Penn Virginia Corporation
Q3 2017 Earnings Call Transcript

Published: 12 Nov 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation webcast. [Operator Instructions] As a reminder, today's conference is being recorded. I would now like to introduce your host for today's conference call, Mr. John Brooks. You may begin, sir.

[John Brooks:]

Thank you, Kevin, 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 new Vice President of Operations, who joined Penn Virginia after several years in a leadership role at Statoil, helping them develop their onshore conventional assets. And prior to that, he had a distinguished career with Occidental and Unocal and he received his Bachelor of Science in Petroleum Engineering from Texas A&M in 1992. Prior to getting started, I'd like to remind you of 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 and quarterly reports on Form 10-Q filed with the Securities and Exchange Commission. Cautionary language is also included on Slide 1 of our presentation, which is available on our website. We will use the 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, where we provide a brief overview of where Penn Virginia is today as a company. We are a pure play independent oil and gas company focused on the South Texas Eagle Ford shale. We hold approximately 76,000 core net acres, much of which is contiguous and focused in Gonzales, Lavaca and DeWitt counties and is 92% held by production. Given that much of our acreage lies in the volatile oil window of the oil Eagle Ford - of the Eagle Ford. We have an exceptional inventory of oil-related drilling opportunities. With that exposure to oil projects, our production mix is heavily weighted to liquids with 72% oil and 15% NGLs with a combined production mix of approximately 87% liquids, one of the highest in our peer group. This allows us to generate high EBITDAX margins per BOE produced. And this high concentration of liquids production, we believe, sets us apart from many of our independent oil and gas company peers. Most of our acreage position is operated by Penn Virginia, which allows us to control the pace of activity and the drilling schedule. We operate more than 360 producing Eagle Ford wells in South Texas and have working interest in another 42 Eagle Ford wells operated by others. Along with our producing wells, we also have a deep inventory of more than 600 highly economic locations, 88% of which we operate. We're pleased to report that even with the impact of Hurricane Harvey, we hit the midpoint of our published guidance for the third quarter at 864,000 barrels of oil equivalent or on an approximate daily basis of 9,400 BOE per day. We closed our previously mentioned acquisition on the last day of the quarter, and because of this, we do not recognize any benefits from the transaction during the third quarter. However, to provide you a snapshot where we stand today on production, we averaged approximately 12,200 BOE per day for October. We expect Penn Virginia's production rate to continue to climb through the balance of the year as we bring on additional pads that are currently drilling and completing. Turning to Page 3. We highlight several reasons. We're so excited about where Penn Virginia is today and where we will be in 2018. Yesterday, we raised our production guidance for 2018 and now are expecting 100% production growth year-over-year. 75% of that production is oil, which receives premium Louisiana light sweep pricing. Combined with NGLs, our production is 87% liquids. We believe this is one of the highest growth rates in our industry. This significant organic growth will be accomplished by utilizing a three-rig program throughout 2018, contingent upon commodity prices. We plan on drilling more than 70 wells over the next five quarters with this three-rig program. Several of these wells will be extended laterals reaching lengths of 8,000 feet or longer. Beyond the existing inventory we hold, we see additional significant upside to our inventory locations from the Upper Eagle Ford in Austin Chalk formations. We still need to do more work to delineate these horizons, and we plan to do that next year. As I previously mentioned, we have an outstanding portfolio of opportunities, which is heavily weighted to oil. This leverages Penn Virginia performance to the current rising oil price environment. But even at $50 oil, we are generating robust EBITDAX per BOE margins. Although we anticipate growing 100% year-over-year, we are expecting to be cash flow neutral in the fourth quarter of 2018, and Penn Virginia is committed to maintaining a solid balance sheet with ample liquidity. Turning to Page 4. We highlight some of our third quarter operational accomplishments. The biggest catalyst for future growth this quarter was the September 29 closing in the previously announced acquisition of Eagle Ford assets. This transaction increased our net acreage and production by approximately 30%, but more importantly, provided us with some great inventory of extended laterals. As you know, Hurricane Harvey caused a significant amount of damage to the South Texas region, but Penn Virginia was still able to achieve the midpoint of our production guidance. Even though we were able to recover our production rather quickly after the hurricane, we did experience significant disruption to our drilling and completion operations. And I'll discuss the impact in greater detail a little bit later. We were very active during the quarter, drilling and turning to sales seven gross in five net wells. One of those wells was the Chicken Hawk 5H. This well was completed in a new landing zone in the lower Eagle Ford, which could further optimize recoveries. We have more work to do to determine the ultimate potential of this new landing zone, but we're encouraged by the early results that we've observed so far. Turning to Page 5, we've illustrated this, showing two different stack and staggered configurations, we tested with the Chicken Hawk and Jake Berger pads. The first stack and stagger configuration, which we tested with the Chicken Hawk 5H, paired a lateral drilled in an upper bench of the lower Eagle Ford with a lateral drilled in our traditional lower Eagle Ford landing zone. The Chicken Hawk 5H's initial production is above our type curve, normalized to a per-foot basis. The other stack and stagger configuration paired two upper Eagle Ford laterals, the Chicken Hawk 2H in the Jake Berger 2H with adjacent lower Eagle Ford laterals. These two upper Eagle Ford wells were also our first slickwater completions in the upper Eagle Ford, although they have not yet exhibited much material uplift as compared to previous hybrid completions. We think the upper Eagle Ford in the lower Austin Chalk present a large potential opportunity set for upside across our assets. While we have yet to test the Austin Chalk, we now have 37 tests of the upper Eagle Ford across our acreage, which has exhibited a wide range of productivity. The challenge for us is to delineate the sweet spots for these two intervals. To that end, in 2018, we anticipate obtaining additional subsurface data through enhanced logging raw drilling and/or by drilling and logging additional pilot holes. The main takeaway here is that we tested a secondary landing zone in the lower Eagle Ford that combined with continued devaluation of the upper Eagle Ford and lower Austin Chalk could further optimize recoveries across the entire stratigraphic interval. Page 6 is a map showing our fourth quarter 2017 activity and preliminary 2018 development plan, which is based on a three-rig program. We anticipate drilling 37 to 42 gross wells in Area 1 over the next five quarters at working interest ranging from 45% to 50%. We anticipate drilling 30 to 35 gross wells in Area 2 over the next five quarters at working interest ranging from 60% to 98%. We have one rig currently drilling on the two-well Geo Hunter pad in Area 2. We have another rig drilling on the two-well Furrh pad in Area 1, and we are currently moving in the third rig on the two-well Schacherl-Effenberger pad, which is expected to spud in the next few days. The Rhino Hunter pad has four wells that have been fracked and commenced flowback in the last 36 hours. The Oryx Hunter is a three-well pad where frac operations are currently underway. Looking forward to ensure we have the right equipment and personnel to execute on our 2018 strategic plan, to reiterate, we have recently contracted three new flex rigs along with the addition of some key operations personnel, including a new VP of Operations, who I introduced earlier. We have taken proactive steps to strengthen our operating team and improve the quality of our drilling rigs to position the company for an active and successful drilling program in 2018. On Page 7, our keys to success in 2018 largely lie in implementing solutions to the challenges presented to us in the third quarter. First, while Hurricane Harvey's impact on our producing operations was largely mitigated to our team's collective actions, timing effects were more pronounced on the drilling and completion operations. Drilling operations for two rigs were disrupted. Frac operations were disrupted. And coil tubing drill at operations were disrupted. And the Chicken Hawk wells were not drilled out for over 30 days, moving large volumes of frac water static on the formation for an extended period of time. In the aggregate, these factors all delayed operations and pushed back capital spending as well as new production. Secondly, mechanical issues with the previously contracted drilling rigs further exacerbated these delays by lengthening the drilling segment of our overall cycle time and also resulted in several instances of shorter laterals being drilled in case than originally planned. Those two rigs have now been released and replaced with top-tier H&P flex rigs, with the third previously mentioned rig brought in to get us caught up. And continuing throughout 2018, if commodity prices are supportive. We are already realizing improved operational efficiencies with the new flex rig as our latest three-stream well. The Geo Hunter 3H was drilled and cased 4.5 days faster than the Lager 3H, our previous three-stream well in Area 2, drilled to an equivalent depth. Thirdly, we came out of restructuring last year with a much smaller overall employee base. And more specifically, a technical team significantly reduced in number, better suited for operating one rig while strategic options were evaluated. Consistent with our current growth strategy, we've recently increased our technical team headcount as well as overall organizational capability as we continue to rightsize our G&A to pursue our returns focused development of our considerable inventory of low risk, oil-rated drilling locations. In short, we're very excited about deploying top-tier equipment and technology along with an expanded technical team with proven engineering talent to execute 2018's drilling program. And on Page 8 is a table summarizing our lower Eagle Ford drilling inventory segregated by Area 1, Area 2 North and Area 2 South. Additionally, we've listed the inventory for each area by conventional lateral length and by extended reach laterals, or XRLs. As you can see, we have an attractive inventory of oil-related development drilling opportunities. And as we continue to optimize our overall plan of development, this subject is subject to change as we focus on improving capital efficiencies and rates of return by forming more production sharing agreements, which could allow us to drill more extended reach laterals and fewer wells with shorter laterals. For the financial highlights, I'll turn it over to Steve Hartman.

[Steven Hartman:]

Thanks, John. I'll start with an overview of our third quarter financials on Slide 9. Total product revenues for the quarter were $34.3 million or $39.72 per BOE, with 87% of our product revenues derived from oil sales. This was a slight decrease compared to the second quarter, primarily driven by a 7% decline in volume. On a per barrel basis, our realized price was slightly higher than the previous quarter driven by higher commodity prices. Total direct operating expenses were $15.3 million for the quarter or $17.66 per BOE compared with $12.9 million or $13.96 per BOE in the prior quarter. The primary driver for the increase was higher cash G&A expense, which was $3.1 million higher than in the prior quarter. Of that $3.1 million increase, $1.5 million were onetime transaction costs related to the acquisition we just closed in the third quarter. The remainder was primarily related to increase staffing to support the 2018 drilling program. With the acquisition transaction cost adjusted out, our cash G&A expense was $4.4 million for the quarter. Adjusted cash G&A as reconciled in the Appendix of the presentation. We reported $5.9 million net loss for the quarter or $0.40 per diluted share compared to net income of $21.3 million or $1.42 per diluted share in the prior quarter. The primary driver of the loss is a $12.3 million noncash charge in derivatives expense, which reflects the change in the value of our derivatives portfolio due to higher commodity prices. This compares to an $11.1 million gain in derivatives in the prior quarter when commodity prices were lower. Our adjusted net income, which adjusts for the noncash change in value of the derivatives and the acquisition transaction costs of G&A, is $8.6 million or $0.57 per diluted share. Adjusted net income is reconciled on the Appendix of the presentation. And finally, Adjusted EBITDAX was $21.5 million or $24.85 per BOE compared with $23.1 million or $25.02 per BOE in the prior quarter. This represents a 63% cash margin off of our realized price. Adjusted EBITDAX includes cash settlements from derivatives. We received $788,000 or $0.91 per BOE in hedge settlements during the quarter. It also excludes the $1.5 million or $1.74 per BOE in the acquisition transaction cost I mentioned. Adjusted EBITDAX is also reconciled in the Appendix of the presentation. On the next slide, Slide 10, we update our 2017 and 2018 guidance. This guidance assumes we'll keep the third rig active through the end of 2018. We currently expect fourth quarter 2017 production to be 13,300 to 14,000 BOE per day. This is about 8% lower than our previous guidance and reflects the delays in the drilling program we experienced in the third quarter. With the third rig coming on, we do expect to exit fourth quarter 2017 within our previously provided exit rate guidance range of 14,600 to 15,200 BOE per day. We're just delayed a little as we catch up the drilling program to where we had originally planned. For the full year of 2017, we are projecting production of 10,400 to 11,000 BOE per day. Looking forward to 2018, we are expecting a full year production rate of 20,500 to 22,500 BOE per day. We expect our fourth quarter production at year-end to be around 23,000 to 25,000 BOE per day. This fourth quarter 2018 guidance is about 10% higher than our previously provided guidance. At the midpoint of guidance, we expect 100% production growth rate for 2018 over 2017 and a 75% production growth rate for fourth quarter '18 over fourth quarter '17. Moving down the slide, we are increasing our realized price differentials guidance by about $1 to reflect better realizations at LLS market. We expect natural gas differentials to be about the same. We expect our LOE will be in the range of $4.75 to $5.25 per BOE, and this is lower on a per barrel basis than our current LOE driven by the higher volume. We do not expect a change in our gathering, processing and transportation expense or ad valorem in production taxes. We expect our cash G&A expense to be $3.20 to $3.50 per BOE with the decline on a per barrel basis from the third quarter again being driven by the higher volume. That would put our total direct operating expenses for the fourth quarter of 2017 at around $14 per BOE at the midpoint of guidance and right around $11 per BOE if you exclude ad valorem in production taxes. For capital expenditures, we're expecting $45 million to $65 million for the fourth quarter of '17 and $120 million to $140 million for the full year of 2017. The full year guidance is $20 million lower than our previous guidance mostly due to drilling delays. We expect this capital will carry into the 2018 program. For the full year of 2018, assuming we keep the third rig active, we expect capital expenditures to be $255 million to $295 million with 95% of that being directed to drilling and completions. This is about $25 million higher over the previous guidance, which was based on a two-rig program, giving credit for the $20 million that was under spent in 2017 being carried into 2018. On Slide 11, on the right, we highlight our liquidity position. At the end of the quarter, we had $57 million drawn on our credit facility, $800,000 outstanding in issued letters of credit and $7.5 million in cash, giving us liquidity of approximately $187 million. Currently, we have $61 million drawn on the credit facility, which gives us about $180 million of liquidity. We also increased our borrowing base during the quarter to $237.5 million, up 18% from the previous $200 million borrowing base in conjunction with the acquisition closing and our fall borrowing base redetermination. And finally, on this slide, we want to emphasize that we aim to maintain financial discipline by targeting net debt to EBITDAX of 1.5x or lower and spending predominantly within cash flow over the long run. We expect to achieve both of these goals by the fourth quarter of 2018. Our leverage ratio as of the end of the third quarter 2017 was 2.4x. On the next slide, Slide 12, we highlight our hedge position. You can see we've added significantly to our hedges since the last quarter. We also started layering in some LLS-based oil hedges into the portfolio in addition to our traditional WTI oil hedges. Most of our sales, as John mentioned, are at the LLS market. So, these LLS hedges are actually better at hedging our true commodity price risk exposure than WTI. Going forward though, I expect that we would be layering in both in a balanced manner depending on the relative pricing. For 2018, we just have under 5,500 barrels of oil per day hedged at WTI pricing of $49.30 and 1,500 barrels per day hedged at LLS pricing of $51.97 for a total of about 7,000 barrels per oil per day hedged for 2018. That's about 45% of our anticipated oil production for the year at the midpoint of guidance. And with that, operator, we can go to Q&A.

[Operator:]

[Operator Instructions]. Our first question comes from Jeff Grampp with Northland Capital.

[Jeffrey Grampp:]

I wanted to start just, I guess, from a high level, get your thoughts on how we should be thinking about 2018 development with the three rigs you guys are looking at now and maybe referencing kind of Slide 8 and appreciate the breakout of the inventory. Is there a way to think about how you guys are kind of going between Area 1 and some of the legacy Area 2 versus the Devon acreage and how we should be thinking about your implementation with more of these extended reach laterals you guys are working on?

[John Brooks:]

Yes. By and large, those rigs will be evenly split among Area 1 and Area 2. I think the plan would be to start primarily in - with regards to the Devon acreage, start up in Area 2 in the north and work our way to the south. I believe we do have a handful of Area 2 South laterals to be drilled early in the year there on a unit that doesn't lend itself to a PSA. So, there'll probably be more of the 6,000-foot variety or more. But we're currently drilling two right now that Devon had roughly a 50% interest in our Geo Hunter. So those will come on right away in here at the end of the year and going into the first quarter. Those will be followed by a couple of other locations that are on our legacy acreage that Devon had high working interest. We've got some PSA forms in our Southern Amber unit, which are also longer laterals that will be on the heels of that. So, we're still forming the PSAs down in the south, and we anticipate having more of those turned around in the second half of next year. So, I don't have a lot of granularity on the second half of next year by pad and actual lateral lengths, other than to say that's when the bulk of those really start showing up on the drilling program.

[Jeffrey Grampp:]

Okay, perfect. No, that's real helpful. And then on the Chicken Hawk 5H well, you guys referenced with the different landing zone. Can you maybe expand a bit upon how that impacts your development going forward? Is this a new zone you guys might target more frequently going forward in a down-spacing pattern? And just generally, how applicable you see that result being towards the rest of your acreage?

[John Brooks:]

Well, I mean, it is a definitely encouraging data point, but it is just one data point. We've got a few other landing zones that are in the Lower Eagle Ford that we would also like to test. In this part of our acreage, that was the one that made the most sense. And time will tell whether it is a meaningful ad on inventory for down-spacing or is it just something that further optimizes recoveries. But I do think it really allows for potentially a more robust co-development pattern for the lower Eagle Ford.

[Jeffrey Grampp:]

Okay, great. And if I could sneak one more, just on the new rigs you guys have. Can you maybe comment, John, on how that maybe impacts your cycle time? It may sound like these are maybe a little bit newer and quicker with some bells and whistles on them and if that maybe reflected in kind of the well count we're looking at in '18 or you continue to see some efficiencies in reduction drilling days that we could see some improvements there as well.

[John Brooks:]

Yes. The flex rigs are certainly higher capability, and we can expect those cycle times on the drilling side to compress over time. However, as we got it modeled, it's a little bit more conservative than a technical limits type of well, which we're striving to get to. So, I mean, we could definitely see more wells drilled early on. And if that's the case, then we have to start reviewing the necessity of that third rig at some point, if two wells - if two rigs can get it down as fast as we think they can.

[Operator:]

Our next question comes from Richard Tullis with Capital One Securities.

[Richard Tullis:]

John, as you currently view the Eagle Ford potential in the acreage following the Chicken Hawk and the upper Eagle Ford, I mean, the Jake Berger upper Eagle Ford results included in the release, how much did the prior rigs and just Hurricane Harvey starts and stops contribute to the results do you think? And do you kind of give it another shot real soon with the new rigs and maybe a different completion methodology?

[John Brooks:]

Yes, I mean, I don't think the rocks been condemned at all. I think the biggest impact that we had with the rigs was twofold. Number one, an expansion of our overall drilling cycles in terms of - from our spud to rig release. And secondly, the problems that ended up resulted in shorter laterals. So, we ended up leaving some rock and oil behind. And if you don't get the full lateral drill, then your results are going to suffer and that's what we've seen. I think the higher mechanical reliability of the rigs we have right now will go to a great way to solving that. In terms of the upper Eagle Ford, I think that - we still like the upper Eagle Ford. It's a different rock than the lower Eagle Ford, and we've got now 37 wells that have all been productive to some extent, some outstanding and some more of this 400 to 500 barrels a day. It may ultimately turn out that what we see in the Chicken Hawk 5H as a second landing zone in the lower Eagle Ford, that may point us towards a co-development model in the lower Eagle Ford and then trying to maybe pair the upper Eagle Ford with the lower Chalk. And that may make more sense because they're similar rock types. So, I think that would probably be the next step. And as we go through '18, gather some more subsurface data through the LWD program and even perhaps another pilot well with some additional logging into our coring to help augment that. We know there's a lot of successful Austin Chalk production in the trend and in our region, we just want to be real judicious about how we go spend those dollars.

[Richard Tullis:]

That's helpful. And a lot of good detail on the - in the slide on Page 8 related to some of the details and the different areas and the different depths. The Chicken Hawk and Jake Berger pads, did you generally already achieve the well results adjusted for lateral foot that you have outlined on Slide 8?

[John Brooks:]

Slide 8, I think, by and large - I think that the - by and large, the Chicken Hawk and Jake Berger pads came in below expectations with the exception of the Chicken Hawk 5, which tested that new landing zone and it actually exceeded the type curve. So that's encouraging there. Like I said, on average, most of those wells had much shorter laterals than they were planned. And you can normalize it per foot. But if you end up with significantly shorter laterals, you're leaving too much rock and oil behind to get your goals.

[Richard Tullis:]

Okay. And just lastly, I know you had the LOE target out there of $5 per barrel or less. Given where we are now, what do you think the time it would be for achieving that level of efficiency?

[John Brooks:]

Well, that $5 of BOE target is really going to be driven mostly by the denominator. Our operating expenses are largely online and in trend with - on trend with expectations. So, the growth in production will be what drives that to what it needs to be.

[Operator:]

[Operator Instructions]. And I'm not showing any further questions at this time.

[John Brooks:]

Well, thanks for joining us, and we look forward to talking with you next time.

[Operator:]

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.