 26,000 net acres in the Anadarko Basin for $27.1 million that directly overlays our existing Cleveland position. The acreage has 98% held-by-production with no near-term lease expirations and fits into our existing position like a glove.
As you can see from the map that we posted to the presentation page of our website yesterday, it also adds 92 gross and 38 (sic)  (04:16) net Cleveland locations to our inventory and approximately 850 Boe per day of production. This acquisition increases our inventory in a meaningful way as it adds about 1.5 years of drilling inventory at our current three-rig pace. In addition, most of the added locations are in largely undeveloped sections that have multiple horizontal wells remaining to drill.
We plan to fund the deal with cash on hand and expect the transaction to close by the end of August. We were able to acquire these high quality assets at a very reasonable price, due to our best-in-class drilling cost, which allow us to generate compelling returns even in the current commodity price environment. Our strong operating results and this bolt-on acquisition give us positive momentum heading into the rest of the year and into 2017.
We're also raising 2016 production guidance by 5%, while lowering capital guidance by 10%. One of our themes this year has been doing more with less. And this is evident in our ability to raise production guidance even while spending less. Since resuming drilling in April, we have literally broken every single drilling record we have as a company. As a result, we're drilling faster than expected and are averaging approximately 17 days spud-to-spud, which is down from the 18 days we budgeted for our prior 2016 guidance.
We still expect to spud approximately 40 gross wells in 2016, although we may be able to complete a few more wells during the year than previously forecasted. In the second quarter, we spud 11 wells and brought six wells online. Based on our drilling performance today, we believe, we are achieving or beating our $2.03 million AFE on a consistent basis while achieving our increased type curve. We're also continuing to see a very competitive environment amongst service providers in the field, which is benefiting cost.
The combination of continued vendor competition and the operating efficiencies we have been able to achieve is having a very positive impact on our results. Our 2016 production guidance raise is primarily due to base outperformance, but is also helped by the fact that we are drilling a bit faster than we budgeted, and to a very small extent production associated with the acquisition.
The acquisition adds production of approximately 850 Boe per day, but it's important to remember that we only get credit for that production once we have closed the acquisition, which is expected to occur by the end of August. So, the additional production from the acquisition is contributing to our guidance raise, but the real driver of the raise is base outperformance. In fact, only 1.5% of the 5% increase in 2016 production guidance is due to the acquisition.
Base production is outperforming due to the fact that we have completed over 200 work-over projects year-to-date. Most of these projects have a payback period of just a few months and all of them have very high rates of return. We have been extremely efficient in completing these workovers at a faster pace and lower cost than budgeted, which has benefited both, production and capital.
I've been very impressed with our team's focus on getting these projects done and we are seeing the benefit directly in our result. In our press release, we also provided a preliminary forecast on what production and capital could look like, should we continue running three rigs in 2017.
Assuming our $2.03 million AFE and three Cleveland rigs running with an average of 80% working interest, we have the potential to grow production by nearly 10% in 2017. With four rigs, production growth would be well into the double digits.
We are running three rigs today with all of the expected oil and gas production hedge for 2016 and 2017, and continue to believe that it is right level of rig activity in the current environment, but we will continue to evaluate what the right level of activity is and could easily add a rig if we believe that this is a right move for the company.
The M&A market in the Mid-Cont is quite hot, and our team is currently evaluating several additional opportunities. We are focused on seizing upside in the downturn and we'll remain disciplined in our approach to evaluating M&A. I'm very proud of our results so far this year. And believe this is just beginning of many exciting things to come for Jones Energy.
With that, I'll turn the call over to Bob.
Good morning, everyone. Our second quarter of 2016 EBITDAX was $46.2 million, which compares to $51.1 million in the first quarter of 2016 and $64.4 million for the same period a year ago. Our second quarter EBITDAX declined at a lower production and lower commodity prices, which was only partially offset by lower operating expenses.
For the second quarter, we reported a net loss of $58.6 million and an adjusted net loss of $5.7 million, which represents an adjusted net loss of $0.09 per share. Second quarter capital expenditures totaled $17.8 million, which brings our total capital spend year-to-date to $23.8 million.
In the second quarter, we spent $12.4 million on drilling and completion capital, with the remainder primarily allocated to maintenance. As Jonny mentioned, we are lowering our 2016 capital guidance to $90 million from $100 million and expect the remaining $65 million or so of capital spend to be relatively evenly distributed across the third and fourth quarters. This updated capital guidance does not include the cost of our acquisition.
Lease operating expense or LOE was $7.5 million in the second quarter, which is even better than expected. Second quarter LOE decreased 12% from last year and is down 36%, compared to the same period a year ago. We're maintaining our 2016 LOE guidance even after incorporating the additional expense related to the wells acquired through the acquisition.
We expect 2016 LOE to be down significantly compared to 2015, which is particularly impressive when we consider that we will brought online about 115 additional wells by the end of 2016, compared with our well count at the beginning of 2015, and added more than 150 wells associated with the acquisition on top of that. This shows we have been able to lower LOE by a meaningful amount even while our total well count increased by approximately 25%.
G&A in the second quarter of $8.1 million included approximately $1.5 million for a litigation reserve, which corresponds to an accrual for the anticipated settlement of pending litigation.
Hacking out the litigation reserve and certain other non-cash items, our cash G&A for the second quarter was approximately $4.5 million, which was largely in line with our expectations. Our year-to-date cash G&A expense is running at the high end of budget, which is largely due to reduction in corpus cost recover early in the year and unbudgeted items like transaction expenses that are less predictable. It is important to note that we've continued to realize substantial savings on controllable G&A items this year compared to last year and still expect G&A to be down materially in 2016 relative to 2015.
We are maintaining our full year 2016 guidance for cash G&A of $18 million to $20 million, although we would expect to be at the higher end of the guidance range for the year. We recently completed our spring borrowing base re-determination. The borrowing base was re-determined at $410 million under largely the same terms as before and will automatically increase to $425 million upon closing of the Anadarko Basin acquisition.
As of June 30, we had senior notes outstanding of $559.1 million, outstanding borrowings under our revolving credit facility of $185 million and approximately $59.3 million in cash. As a reminder, we also repurchased $20 million of senior notes in the second quarter for $11 million and have repurchased a total of 191 million of the notes for $85 million year-to-date.
In the second quarter, we put in place an at-the-market or ATM equity program, which allows us to issue equity directly into the market. As of August 1, we had issued 498,400 shares at an average price of $4.31 per share for gross proceeds of $2.1 million. All shares sold to the program or issued above $4 per share.
We continue to be substantially hedged in 2016 and 2017 and are beginning to add hedges in 2018 and 2019 as well. As a reminder, we entered into offsetting hedged transactions to lock-in $47 million hedge gains in 2018 and 2019 earlier this year. Locking in these hedge gains provides us with financial flexibility, giving us the option to monetize those gains, move them forward in time and count them as EBITDAX this year or next year if we should chose to do so.
With our resumption of drilling, we believe that it make sense to begin adding oil and gas hedges in 2018 and 2019 and have begun executing hedges to lock-in a portion of our PDP in 2018 and 2019.
Finally, I'd like to provide you an update on our tax position. Year-to-date, we've made $20 million in cash tax distributions to JEH unitholders of which $9.9 million was distributed to Jones Energy, Inc. and $10.1 million was distributed to the other JEH unitholders.
We made our first distribution in April, and the second in June. We expected to distribute an additional $22.4 million for the rest of 2016, but do not expect to pay cash tax distributions beyond 2016.
Of the $22.4 million remaining, $12.7 million is expected to be distributed to Jones Energy, Inc. and $9.7 million to the other JEH unitholders. We expect to pay the remaining distributions in two equal installments over the next two quarters of 2016.
In conclusion, our resumed drilling program is off to a great start and we're pleased with the progress we've made this year and continuing to reduce cost and improve our balance sheet. I believe we're well positioned to capture value or any opportunities and look forward to providing you with future updates.
That concludes our formal remarks. Operator, would you please open the call for questions?
[Operator Instructions] Your first question comes from Will Derrick from SunTrust. Your line is now open.
Good morning, guys. I guess, Jonny, first question is on the budget for next year. You talked about running three rigs initially, curious what your thoughts are there and sensitivity to the commodity?
Yeah. Will, thanks for calling in. That's not a budget. Actually, it's just an indication of what that might look likely. We began our budgeting process in October, and we just wanted to give folks a feel for what that might look like, should we just stay at the current activity level of where we are. Remembering, we're hedged for 2016 and 2017 on the drilling that we're doing right now, so we really don't have a decision there.
The decision in October that we start making as we start formulating the budget will just be based simply on where commodity prices are at the time or where our service costs are. So, we really don't have an indication of where we might begin the year at this point.
Okay. Thanks. And then, on the cost side, LOE continues to come down, and you were talking about that. Curious how sustainable that is and what the key drivers are that you've seen over the last couple quarters?
Yeah. That's a good question. Compared to drilling costs, what we've seen, I'll sort of compare the two. We've seen more than 50% of our drilling cost reductions be something that we would call sticky or something that's permanent on the LOE side. Most of the LOE reduction is just simply lower tender cost. There's really not going to be permanent savings as we see when out cost go up there, so we wouldn't expect to capture a meaningful amount of the LOE on a permanent basis.
Okay. Thank you, all.
Your next question comes from Derrick Whitfield from GMP Securities. Your line is now open.
Good morning, Jonny and team. Great quarter.
Thank you, Derrick.
So, regarding the acquisition, is it safe to assume that that acreage goes to the front of your development queue?
Yeah. The right way to think about this is, we actually are in full development mode in the Cleveland, and we started out at the beginning of the year on the east side drilling our Ellis County acreage, and I just discovered or found out that all three of our rigs right now are in Lipscomb County, which is very near where the bulk of this acreage is.
We won't specifically target this acreage to the exclusion of other acreage. We're just going to fold it in with our program. We're very close to that acreage right now with our rigs, so you can expect to see us drilling wells on it soon, but we won't dedicate rigs to this acreage specifically over any other acreage. We really see it folding right in nicely, hand-in-glove.
And if you look at the map that we put on there, you can really see how it sits right in there closely with our XCO XON position and our Chalker position, but we'll just move across the acreage to the West to pick those sections up as we get to them.
We have the luxury of doing that, obviously because the acreage is 98% HBP. And one of the nice things about the acquisition that we're excited about is most of these sections are not very developed. There's one or two or fewer wells in the section, so we're able to go in and drill two, three, four wells at the same time, which is the way we're getting a lot of our efficiency that we're seeing right now at our rigs. Minimizing rig moves is a big component of the efficiencies that we're seeing.
Very good. That makes sense. And then, Jonny, you mentioned something earlier on the acquisition market in general, that piqued my interest. Bigger picture, if you could just comment on where you see the acquisition opportunities at present? And if you kindly note if any of those opportunities extend beyond your current areas of focus.
Yeah. That's a good one. Yeah, as I mentioned the A&D market is very hot right now specifically in the Mid-Con. There's a lot of attention around the STACK and SCOOP trend, which is just on the Eastern edge, where our acreage position is. We're comfortable extending out that far. We have current assets in the Arkoma Basin, which is just across the mountain front and are active across the entirety of Oklahoma and the Texas Panhandle. We really see a lot of activity in that entire area.
One of the things that's nice, is we can sort of have a two-pronged approach to our acquisitions. Obviously, things similar to what we just did, where we were able to pick up nice upside by paying a very minimal to zero for that, because of our AFE advantage, but we also think it's important for us to continue to look to expand within the Anadarko Basin and use our efficient operating capabilities to do so.
Very helpful. And then, thinking about your organic opportunities. I know you guys hold the potential of the Tonkawa in high regard, any thoughts around testing that opportunity with the modern completion late this year or next?
Yeah. That's a good question, Derrick. We were going to do that in 2015, and that was one of our plans after we sort of did a test. But as you pointed out, there's really not been a modern completion done on the Tonkawa. It will be a function when we get to our budgeting process of our commodity prices or that stacks up. I don't think you would see us do that in a sub-$40 environment like we're close to right now. As prices push towards $50, I think, we'd have a better opportunity to try to do something in Tonkawa. Don't expect to do anything though in the back half of this year. It would be 2017.
Thanks. Great. That's all for me, guys.
[Operator Instructions] There are no further questions at this time. I'd like to turn the call back over to management for closing remarks.
Thank you, operator, and thanks all of you for listening today. I am confident that what we have discussed today is just the beginning of great things to come for Jones Energy. I look forward to providing you with further updates on our next call. Operator, you may now bring this call to a close.
This concludes today's conference call. You may now disconnect.
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