Penn Virginia Corporation
Q4 2017 Earnings Call Transcript

Published: 2 Mar 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation Fourth Quarter and Full Year 2017 Earnings and 2018 Outlook Webcast. At this time, all participants are in a listen-only mode. Following management’s prepared remarks, we will host a question-and-answer session and our instructions will be given at that time. [Operator Instructions] As a reminder, this conference call is being recorded for replay purposes. It is now my pleasure to hand the conference over to Mr. John Brooks, President and Chief Executive Officer. Sir, you may begin.

[John Brooks:]

Thank you, Brian, and good morning, everyone. We appreciate your participation in today's call. I'm joined this morning by Steve Hartman, our Chief Financial Officer; and Ben Mathis, our Vice President of Operations. Prior to getting started, I'd like to remind you of the language in our forward-looking statement section of the press release, which was released yesterday afternoon. Our comments today will contain forward-looking statements within the meaning of the federal securities laws. These statements, which include, but are not limited to, comments on our operational guidance, are subject to a number of risks and uncertainties that could cause actual results to be materially different from those forward-looking statements, including those identified in the risk factors of our annual report on Form 10-K. We will discuss non-GAAP measures on this call. Definitions and reconciliations of these measures to the most comparable GAAP measure are provided in the presentation posted on our website this morning. Cautionary language is also included in Slide 1 of our presentation, and we will use this presentation to go through today's discussion. Finally, after our prepared remarks, we will answer any questions you may have. So let's start on Page 2 with a quick company overview. Penn Virginia is a pure play, Eagle Ford shale-focused operator in Gonzales, Lavaca and DeWitt counties in South Texas. As you know, yesterday, we closed our previously announced acquisition of Hunt Oil Company's Gonzales and Lavaca County Eagle Ford assets. Including the Hunt acquisition, we had 83,100 core net acres in the Eagle Ford as of year-end, which is about 93% held by production and 99% of which is now operated by Penn Virginia. Our product mix in the fourth quarter was 75% oil, which receives the Louisiana Light Sweet, or LLS premium, and generates very attractive realized pricing in EBITDAX margins. We're currently running three rigs in one dedicated frac spread, and we plan on bringing in on spot frac spread periodically as our debt inventory builds. We're targeting year-over-year production growth of 125%. We have a large inventory of Lower Eagle Ford drilling locations, totaling 589 gross and approximately 500 net as of year-end 2017 pro forma for the Hunt acquisition. So far, we've identified 80 net XRLs, or extended reach laterals, which we loosely define as lateral lengths of approximately 8,000 feet or greater across our leasehold. We expect this XRL count will increase over time as we continue to identify opportunities to form production sharing agreements across unit lines to not only optimize capital efficiency but also to access otherwise stranded reserves. Our fourth quarter 2017 production averaged 12,340 barrels of oil equivalent per day. And for the last five days of 2017, we averaged 14,650 barrels of oil equivalent per day, reflecting the early contribution of our two-well Geo Hunter pad in Area 2, which we turned to sales near the end of December. Moving on to Page 3. The Geo Hunter pad was our second confirmation test of slickwater completions in Area 2, and we've been very pleased with that pad's results. We're also very excited about another successful test in Area 2, our two-well Southern Hunter Amber pad, which has a preliminary peak rate 24-hour IP of 5,092 barrels of oil equivalent per day, is 86% oil and exceeds our type curve expectations. The two-well Southern Hunter Amber pad resulted from forming a production sharing agreement across two units that allowed us to drill two wells with average lateral lengths over 8,100 feet and enable us to access reserves that would have otherwise been left in the ground. This is our third pad in Area 2, and we look forward to more Area 2 activity this year, including two pads that are currently waiting on completion that we plan to turn to sales next month. Over the last few months, we've significantly expanded our technical team and upgraded our drilling and completion service providers, and this combination is delivering significant improvements in operational execution, both with respect to drilling and also the completions, which we'll illustrate quite clearly a little later on in the presentation. Fourth quarter 2017 production increased 31% over third quarter 2017. And as I mentioned, we're targeting 125% production growth year-over-year for 2018. In 2017, we increased our proved reserves by 47% at a drill-bit finding and development cost of $4.40 per barrel of oil equivalent. Yesterday, we closed on our previously announced acquisition of certain of Hunt Oil Company's Eagle Ford assets, and simultaneous with that closing, also increased our borrowing base by more than 40% to $340 million. With the Hunt acquisition at year-end, we had 83,100 core net acres that is 93% held by production, 99% operated, over 420 operated Eagle Ford wells and 589 drilling locations with 85 million barrels of oil equivalent in proved reserves. Moving on to Page 4. While we were able to grow fourth quarter 2017 production, 31% over the third quarter, the fourth quarter was not without challenges. As we have previously reported in our third quarter call, equipment-related drilling challenges in the second half of 2017 yielded laterals meaningfully shorter than originally planned and had adversely impacted fourth quarter production. Since then, we've completely changed out our drilling fleet, we've substantially upgraded equipment, expanded the technical staff and those drilling operational challenges have been resolved. And while the Geo Hunter pad came in with very strong production exceeding type curve, our former stimulation service providers completion efficiencies fell short of expectations, mainly with respect to the number of frac stages per day they were able to deliver. This lower completion pace resulted in the Geo Hunter pad coming online later than expected. Additionally, the completion of the two-well Furrh pad was also delayed into January. As that frac contract expired at the end of December, we changed out our stimulation services provider so we've also improved on our completion execution, in addition to the improvement we've seen on the drilling side. Looking forward, we expect another 30% growth in production, with first quarter guidance of 15,500 to 16,500 barrels of oil equivalent per day. So even with the challenges we encountered in the second half of 2018, we're excited about delivering back-to-back quarters of 30% growth. Moving on to Page 5. The first few charts on the left side of the page here very clearly illustrates the improved operational execution that our new technical team and upgraded drilling and completion service providers are achieving. In Area 1, where we drilled two string wells, our average effective feet per day has improved 30%. In Area 2, where we drilled three string wells, our average effective feet per day has improved even more dramatically up about 60%. Now this is just simply our average feet per day from spud to rig release, comparing the first three quarters of 2017 to the average that we experienced in the fourth quarter of 2017 through year-to-date 2018. And this reflects the improvement the new technical team and drilling equipment have achieved. The chart on the right-hand side of Page 5 also clearly illustrates the improved completion efficiencies since changing frac service providers, going from 4.7 stages per day to 6.6 stages per day. And while the average of 2017 may have been 4.7 stages per day, later in the year, the average over the last two pads in 2017 was only 3.2. So we've had quite an improvement here lately, over doubling that completion efficiencies. Moving on to Page 6. We have a summary of our reserves at year-end 2017. And please note that this is excluding the Hunt acquisition. Reserves grew 47% from 49.5 million barrels of oil equivalent to 72.6 million barrels of oil equivalent, and consist of 77% oil, 12% NGLs and 11% natural gas. The PV-10, valued at strip pricing at year-end 2017, was approximately $632 million, with $467 million of that in the form of proved developed producing reserves. Looking just at our South Texas properties and excluding our legacy Oklahoma assets, Eagle Ford proved reserves grew 49% year-over-year to 70.2 million barrels of oil equivalent, and we replaced 710% of 2017 production at a drill-bit finding and development cost of $4.40 per BOE. On Page 7, we provide details of our drilling inventory, breaking it down by Area 1, Area 2 North and Area 3 South, as well as by conventional laterals and extended reach laterals or XLRs. I want to point out that well costs have increased somewhat by between $100,000 and $400,000 per well across this inventory set, driven for the most part by increases in stimulation costs. Our capital plan for 2018 is an estimated $320 million to $360 million, as you'll see on Page 8, 95% of which is anticipated to be directed to Eagle Ford drilling and completion, and the balance directed primarily toward facilities, pipelines in land. We expect to drill a total of 55 to 60 gross wells, 45 to 50 net wells. And as it stands today, 22 of the gross well count will be XRLs. As you can see, capital allocation by area is pretty close to 50% in Area 1, and 50% in Area 2, with a higher numerical well count in Area 1. While this is our current plan, drilling schedules tend to change. Our 2018 drilling schedule reflects a shift to drilling wells with the longer XRLs, as illustrated in the chart at bottom right. So you can see in 2017, our average treatable lateral length was 5,250 feet. But for 2018, we expect that to increase 33% over the prior year to about 7,000 feet. And to the extent we're able to timely form additional PSAs that allow for drilling more extended reach laterals, the drilling schedule is flexible enough for changes that allow us to more efficiently deploy capital. Moving on to Page 9. This is our activity map. Now with our recent pickup in drilling and completion activity, this map gets really busy fairly quickly, so we've just shown the highlights and where we have new information. First of all, the blue colored acreage is the formerly Hunt-operated leasehold that we just acquired. Along with that, came Hunt's working interest in the Penn Virginia-operated Area 1 acreage further to the northeast, or upper right on the map, where we've got two active drilling rigs, the Snipe Hunter 3 well pad and the Elk Hunter 3-well pad to which one of our drilling rigs is currently mobilizing. This also shows where our dedicated frac spread is currently active at the Bongo Hunter 3-well pad. Additionally, this shows where our third drilling rig is active, which is on the 3-well Lott pad, which you can see on the callout box, second from the top on the upper right of the map. Below that, we have the 2-well Schacherl-Effenberger pad and the 3-well McCreary-Technik pad, both of which are PSA pads and are scheduled to begin completion operations later this month. Down in our most southern acreage, or first foray into DeWitt County unit, we have the 3-well Medina pad also waiting on completion. So we've got a total of eight DUCs waiting on completion, which we plan to complete over the next couple of months. Continuing around clockwise, we come to the Dubose 3-well pad, which has been completed and recently commenced flowback. Continuing up, we come to the Furrh pad, the completion of which was originally scheduled for the fourth quarter but was moved into the first quarter of this year as I mentioned earlier. This 2-well pad in the up-dip portion of our Area 1 has a preliminary IP over 2,500 barrels of oil equivalent per day. Now while 2,500 BOE per day is a pretty good outcome, when you look at the 2-well Geo Hunter and 2-well Southern Hunter Amber pads with IPs in excess of 5,000 BOE per day, you can see why we're so excited about further delineation in Area 2. Moving on to Slide 10, I want to walk you through the value proposition over the next four slides that comes from the 2018 drilling program. We start with production growth. Production growth in 2018 is the heart of the Penn Virginia story. We expect about 125% production growth in 2018 over 2017 with our development plan. Our guidance for first quarter 2018 is between – 15,500 to 16,500 barrels of oil equivalent per day. And this would include one month of contribution from the Hunt acquisition. Even though the effective date of the Hunt acquisition is October 1, Hunt-related production and cash flow prior to yesterday's closing is treated as a purchase price adjustment, and therefore won't be included in the first two months of the first quarter. Looking to the second quarter, that's the first quarter where we see the full effect of the Hunt acquisition, not only in PDP volumes, but also by virtue of our increased working interest throughout a big part of Area 1. We aren't giving second through fourth quarter guidance yet, but we expect a meaningful growth each quarter. The end result is full year guidance of 22,000 to 25,000 barrels of oil equivalent per day and that growth leads us to the next slide. Slide 11 is where we show you our cash cost on a per barrel of oil equivalent basis. In 2017, we saw $12.08 per barrel of oil equivalent for our total cash cost, or the sum of LOE, GPT and cash G&A adjusted for some onetime items, which are reconciled in the appendix of the presentation. For 2018, thanks to higher working interest as a result of the recent acquisitions and substantial production growth, we expect our cash cost per BOE to be $10.38 at the midpoint of guidance. Remember, we had to add very little G&A cost to support the Devon and Hunt acquisitions, so we're driving cost down and cash margin up per barrel of oil equivalent. This lower cost lead us to the next slide, on Page 12, which shows our adjusted EBITDAX per barrel of oil equivalent. For full year 2017, we realized $27.05 per BOE as adjusted EBITDAX. And while we're not giving adjusted EBITDAX guidance with WTI oil prices in the upper 50s to low 60s, cash cost of $10.38 per BOE and premium LLS pricing, which gives us realized differentials of WTI of $1 to $2, you can see our cash margins are getting much better. You can really see this in our fourth quarter 2017 realized number. Our adjusted EBITDAX per barrel of oil equivalent for the fourth quarter was $32.97, and we expect adjusted EBITDAX per barrel of oil equivalent to increase throughout the year. And the strong cash margins, combined with strong production growth, which leads to the next slide, 13, which shows our balance sheet improvement. Pro forma, for the Hunt acquisition, we had debt to adjusted EBITDAX ratio, as defined in our credit facility, of about 2.6x. With our production growth and our improving cost structure, we see that leverage coming down to about 1.5x by year-end. And we expect to be drilling within cash flow by the end of the year as well. Along with the 125% anticipated production growth, these are our financial goals for 2018 that we are committed to achieving. So with this plan laid out for you, let's look at how we compared to our small to midsize E&P peers. The next few slides show data from a range of peers, which was gathered by an outside firm. Since the data is based on consensus estimates and was gathered prior to issuing our earnings, it doesn't tie the numbers we discussed, but it's very directional. I should show – note that we are not endorsing or confirming any of the consensus estimates on the next several slides. So turning to Page – Slide 14, we believe we have a very high growth rate for 2018 compared to that of our peers. As I mentioned, the chart is showing consensus estimates and we are actually targeting a growth rate of approximately 125% based on the midpoint of guidance. And that's even higher than what is shown here. On Slide 15, although we don't guide the EBITDAX, we expect it to increase considerably in 2018 as a result of our production growth and lower cost profile. On Slide 16, with the growth I laid out for you, the low-cost structure and very strong cash margins, this third-party data has us trading at the lowest multiple to 2018 EBITDAX and a small to mid-cap peer group. So on to Slide 17, what is Penn Virginia's value proposition? We are pure play Eagle Ford company with a large derisk contiguous acreage position. We're focused on returns and we have a drilling inventory that provides a nice runway for delivering those returns. We have quality assets that are oil-rich, centered in the volatile oil window of the Eagle Ford and well positioned to geographically to take advantage of Louisiana Light Sweet premium pricing. We are committed to financial discipline with a well-defined plan to get us to leverage of 1.5x by year-end, and drilling within cash flow. And we are protecting that cash flow along the way with hedges. And finally, we have growth potential. If you take away anything from this presentation, you should take away that we are growing rapidly. We have a multiyear inventory of drilling locations with superior economics, especially with the growing inventory of XRLs in Area 2 as well as in Area 1. And with that, Brian, we can go to the Q&A portion of the call.

[Operator:]

Thank you, sir. [Operator Instructions] And our first question will come from the line of Jeff Grampp with Northland Capital. Your line is now open.

[Jeff Grampp:]

Good morning, guys.

[John Brooks:]

Hey, Jeff.

[Jeff Grampp:]

Question first, John, on the cycle time. Appreciate the detail on kind of where you guys had been at lately. First, I just wanted to understand the dynamics there. Would you say that, that's kind of generally the new service providers on the drilling and completion side, as well as what you guys have kind of stacked up internally or kind of the main drivers there? And then as we kind of look at your activity levels now, it seems like – and you got 20-plus wells kind of drilling or completing, and you're going to do 55 or 60 for the year, it seems like you guys are maybe ahead of schedule. Or is it kind of a front-end-loaded program? I guess, just kind of wondering how we should interpret kind of where you guys are at on a drilling and completion side.

[John Brooks:]

Well, our drilling and completion team continues to make strides. I think there's probably some upside on the drilling and completion cycle times. We have modeled, on the drilling side, the average of what we have seen. And in the middle of all that, that also includes some wells that we've had some really outstanding cycle times as well as a couple where directional tools failed and we required a couple of extra trips. So if we get more consistency on the directional drilling tool side, I think we can drive the cycle time down even further on the drilling. And on the completion side, I think we're modeling 5.5 stages per day. And the real-time estimate on that of what we're delivering is over – is between six and seven and closer to seven. Here recently we've had quite a few eight stages per day and even a couple of nine stages per day. So getting that consistency on the stages per day down and tightening that spread could certainly lead to some improved cycle times as well. So I wouldn't really want to say that anything is front-end loaded. I think that the DUC inventory we're building will allow us some flexibility in scheduling of what pads we go to, to frac, and that's important in a mature asset, so that we can hopefully limit adverse impacts and frac hits throughout the asset. And we've already had a spot frac group come in once this quarter, and we expect the second one here shortly as well. So we anticipate the McCreary-Technik and Schacherl-Effenberger pads being fracked here this month, followed by the Medina pad shortly thereafter. So I think you'll see that 6 to 10 DUC inventory roll forward as we go through the year, and will get them fracked and put online as quickly as we can.

[Jeff Grampp:]

Okay, perfect. Appreciate that detail. And then on the – for my follow-up, kind of interesting on the commentary on the PSAs and it certainly sounds like a pretty good kind of trade-offs there with extending those. Was just kind of curious if you guys kind of line of sight towards getting more of those done, do you think, John, that maybe it looks like about 40% of your wells this year is going to be those XRLs? Is that a number you think you can maintain? Or how do you think that maybe evolves longer term?

[John Brooks:]

Well, in terms of percentage, I think we stated we got 22 of them out of a total of 60, is that kind of the rough number; so 30% to 40%. What we typically have included are the ones where we've got PSAs close to completion. So we're continually adding to that. So we do anticipate having more extended reach laterals as the year changes, or as the year progresses, and the drilling schedule will be changed to reflect that. So the current schedule is planned – planning will yield 7,000-foot laterals as we see it today, but there's a very good chance the number goes up.

[Jeff Grampp:]

Okay, great. Appreciate the thought. Thanks, guys.

[Operator:]

Thank you. And our next question will come from the line of Neal Dingmann with SunTrust. Your line is now open.

[Neal Dingmann:]

Good morning, John. John, most of your acreage is HBP, but I'm wondering, for the drilling plan this year, what size pads are you sort of targeting. Or I guess, another way to ask the question, just wondering, you gave first quarter and sort of for the year guidance, I was just wondering how lumpy we should think about the guidance being the remainder of the year given the size of the pads.

[John Brooks:]

Well, the size of the pads are going to be 2- and 3-well pads. We don't currently have any 4-well pads contemplated. There may be one or two single-well pads. I think there's some stranded reserves by virtue of the two acquisitions that we've done, where we might be able to squeeze in a well where one had lessened reserves behind. But on average, they're going to be 2- and 3-well pads. So the lumpiness that we have will probably be more related to when we drop the DUC inventory down by virtue of the second spot frac spread coming in. But we think it's going to be fairly steady production growth quarter-over-quarter.

[Neal Dingmann:]

Got it. And then just one follow-up on service cost. What are you assuming for service cost inflation, John, and how are you looking as far as – I know prior company that was going to get a bit a promise on sourcing sand and other things, how is that going right now?

[John Brooks:]

Well, I'll deal with the second question first. We have self-sourced the significant portion of our sand needs for 2018, with a mine here in Texas. It's not fully up and ramped up to full production, but it will be this month. So the – actually the – probably the early part of 2018 drilling plan will have some slightly higher frac cost until that sand mine is delivering at full load. That being said, out beyond the second half of the year, frac cost can certainly be subject to upward pressures. But right now, I think, the frac and drilling completion cost that we've seen across the board, I think, it's about a 5% increase over our prior estimates.

[Neal Dingmann:]

Very good. Thanks, John.

[John Brooks:]

Thank you, Neal.

[Operator:]

Thank you. And our next question will come from the line of Richard Tullis with Capital One. Your line is now open.

[Richard Tullis:]

Hey, thanks. Good morning, John.

[John Brooks:]

Hey, Richard.

[Richard Tullis:]

Coming off the two acquisitions for 2017, that really increased the acreage footprint of the company. What's the go-forward acquisition strategy at this point, John? Is it mainly focused on trades and bolt-ons? Or would you be looking at more sizable acreage add?

[John Brooks:]

Well, we're always looking at the bolt-ons and trades and swaps as they become available. And there's a finite set of those around us. But our first priorities here are to grow our production and revenue to reduce our leverage ratio back to a 1.5x ratio in conjunction with funding the development program from – with cash flow from operations about the year for 2018. So if we're able to grow into that goal more quickly or if the opportunity for another transaction comes along is too attractive to pass up, by all means, we're going to look at it. But first thing's first, we just closed on two strategic acquisitions in the last six months that we need to digest.

[Richard Tullis:]

Thank you. I appreciate those comments. And lastly, for me, John, sorry if I missed this. What was the lateral for the Geo Hunter pad?

[John Brooks:]

I think those were average about 7,400 to 7,500.

[Richard Tullis:]

Okay. All right, that’s all from me. Thank you.

[Operator:]

Thank you. [Operator Instructions] And our next question will come from the line of Ron Mills with Johnson Rice. Your line is now open.

[Ron Mills:]

Good morning, John. Just a point of clarification. You talked about a couple of the wells may be not having an effective frac job across the whole lateral. Which wells were those and what were – was that part of the fourth quarter impact as well?

[John Brooks:]

No, maybe you misunderstood me. I think we had some wells that we just didn't get drilled and cased as long as we would have liked, but that was really limited to the second half of 2017. Maybe that's what – is that what you referencing?

[Ron Mills:]

Yes, it may have been. That's why I was trying to clarify but – since the Geo Hunter the Southern Hunter wells, those were both wells that were drilled subsequent to changing out the rigs and even the completion crews. Is that correct?

[John Brooks:]

Correct. The Geo Hunter, however, was a fracked with the prior completion crew, but it was drilled by the current drilling fleet.

[Ron Mills:]

And are you seeing anything in terms of – from a rock standpoint, and what potentially is – is there anything different about those wells given the high level of productivity that's applicable across a greater portion of your acreage? And can you remind me what spacing you plan on developing your acreage at?

[John Brooks:]

Okay, well, let me answer the first question. The primary difference, I guess, is we're getting a little bit deeper there so we have a little bit more pressure to work with. And the pressure really helps there. On the spacing side, we have stuck to our nominal spacing across our field of 400 to 500. And sometimes they're going to be 450, sometimes, they'll be 550, depending on how much room is left in a unit. So the spacing, like I said, is nominally 400 to 500, but it can range from 450 up to 550, or sometimes 600. We don't want to fit two wells in at 300-foot spacing, so we will stick to the 400 to 500 nominal.

[Ron Mills:]

And that's where I was going with that. I assume at that level of spacing you're not seeing any pressure depletion or any of the parent-child relationships?

[John Brooks:]

Since we have transitioned to slickwater completions starting in the third quarter of 2015, the frac hits that we have observed have, on average 75% or so, been positive. Now what we observed during our prior completion design, which was hybrids, frac hits were often negative and sometimes catastrophically. So – but while we've seen on the slickwater completions, roughly 75% of the time, it's a positive frac hit. I can't give you a physical model that explains that, but just the observation of the empirical data. The biggest impact to the infill drilling with the slickwater completion that we're doing now is just the shut-in volumes that we've got to shut in, in and around it while drilling and completing. But like I said, the parent-child relationships are generally positive and overall, we just consider it a neutral event.

[Ron Mills:]

Great, thank you very much.

[Operator:]

Thank you. Ladies and gentlemen, this concludes our question-and-answer session for today. It's my pleasure to hand the conference back over to Mr. John Brooks, President and Chief Executive Officer for some closing comments or remarks. Sir?

[John Brooks:]

Well, thank you for your time this morning and participating in the call and your interest in Penn Virginia. We look forward to talking to you again next quarter. You all have a good afternoon and good weekend.

[Operator:]

Ladies and gentlemen, thank you for your participation on today's conference. This does conclude our program, and we may all disconnect. Everybody, have a wonderful day.