Vital Energy Inc (VTLE) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Laredo Petroleum, Inc.'s third-quarter 2016 earnings conference call. My name is Andrew and I will be your operator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce Mr. Ron Hagood, Director of Investor Relations. You may proceed, sir.

Thank you and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Dan Schooley, Senior Vice President of Operations; and Karen Chandler, Vice President of Operations as well as additional members of our Management team.

Before we begin this morning, let me remind you that during today's call we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts, and assumptions, are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control.

In addition, we will be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in today's news release.

Yesterday afternoon the Company issued a news release and presentation detailing its financial and operating results for the third quarter 2016. If you do not have a copy of this news release or presentation, you may access it on the Company's website at www.laredopetro.com. I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron, and good morning, everyone. Thank you for joining Laredo's third-quarter 2016 earnings conference call. Laredo continued its trend of exceptional operational performance in the third quarter, demonstrating the advantages of our acreage position.

Production again exceeded the top end of our upwardly revised guidance as utilization and refinement of the multivariate Earth Model continued to drive production outperformance versus the Company type curves. Benefits of previous infrastructure investments continued to grow as more wells existing production corridors helping to further reduce LOE.

The ongoing outperformance of our drilling program in 2016, coupled with the reduced downtime associated with our base production, continues to drive production higher and we now expect full-year 2016 production to be up approximately 10% versus 2015. This is up significantly from initial expectations for 2016 growth.

We continue to refine our multivariate Earth Model workloads, integrating additional engineering parameters that are related to oil production. The multivariate reprocessing time has evolved from 12 to 18 months to a matter of weeks as we have developed proprietary work flows in house.

Especially valuable is the Hydraulic Fracture Test Site, a joint industry project led by Laredo and the Gas Technology Institute. This $23 million project is amassing a comprehensive set of data proprietary to the consortium members to be used in modeling hydraulic fracture propagation and profit placement.

This data collection was led by Laredo in a package of 11 wells the Company drilled late in 2015, with its leasehold in Reagan County. The multivariate Earth Model has included data from the project, along with other engineering and GSI data, to optimize our development drilling.

To take advantage of the tremendous capital efficiency gains derived by the multivariate Earth Model uplift, drilling efficiencies, reduced operation expenses, the Company is adding a fourth horizontal rig in mid-November. Capital efficiency improvements throughout 2016 have enabled the Company to operate well within its capital budget, and as such, we are able to add the fourth rig without increasing our $420 million capital program for the year.

Our recently reaffirmed borrowing base under our credit facility, which provides $755 million of liquidity, our extremely strong hedge position, our flexible balance sheet with no term debt maturities for more than five years, and a debit to EBITDA ratio of around 3 times enabled us to confidently accelerate value creation in an uncertain commodity price environment. Later in the call, Rick will give more detail on how our hedging strategy reduces variability in our anticipated cash flows, and enables the Company to minimize the impact of commodity price weaknesses.

I would now like to turn it over to Dan for an operational update.

Thank you, Randy. For the second consecutive quarter the Company (technical difficulty) record quarterly production (technical difficulty) 4.7 million BOEs or 51,276 BOE per day. We continue to benefit from the efficiencies generated by early investments in data and infrastructure, and a contiguous acreage position that enables extended reach drilling.

Average lateral lengths in 2016 were approximately 10,000 feet, and four wells were drilled longer than 13,000 feet. During the third quarter, we completed 10 horizontal development wells, seven of which were a package of wells brought online late in the quarter in a managed drawdown and therefore currently have limited relevant production data.

Two significant completions that occurred early in the quarter were tests of the multivariate Earth Model wells with 2,400 pounds of sand per foot. The production on these wells in the first 30 to 45 days reflects the managed drawdown protocol, but with approximately 90 days of production, these wells have cumulative production of 161% and140% of type curve on a lateral adjusted basis.

Additionally, the seven wells that were completed later in the quarter were also completed with 2,400 pounds of sand per foot. We are very encouraged by these early results of the first two wells, and will be watching the data on all nine wells closely to continue to determine the economics of their completion design.

Drilling efficiencies and lower operational costs, combined with the multivariate Earth Model production performance improvement, is generating a significant uplift in returns. As Randy mentioned, we are adding a fourth horizontal rig in mid-November to take advantage of these improvements. We do not expect the rig to contribute to 2016 production, but we do expect to operate the rig throughout 2017.

Unit lease operating expenses in the third quarter decreased to $3.85 per BOE from $6.09 per BOE in the third quarter of 2015. Field infrastructure investments are responsible for a $0.52 per BOE reduction, primarily attributable to the LMS water infrastructure assets.

LMS gathered 67% of produced water by pipe, saving approximately 1.9 million (technical difficulty) trucking. Additionally, LMS water treatment plant supplied more than 1.8 million barrels of recycled water for completion operations, and recycled more than 1.6 million barrels of flowback and produced water at an aggregate cost savings of approximately $800,000.

LMS crude gathering assets transported by pipe approximately 69% of the Company's total gross operated oil production during the third quarter, or approximately 2 million barrels of oil, generating a benefit of approximately $3.1 million during the quarter. As we focus drilling along production corridors, the volume of oil transported by pipe has increased materially.

During the third quarter of 2015, LMS transported by pipe approximately 44% of the Company's total gross operated oil production, or approximately 1.1 million barrels of oil. This growth trend is expected to continue into 2017, with approximately 80% of gross operated oil production expected to be transported by pipe, as additional drilling is focused around production corridors.

The Medallion Midland Basin pipeline system continued its impressive growth as it increased transported volumes to an average of almost 118,000 barrels of oil per day in the third quarter, a growth of approximately 19% from the second quarter of 2016. Even in the challenging commodity price environment, the system has shown consistent quarter-over-quarter growth and has continued to see the rig count increase on acreage dedicated to the system.

The system is expected to grow transported volumes 50% to 60% by the end of 2017 from the expected 2016 exit rate of approximately 140,000 barrels of oil per day. This rate excludes any projects that are not currently under way, thus growth can benefit from additional expansions of the system. Financial performance is expected to remain consistent with EBITDA expected to grow at a rate commensurate with transported volume growth.

With that, I will turn the call over to Rick for a financial overview.

Thank you, Dan, and good morning. As we reported last night in our third quarter 2016 earnings press release, the Company posted solid results driven by strong operating and well performance, coupled with our continued focus on cost control. As a result, we reported net income of $9.5 million, or $0.04 per diluted share.

Our adjusted net income, a non-GAAP financial measure, increased 94% from the prior-year quarter to $28.4 million, or $0.12 per diluted share. Our press release includes the reconciliation of non-GAAP financial measures.

Adjusted EBITDA for the third quarter of 2016 increased to $118 million from the comparable $110 million in the second quarter of this year. Note that to be more comparable to our peers, we have modified the adjusted EBITDA calculation to reflect the non-cash asset retirement obligations, as well as to include Laredo's proportionate share of the Medallion Midland Basin pipeline system's EBITDA.

As the Medallion system continues to grow in value to Laredo, we incorporated our share of Medallion's adjusted EBITDA under the line item proportionate adjusted EBITDA of equity method investee in our reconciliation of net income to adjusted EBITDA. In the third quarter of 2016, cash flow from operations before changes in working capital was approximately $91 million, once again more than funding the incurred capital expenditures of approximately $79 million in our exploration and development activities.

For the first nine months of 2016, excluding the Western Glasscock bolt-on acreage acquisition, we have incurred total capital expenditures of approximately $265 million, relative to our $420 million revised capital budget. As Randy mentioned, we are adding a fourth horizontal rig to our program in mid-November, and due to the efficiencies we have already achieved to date, we expect to cover the additional capital costs within the $420 million capital budget.

Through the fall borrowing base redetermination process, our bank group has now reaffirmed Laredo's borrowing base on our senior secured credit facility at $815 million. Keep in mind that this credit facility does not include any pledge of our 49% interest in the Medallion pipeline system.

We currently have $70 million drawn on this credit line, resulting in liquidity of approximately $755 million. We believe that this provides ample flexibility for the Company to maintain a four-rig program. At current strip prices, which are underpinned by our strong hedge position, we expect to remain under 4 times on debt to EBITDA calculation, not accounting for any potential acquisition through investitures or further Medallion investments.

Our hedging strategy, which targets approximately 75% of our anticipated production for a rolling 12-month to 18-month period, has enabled the Company to maintain both a robust capital program and annual production growth, even during a period of depressed commodity prices. Since the beginning of 2015, our hedging program has produced more than $400 million of benefits to the Company.

We have continued to actively add hedges, and now have hedged almost 7 million barrels of oil for 2017, and more than 2 million barrels of oil for 2018, with both years' hedges having a weighted average floor price of approximately $56 per barrel. Keep in mind that these hedges provide real floor protection to our prices, in that we do not use short puts.

In addition, our hedges retain significant exposure to upward movement in oil prices, as approximately 70% of the 2017 oil hedges have either no ceiling or a ceiling price of $86 per barrel. We are very pleased with the continued progress that our team has made in the efficient development of the vast resource potential that we have identified in the Midland Basin properties, and excited about the future of Laredo for all of our stakeholders.

At this time, operator, we would like to open the lines for any questions.

(Operator Instructions)

Our first question or comment comes from the line of Neal Dingmann with SunTrust. Your line is now open.

Good morning. Outstanding quarter. Randy, could you, or Dan or one of the ops guys, talk a little bit about -- I'm pleasantly surprised how good the wells continue to look despite you continuing to use I think what appears to be a tighter choke program than some others. Would you talk about how you initially are putting these chokes on, and then how you are letting them go versus maybe the typical wells that are on your area?

Thanks, Neal. We had this view all along, as you know, that the emphasis on the 24-hour IP and the first two or three weeks and 30-day accelerated IP was probably not what we wanted to do. We talked about it in the past, that we wanted to see significant data before we really called it.

What we are really trying to do is make sure that on our flowbacks we are allowing the well to flow back at a rate such that we make sure, or attempt to make sure, that where we put the proppant it stays there. We are trying to make sure that we are not changing any of the relative perm curves near well bore.

We are trying to make sure that we get the maximum benefit over time for our completions. We are seeing some really I think outstanding early results. But I think our view is also that, like everything else, we want to see substantive data.

This is kind of what we have been doing for some time. And so for us, it is just acknowledging that our behavior is very geared toward making sure that we get the most value out of that well bore over time.

Makes sense. And then just lastly, on the longer laterals, interesting to see that you had even some put in the press release here greater than the 13,000 feet. What is your thoughts there on diminishing returns? Are you starting to hit that once you get out to 13,000 feet, or are you still pushing the limits there?

There is a couple of issues there, and I think one of them is our acreage base allows us, the way we bought it blocked up, leased it, to actually look at drilling those linked laterals. And I'm not sure that we have seen enough data to call a breakover point on what's the right length, but what I will say is that that last couple of thousand feet of lateral gets drilled pretty cheaply.

We now have some pretty good information that says that we are able to very effectively complete that. We are not having completion issues. So I think our view is that if you look at our lateral lengths, the ones we've drilled averaging more or less 10,000, we've got some room to move that average up, if the data supports that.

Makes sense. Thanks so much.

Thank you.

(Operator Instructions)

Our next question comes from the line of Brian Singer with Goldman Sachs. Your line is now open.

Thank you. Good morning.

Good morning, Brian.

You highlighted the improved efficiencies and productivities that you are seeing in the Cline Shale and that the returns there are approaching what you're seeing in the Wolfcamp. Can you talk to what or add more color on what specifically you are doing there and why the gap between the Cline and the Wolfcamp has improved as opposed to they're both just going -- they're both just moving directionally up?

That's a good question. There are a couple of things right off the bat. One of them is as you know the Cline is deeper, slightly harder, a little more pressured, so it's a little more costly to drill. We've made some pretty big impacts on our drilling AFEs.

The second thing I think is a big push is that we have completed and we have really done a lot of the Earth Model multivariate work on the client, and I think it is helping us land the lateral better. And that is allowing us to optimize the completions much, much more specifically.

So it's the ability to drill more efficiently, the landings on the optimization, and the completion optimization. And we have drilled a lot of Cline over our acreage, and I think when you look in terms of inventory going forward, we've got a lot of zones to look at.

We've got multiple landing zones in some of those zones. But I think going forward, the Cline will be one of the targets that we drill some, although I think we have lots of targets to look at.

Got it. Great. Thank you very much.

Thank you.

And our next question or comment comes from the line of John Herrlin with Societe Generale. Your line is now open.

You addressed this a little bit, Randy, but some of these wells are getting pretty long. How difficult is it to really frac out 13,000 feet?

It is interesting to us. We were worried, John, early on not only about the ability to drill it, but we were also worried whether or not we could effectively, for a number of reasons, the obvious first one is friction loss and so on and so forth, reach out and complete that well. We have now done it successfully.

You kind of have to plan for it. It obviously takes some pretty good pump pressure, but our early indications are that we are able to complete those wells very, very, very successfully. And again, John, that is incrementally some pretty cheap returns if we can drill that extra couple of thousand feet and complete it successfully.

Great, but I was just wondering with slick water how difficult it would be to frac out that far.

It hasn't really been an issue for us. We have successfully done it. We haven't had big problems.

The water specifically, with the way we are doing our infrastructure and corridors, we've got the water. We can actually manage that much water. You are pumping out there quite a ways, but we are effectively getting the fracs off without any real issues so far.

Great. One other question, we have had a lot of equity infusion to the sector. The Permian is certainly heating up. Are you worried about things getting overheated on an intermediate term basis, just given the ramp up in activity for the industry?

I think we have seen a lot of conversation about cost increasing in terms of service costs, and specifically on the pressure pumping side. But as you know, there is lots of pressure pumping companies out there. Some are still looking for work.

I think the intensity of activity is still going to be a reflection of somewhat of commodity prices. So I am expecting a gradual ramp up in activity. And I am very confident that as we ask the service companies for more technology and more services, over time costs are going to go up.

I don't see it being a big issue short term for us. It is interesting to see, your question about equity, it is interesting to see prices being paid in and around our acreage, and we put our acreage together a number of years ago at substantially less cost than what is being paid in the market today.

That's true. Last one for me, in terms of your Earth Model, you've talked about it for a long time now. We are seeing the results from those efforts. Do you think the street really understands what you are doing vis-a-vis a lot of your peers for essentially outsourcing a lot of the petrophysical work?

I think, I actually think the answer to your question is no. I think the Earth Model is a multivariate. It is a very interactive evolving program. It takes data.

It takes years of data in some cases. It takes data that you can only get one point in the life of the well. I think, John, the GTI study that was done, we were the operator, we didn't put -- that was at no cost to us other than just making sure we operated it properly.

Those are the kind of data sets that really lend itself to giving a lot of credibility to our Earth Model. We have now already incorporated some of that data into the Earth Model. It is proprietary for another couple of years, I think, and we are seeing how that works.

So the Earth Model is -- we have seen other people say, well, we have an Earth Model. I think we all have Earth Models. That is not new. But I think the approach we have and the way we have gone about it is very, very deliberate.

It is something that we have done at some of my prior companies, and the interesting thing I think is that we leveraged our relationships with a couple of the other large service providers. We were very pleased with the effort that we had with Halliburton.

We've got Schlumberger doing some stuff for us. The GTI project in itself really gave us a huge jump start. All of those were helpful. But we have moved all of that work flow and analysis in house, and we are doing it in many ways with proprietary techniques.

So I think it is one of those things, John, where I don't think it is -- I don't think we have communicated it. It would take a long time to communicate it. I don't think it is well understood. But the facts are, the data that we are getting in terms of production and production increases, tells us that the Earth Model in our optimized completion is working.

Great. Thanks, Randy.

Thank you.

And at this time, I am showing no further questions. So with that said, I would like to turn the conference back over to the Director of Investor Relations, Mr. Ron Hagood, for any closing remarks.

Thank you for joining us for our third-quarter earnings call. We appreciate your interest in the Company, and have a good morning.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone, have a wonderful day.