Penn Virginia Corporation
Q2 2018 Earnings Call Transcript

Published: 8 Aug 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia's Second Quarter 2018, Earnings Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct the question-and-answer session and instructions will follow at that time. [Operator Instructions] And as a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference Mr. John Brooks, President and CEO. Sir, you may begin.

[John Brooks:]

Thank you, Sandra, and good morning, everyone. We appreciate your participation in today's call. I'm joined this morning by Steve Hartman, our Chief Financial Officer; Ben Mathis, our recently promoted Senior Vice President of Operations and Engineering; and Clay Jeansonne, our Director of Investor Relations. 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. 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 information in risk factors in our most recent Annual Report on Form 10-K and other SEC filings. 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. Before get started with my prepared remarks I want to make sure you saw the press release we issued on July 23 of this year regarding the company's intention to evaluate strategic alternatives. We do not plan to update you today on the status of the strategic alternatives process, but instead refer you to the press release which can be found on Penn Virginia's website. So let's start on page two with a quick company overview. Penn Virginia completed its transformation into a pure play Eagle Ford shale operator in Gonzales, Lavaca and Dewitt counties in south Texas with the recent sale of our Oklahoma properties. We have approximately 84,000 net acres in the Eagle Ford which is approximately 92% held by production and 99% of which is operated by Penn Virginia. Our estimated drilling inventory at August 3, 2018 was 560 locations gross and 461net. I should point out that this inventory count only reflects the lower Eagle Ford opportunity set. Our goal is to continue refurbishing that inventory through organic lease acquisitions as well as acreage swaps with the adjacent operators. For the first half of 2018 we leased or extended approximately 3,574 net acres. Our product mix in the second quarter was 87% liquids of which 74% was oil. Penn Virginia's oil production receives Louisiana Light Suite pricing or more commonly known as LLS and generates very attractive realized pricing in peer leading EBITDAX margins. We're currently running three rigs and one dedicated frac spread supplemented with a spot frac spread periodically as our drilled but uncompleted inventory bills. Penn Virginia is targeting year-over-year production growth of 120% or more after taking into account the sale of our remaining producing properties in Oklahoma and we are well on our way to achieving that target as evidenced by the second quarter results we issued yesterday afternoon. Now let's move on to page three and take a closer look at the strong operational and financial performance from the second quarter. Our second quarter 2018 production averaged 22,200 barrels of oil equivalent per day, which exceeded the second quarter midpoint of guidance. This represents a 39% increase over first quarter of 2018. Even more importantly, we grew our oil production by 33%, which received the benefit of LLS pricing. Operationally we continue to hit on all cylinders. I'm very pleased to report that our capital efficient XRL well program is progressing nicely. Last quarter we drilled and completed the longest lateral in the company's history the McCreary-Technik 2H, which was drilled to a total measured depth of over 21,000 feet with a completed lateral of more than 9,100 feet. In the second quarter we surpassed that mark by more than 20% drilling and completing the Hawn Holt 19H well to a total measured depth of over 22,000 feet and a completed lateral of more than 11,100 feet. These operational successes are a vital part of the process that demonstrate our organization's ability to deliver these challenging wellbore configurations in order to fully realize the most capital efficient pathway to maximizing the value of completed lateral footage. We're excited about our continued success as we move down dip into our deeper higher pressure acreage which we call Area 2. As we've continued to delineate our Area 2 north acreage, we've now completed and turned in line 13 wells for which we have at least thirty days of production history. Given our continued success in Area 2 north, we have increased our EURs for this area by 8% and I'll touch on this more a little bit later in the discussion. Increased volumes and a continued focus on reducing cost allowed us to post a record low LOE of $4.32 per BOE, which is down approximately 14% compared to the first quarter of this year. Penn Virginia is in an enviable position with all of our Eagle Ford production receiving LLS crude pricing and given that strong LLS pricing during the second quarter our average realized price was $67.89 per barrel, which is essentially what WTI averaged for the quarter. We recorded adjusted direct operating cost of $11.63 per barrel of oil equivalent yielding a strong realized cash operating margin of $43.39 per barrel of oil equivalent, which represents a 9% increase over the first quarter of 2018. Lower cost, strong pricing and increased production allowed us to post impressive financial performance for the second quarter. Adjusted EBITDAX was approximately 76 million for the quarter up more than 50% over the first quarter of 2018 and we are firmly committed to meeting our previously articulated goals for 2018, growing our production by 120% or more adjusted for the recent asset sale, growing within cash flow by fourth quarter and reducing our leverage ratio to 1.5 times are lower by year end. Looking ahead into 2019, we expect to grow production between forty and sixty percent drilling with and cash flow. Moving to page four, I'd like to focus in on certain of the recent wells we have drilled in Area 2, which have been completed using our slick water design. We first tested this design back in 2017 on the Lager pad. In May of '17 we turned the Lager 3H well to sales with an IP rate of 2,511 barrels of oil equivalent per day and a thirty day average of o1.899 barrels of oil equivalent per day. We have higher pressures in the down dip deeper Area 2 acreage and with appropriate choke management or to be more precise pressure drawdown management we have reduced the steep declines typically seen in early times. We followed up the Lager well with the Geo Hunter Pad, which was our second confirmation test of slick water completions in Area 2. The Geo Hunter results like the Lager have been very positive. The two well Geo Hunter Pad had a 24 hour IP of 5,465 barrels of oil equivalent per day and produced a thirty day average IP rate of 3,767 barrels of oil equivalent per day. Our third successful test in Area 2 was our two well Southern Hunter-Amber pad, which had a peak 24 hour IP rate of 5,092 barrels of oil equivalent per day and a thirty day IP rate of 4,018 barrels of oil equivalent per day. The production from his pad is more than 80% oil. The Southern Hunter-Amber pad was a result of forming a PSA or 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 likely otherwise been left in the ground. Our fourth Area 2 test, the three well McCreary-Technik pad, another PSA opportunity recorded a 24 hour IP rate of 5,425 barrels of oil equivalent per day and a thirty day IP rate of 3,843 barrels of oil equivalent per day. The production from this three well pad is approximately 80% oil. Early in the second quarter we brought on yet another PSA pad, our Schacherl-Effenberger two well pad, which had a 24 hour IP rate of 3,073 barrels of oil equivalent per day with 88% of its production crude oil. The thirty day IP for Schacherl-Effenberger pad was 2,117 barrels of oil equivalent per day. And finally, also in the second quarter we turned the sales of the three well Medina pad, which recorded a 24 hour IP of 5,208 barrels of oil equivalent per day with 60% oil. The Medina pad recorded a thirty day IP of 3,827 barrels of oil equivalent per day. The three well Medina pad is actually in Dewitt County and is in the southernmost portion of our leasehold position on the acreage we purchased from Devon last year or what we call Area 2 south. Penn Virginia's working interest in the 13 Area 2 north wells range from 71% to 100%. As you can see we have had some pretty impressive results from our Area 2 drilling program and we're optimistic this trend will continue for the balance of our 2018 plans and into 2019. Looking to the future and beyond, the primary recovery stage of our reserves offset operators are beginning to test pilots of enhanced oil recovery or EOR. Now, you may think of enhanced recovery mostly as water floods or CO2, but EOR also includes natural gas floods. During the primary recovery stage of an Eagle Ford well only a small fraction of the estimated total oil in places recovered during the primary recovery phase leaving behind a significant amount of the original oil in place. As you can see from the map highlighted in red, the EOR pilots are very near and on trend with our contiguous 8,400 net acreage position. We are very excited about what EOR could mean for Penn Virginia in the near future. We estimate that gross original oil under our acreage position could be between 2 billion and 3 billion barrels and to put that in perspective, for every 1% of incremental recovery that could be an additional 30 million gross barrels. We will continue to monitor the results of the offset operators EOR pilots and Penn Virginia plans to be a fast follower and a flying EOR to our acreage position where appropriate. Now turning to page five, let's talk about the drilling results from our Area 2 north wells in aggregate. To date we have drilled and completed thirteen wells in Area 2 north using a slick water completion design for which we have at least thirty days of production history. The graft depicted on page five is a plot of cumulative oil produced versus time. For simplicity and consistency, we've normalized the production rate to a 6,000 foot lateral. The black line is our regional type curve projection for Area 2 north. The dash in blue line with the yellow squares is the actual average production rate over the seven plus months for the thirteen wells for which we have at least thirty days of production. As you can see the average actual production rate for these wells exceeds our original Area 2 North type curve. This is being driven by a combination of factors, first of all in Area 2, we have higher reservoir pressures providing more flow capacity and drive energy. Secondly, we continue to optimize our completions not only with respect to propane loading, but also by focusing on fluid pumped in perforating scheme [ph]. In the second quarter we also conducted trials of some specialty additives such as diverters and nano surfactants that had some non-negligible cost. We intend observe all these wells to determine the various value propositions that each of these completion design elements has to offer, fully cognizant that the returns may not be as obvious in early life but can also manifest their effects over the next few months. As our choke management protocol or actually better termed as drawdown management has demonstrated, sometimes the most significant effects are not realized until three to six months after initial production as our tight curve uplift demonstrates. We're obviously very encouraged by these results and so given this continued exceeding to the type curve we've elected to raise our Area 2 EURs by 8%. Along with that we have decided to shift our focus for the balance of the year to Area 2 with many of those wells also being an XRLs. On page six, we provide details of our drilling inventory breaking it down by Area 1, Area 2 north and Area 2 south as well as by conventional laterals and extended reach laterals or XRLs. This in them count is up to date as of August 3 and reflects our increased estimates for the Area2 north type curve. Based on our current type curves the anticipated rates of return for inventory range from approximately 80% to more than 150% as shown by the columns above the table. The economics for this inventory will reign at $60 WTI oil and $3 gas. Another take away from the slide is that it illustrates the value proposition of drilling, the extended reach laterals or XRLs which is a more capital efficient approach to monetizing our inventory of net treatable lateral feet. Another one of our goals is to continue organic lease acquisitions to replace this inventory that we drill each year and maintain approximately ten years of inventory. Moving to page seven of the presentation, we believe Penn Virginia is one of the oiliest companies in the E&P sector with 74% of our production stream being oil, which overall averages 43 to 45 degree API gravity. The recent move up in oil prices has benefited all producers with WTI hovering around $70 per barrel. Penn Virginia is very fortunate and well positioned so that now the entirety of our oil production is sold into the LLS market, which is currently trading at a significant premium to WTI. During the second quarter WTI averaged $67.91 per barrel. Our realized price was $67.89 per barrel, which is just a couple of pennies below that WTI. As of yesterday LLS is trading at more than a $3 premium to WTI and more than $20 compared to Midland pricing. Turning to page eight, I would like to discuss several of our 2018 highlights and goals and profits we've made to date. We've grown production so far this year by more than 78% and we plan to further increase production by more than 30% in the second half of the year. We are also on track to spend within cash flow in the fourth quarter and believe our leverage ratio will be at the 1.5 times mark or lower by year end. As previously discussed, we have increased our Area 2 north EURs by 8% and are shifting our drilling to this area. A significant amount of that drilling will be on XRLs at year end. This increased activity at year end helps build momentum for strong production growth continuing into 2019. We're currently evaluating running either two or three rig program for 2019. Running a three rig program will maximize production growth for 2019 for Penn Virginia while a two ring program would maximize free cash flow generation. Given these parameters, we expect production to grow between 40% and 60% for next year. We're projected to have one of the highest growth rates in our peer group, just like this year's goal to spend within cash flow by the fourth quarter, we plan to continue to have capital discipline in 2019 and expect to spend within cash flow. Turning to page nine, to set a strong foundation for 2019, we have revised our capital plan for 2018. Given our continued success in Area 2 and the further improved economics that Area 2 north wells can provide, we are shifting our drilling program to focus on this high return area for the balance of the year. Due to Area 2 wells being deeper and higher pressured they cost more, so with this shift in drilling activity to Area 2 and the generally higher cost environment facing the industry, we anticipate a capital program for 2018 of between 390 million and 410 million, 96% of which is anticipated to be directed to Eagle Ford drilling and completion and the balance directed primarily towards facilities, pipelines and land. We expect to drill and turn in line a total of 55 gross, 47 net wells in 2018. As it stands today with our proven ability in drilling longer laterals, we plan to spread 20 XRL wells in the second half of 2018, with 10 of those turned in line by year end and another ten in process of drilling or completing at year end, so there will be some carryover associated with those 10. As illustrated in the chart of the top right in 2017, our average treatable lateral length was 5,250. In the first half of 2018, it was approximately 6,500 feet and for the second half of 2018, we expect that average lateral length to increase to 7,500 feet, which is over 40% longer than the previous year. In total our revived capital plans call for turning in line 16,000 feet of additional net treated lateral feet in 2018, although our well count is essentially flat or lower by one well. Now let me provide you with a little more detail on the increase in our 2018 capital plan and bridge it back to the original CapEx plan. The switch to an increased focus on Area 2, where well costs are a bit higher due to setting a third string of casing will increase our capital requirements for the year by an estimated $32 million. As you're aware, the industry is experiencing cost inflation across the spectrum of services, which we estimate at approximately 5% and that translates to an increase to the capital budget of around 116 million. Finally an additional $12 million of capital was spent on well design changes in the second quarter, some of which I already mentioned and we are currently evaluating the impact of those changes. We still expect to spend within cash flow during the fourth quarter and generate a leverage ratio of 1.5 times or lower by year end. This increase in capital build a strong foundation positioning us for continued significant growth for 2019 as evidenced by the 10 additional Area 2 XRL wells scheduled to be in the process of drilling and completing, but not yet turned in line by year end 2018. Moving on to Slide 10, I'm going to walk you through the Penn Virginia value proposition over the next four slide. We start with production growth. Production growth in 2018 is the heart of the Penn Virginia story. We expect at least 120% production growth in 2018 over 2017 from our development plan after adjusting for the sale of the Oklahoma properties. Our guidance for third quarter of 2018 is 23,500twenty to 24,500 barrels of oil equivalent per day and fourth quarter guidance is 28,500 to 30,500 barrels of oil equivalent per day. That's about a 30% growth in the second half of the year. The end result is full year guidance of 22,000 to 24,00 barrels of oil equivalent per day. These numbers reflect the sale of the Oklahoma properties and that growth leads us to the next slide. Slide 11 is where we show you our adjusted direct cash operating cost on a per barrel of oil equivalent basis. In 2017 we saw $14.41 per barrel of oil equivalent for our adjusted direct operating expenses which is the sum of LOE, GPT, production in ad valorem taxes and cash G&A adjusted for some onetime items which is reconciled in the appendix of the presentation. We've made tremendous progress already in lowering our cash cost to $11.63 per barrel of oil equivalent second quarter. For 2018, thanks to higher working interest. As a result of our recent acquisitions and substantial production growth, we have lowered our adjusted direct cash operating cost per barrel by approximately 19% from the full year average of 2017. Our laser focus on costs are continuing to drive cost down and cash margins up . These lower cost lead to the next slide. Slide 12 shows our realized cash operating margin per barrel of oil equivalent. For full year 2017, we realized a cash operating margin of $27.79 per barrel of oil equivalent. We have greatly benefited from driving our cost lower as well as the premium LLS pricing which gives us realized differentials off of WTI between $0 to $1 and that is reflected in our cash margins. You can really see this in our first and second quarter 2018 realized numbers. Our cash margins per barrel of oil equivalent for the second quarter was $43.39, a 56% increase over the second quarter of 2017. We expect cash operating margin per barrel of oil equivalent to increase throughout the year and the strong cash margins combined with strong production growth lead us to the next slide. Slide thirteen balance sheet improvement. Pro forma for the Hunt and Devon acquisitions we had debt to adjusted EBITDAX ratio of about 2.6 times at year end 2017. We have already seen improvement to our leverage ratio posting a 2.2 times number as of the end of the second quarter and we expect that downward trend to continue throughout the year with a target leverage ratio of 1.5 times by year end 2018. Turning to guidance on page fourteen, we've modified our guidance from the update we provided during our first quarter conference call. Revised guidance reflects the sale of our Oklahoma properties, lower lease operating expenses per BOE, lower G&A expenses per BOE, lower GPT per BOE and lower ad valorem and production taxes. These reductions equate to $1 per BOE reduction in cost going forward. With our production growth and our improving cost structure we see that leverage ratio coming down to about 1.5 times by year end and we expect to be drilling within cash flow by the fourth quarter. Along with the 120% or more anticipated production growth these are our financial goals that we are committed to achieving. So with that plan laid out for you, let's look how we compare to our small to mid-sized E&P peers. The next few slides show data from a range of peers. The data is based on consensus, estimates, peers press releases, filings and presentations. I should note that we are not endorsing or confirming any consensus estimates on the next several sides. Turning to Slide 15, we've projected to have one of the highest growth rates for 2019 compared to that of our peers. As I mentioned this chart is showing consensus estimates for our peers and Penn Virginia. On Slide sixteen, given our high percentage of oil production, lower cost per BOE and LLS pricing, we are projected to have one of the highest EBITDAX per BOE ratios in Penn Virginia's peer group in 2019. Now turning to valuation metrics, let's move on to slide 17. Here we take a look at the multiples of companies for 2019 that operate across different basins. The Permian generally garners the highest trading multiple and the Eagle Ford focused companies on average trade at the lower multiple as shown on the graph on the left. On the chart on the right within the Eagle Ford consensus and for our peers other public data has Penn Virginia is trading at one of the lowest multiples for 2019 within that group of companies. With the growth I've laid out for you, the low cost structure and very strong cash margins, we believe that Penn Virginia provides an attractive valuation. So on slide 18, what is Penn Virginia's value proposition. We are a pure play Eagle Ford company with a large de-risk contiguous acreage position. We are 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 geographically to take advantage of Louisiana Light Suit premium prices. We are committed to financial discipline with a well-defined plan to get leverage down to 1.5 times by year end and drilling within cash flow. We are protecting that cash flow along the way with hedges and finally we have growth potential. If you take away anything from his presentation you should take away that we are growing rapidly. We are targeting production growth of at least 120% for 2018 and 40% to 60% in 2018. We have a multi-year inventory of drilling locations with robust economics especially with the growing inventory of XRLs in Area 2 as well as an Area 1 and the future potential that EOR may have for Penn Virginia. And with that, Sandra, I think we can go to the Q&A portion of the call.

[Operator:]

Thank you [Operator Instructions]. And our first question comes from the line of Neal Dingmann with SunTrust. Your line is now open.

[Neal Dingmann:]

Good morning, John. Thanks for the details. John, my first question is more just kind of on your most recent guide to boost in CapEx , I'm just wondering what you do in the board sort of the thought process that went behind that. It seems to me to make sense, but just wondering if you could talk a little bit more about that given the growth and sort of balance sheet et cetera.

[John Brooks:]

Well, we just saw some great well result in area two with superior returns and we wanted to focus our drilling program in that part of our acreage. So obviously those cost a little bit more, but they generate higher returns. If you look at it in terms of net turned in line three lateral [ph] feet, we're actually going to add 16000 feet to our completed laterals by the end of '18 by drilling one last well. So it really goes to the capital efficient part of the development program in the highest return area where we're drilling. There's going to be 10 wells that will be in progress by the end of the year in various stages of drilling and completion that we will expend funds for, but we won't have them turned in line. So the significant part of that will be some carryover capital, while the production will be carry-over in 2019 but the capital to be spent in 2018.

[Neal Dingmann:]

Good detail. And then, John, it's my follow-up, so at least in the way you are just saying on those 10 wells or as you look at early '19, how different - it seems like the market seems hyper-focused on how much sort of oily versus gassy growth you have, could you just talk about where you're going to be putting things and how you see sort of that playing out?

[John Brooks:]

I think we're still planning on being in the mid70's, 4% oil that bounces around from 74. I think we saw something at 76 in one quarter this year, but that's where we think it's going to land.

[Neal Dingmann:]

How different is two versus one just when you think about from the gas perspective. I know Steve was talking about it, but just to hear if you can reiterate that as well?

[John Brooks:]

Well, DORs in area one are quite a bit less than area two. So in the most portion it will be close to that 200 DOR. It gets down to maybe a 1000 bases at the deepest and then once we get into area two, it'll scale up from 1000 all the way down into the area two south of around 5000.

[Neal Dingmann:]

Very good. Thanks, John.

[Operator:]

Thank you. And our next question comes from the line of Brian Corales with Johnson Rice. Your line is now open.

[Brian Corales:]

Good morning guys.

[John Brooks:]

Good morning.

[Brian Corales:]

I want to hit on just '19 to start. I know it sounds like you're looking at a two or a three-rig program. Is commodity price the main driver? Can you maybe - what's the main things to determine what you're going to - your activity level next year?

[John Brooks:]

Yeah. Commodity price is a big driver. The other driver is trying to balance production growth with free cash flow generation. We hear a lot of concern from our investors about both of those issues. So we haven't made a decision for '19. So we're just putting the two and three-rig case out there showing a range of growth and one of the favors [ph] free cash flow generation over production growth and so we'll just have to see how the rest of the year goes and how commodity prices go and make those determinations at a later point.

[Brian Corales:]

Okay. That's helpful. And then the EOR, I found that was a good math you had on your presentation. It shows how close those projects are. Is this something - you said you'll be a fast follower and you are closely watching, but is this something you want to test to try to get value from or can you maybe expand on that?

[John Brooks:]

Absolutely. There's a lot of technical challenges and hurdles to implementing it. We're probably not going to be out in front of the pack leading that, but trying to observe best practices and come in a different part of the learning curve, but the upside is a potential game changer for us and for anybody with acreage that falls on trend where the EOR works, during your primary production phase of the life of these wells, you're leaving most of the oil behind. So if you can come in for a small fraction of your original drilling and completion capital and inject gas in an existing well and can recover a significant percentage of what you did on primary, through a secondary or tertiary process, while the economics of that are pretty compelling. So the best place to look for oil is where you've already found it. We've already found it. We know what the oil in place is with a pretty degree of certainty and we just need to find a way to get out of the ground and most economically possible.

[Brian Corales:]

Can you estimate on when you try to test it?

[John Brooks:]

We would hope to have a pilot initiative probably by mid to late 2019.

[Brian Corales:]

Okay. Great, guys. Thank you.

[Operator:]

Thank you. And our next question comes from the line of Jeff Graham [ph] with Northern Capital. Your line is now open.

[Unidentified Analyst:]

Hey, John.

[John Brooks:]

Yes.

[Unidentified Analyst:]

The question just kind of building on brain blast [ph] topic here on the EOR. Could you give us a ballpark sense understanding kind of what capital costs would be associated with the power project? What would that look like for you? And just generally I guess kind of land discussion aside, should we think about geologically if it works for EOG and the pilot looks good that it's pretty applicable across your footprint or is it just technically not going to be feasible in certain parts of your footprint for whatever reason?

[John Brooks:]

Well, there's a lot of questions there that we're not going to have all the answers to. I think the most important factor based on what we've been able to glean from our offsite operators releases and other reconnoitering of the developing play is that the PVT of the oil plays a big part and the ability to mobilize our mix, the injecting gas with the oil left behind to get it moving to surface is a big part of that. So technical questions remain on the PVT portion of the oil and gas left in the reservoir. Secondly, you want it to be contained underground. So if you are in a highly faltered up area, you probably have a different set of challenges. For the most part the bulk of our acreage is fairly quiet. Structurally we don't have a whole lot of faulting in the bulk of our acreage, although some of our acreages faltered up. So the two things that I mentioned so far is the PVT, the oil and fluid characteristics in the subsurface containment and being structurally quiet from a geologic standpoint. Thirdly, you want to have a high working interest percentage. There's some commercial issues you will face if you want to turn a good producing oil well into an injection well. So you've got to get the concurrence of your working interest partners. And so having a high working interest percentage helps achieve that and that's another thing we've got. So having a big blocky acreage with a high working interest on trend where it appears to be working for other people, I think it bodes well for us.

[Unidentified Analyst:]

Great. That's really helpful. I appreciate that. And for my follow-up, I'm curious on your longer laterals you guys are increasingly working on, John, are you seeing any difference on a production per foot basis or on an EOR per foot basis, just kind of curious how that's kind of changing things at all understanding I'm sure you're still getting some cost efficiencies from the longer laterals as well?

[John Brooks:]

Well, actually I think if you look at the fact that we changed our type by curve 8% on Page 5, you can see what we're maintaining. We're maintaining the - our anticipated economics and actually starting to increase it. As far as on a per foot basis that scales up just as well. This is all on a 6000 foot lateral. If I plodded up on 7000 or 7500, it looks even better. But on a per foot basis it all seems to hold together very well. The choke management is a big part of that, especially as we get deeper in some of these wells as they traverse two miles of the subsurface they will go from different parts of the reservoir that will see higher pressures at the toe-end of the lateral to the heel-end. So your production and drawdown management becomes even more critical. So you don't want to overproduce that in the early life and that helps you let the deeper part of the well produce early with the shallower parts of the lateral kicking in a little bit later and that's another characteristic of these longer laterals that are helping to sustain and arrest those early-time declines.

[Unidentified Analyst:]

All right. I appreciate those comments and the time, guys. Thanks.

[Operator:]

Thank you. And our next question comes from the line of Brian Steck with Mangrove Partners. Your line is now open.

[Brian Steck:]

Hey, guys. Thanks for a good quarter and particularly thanks for your comments regarding 2019 and the production profile and the intended rig program or a range of rig programs. Related to that, I'm just thinking about the kind of growth that you can develop off of the two-rig program or a three-rig program and I wondered if you could comment a little bit about it. I'd like to better understand what your expectations are as it relates to rig productivity and how that's changed since you put the 2018 plan up together?

[John Brooks:]

Well, we're not modeling any increased rig productivity as it stands. We're modeling what we're seeing. So to the extent that we continue to gain drilling completion and other operational efficiencies, things certainly could get better. But we're not baking in any improved efficiencies. I'm not sure if that answers your question or not, but the two-rig case is going to probably generate or basically will maximize free cash flow generation and the three-rig case will maximize production growth and really that's kind of the extent of the analysis for 2019 we're really prepared to release at this time.

[Brian Steck:]

Got it. And I know it's early to say the two to three-rig plan on a gross basis. Can you give me a sense of what that would look like on a net basis, the range? And if that's not handy, we can go with that off on?

[John Brooks:]

Are you talking - can you repeat the question, Brian?

[Brian Steck:]

If it's a two to three-rig gross program, I'm just curious as to what that looks like in terms of net rigs.

[John Brooks:]

Okay. I got you. Well, our average working interest is about 85% to 87% across the asset. I think if you get down in area two, it tends to be a little higher. So it would probably be skewed towards that higher - the higher working interest. Does that help you there?

[Brian Steck:]

Yeah, I guess. And your last question, with regard to your XRL inventory, how many - what is the current XRL inventory in terms of PSAs that you already have in place and how many additional XRLs are kind of in progress from a PSA perspective?

[John Brooks:]

Well, the inventory slide on Page 6 really speaks to the XRLs that we have - already have executed PSAs for or close to being that. So there could be more, but right now that's where we stand. We want to - there's some pending acreage swaps that we're doing that can make a lot of these numbers change and hopefully we have some news to report on that in the third quarter and then they're not insignificant, but probably the biggest change that we will have to move those forward with some of the acreage swaps that we have pending.

[Brian Steck:]

Great. That's helpful. And thanks again and congratulations on a good quarter.

[John Brooks:]

Thanks, Brian.

[Operator:]

Thank you. And our next question comes from the line of Wayne Cooperman with Cobalt Capital. Your line is now open.

[Wayne Cooperman:]

It's probably mid night here. Just for next year you guys said you have some pretty - some guidance for 50% growth. I think you said that your - the composition between oil and gas should be pretty similar to where you are now. I just want to confirm that. And also you've seen a nice decline in cost as you grow 50%. Do you think we'll continue to see some benefits on the cost side? And lastly if I just take that 50% growth and I kind of know where you're going to start and know where you're going to end [indiscernible] so bold as to model out 2020, would we see sort of a growth from the exit rate of '19 one into '20, would that not be unreasonable?

[John Brooks:]

Well, let me tackle the first two. Yeah, we anticipate our percent oil to stay in the mid 70's. On cost, we're not really baking in anticipated cost reductions. We're letting the denominator drive that at this point. That being said, we would expect to continue gains on the cost front. A couple of three items that I've already talked about it. It gives me the chance to talk about our LOE reduction and what we've been doing in that regard. Number one, we completed a smart gas-lift intermediate [ph] project that we started a little over a year ago and smart gas-lift intermediates are basically a way to control your gas injection volumes to minimize the amount of gas you inject, while maximizing fluid lift. So what we've seen is our gas lift costs come down successfully because of the implementation of that project field wide. It's the largest implementation of Weatherford smart gas-lift intermediates that they've put in place and we're happy with the results. The other big component in our LOE is salt water disposal. We produce a significant amount of water along with our oil and to the extent that we can dispose of that in our own disposal well preferably via a disposal gathering system that we build out in a logical and progressive fashion. When we're hauling water to a third-party versus injecting it into our own, when we inject it into our own, we're going to save about a buck a quarter a barrel. So to the extent we can grow that that helps as well. The other component of our costs that we give a lot of attention to is on the chemical side and we've made some recent changes there that we're looking forward to seeing those in the second half of the year. So none of those things have been baked into the LOE guidance that we've issued. Those are all ongoing projects that we think will have a good benefit. But as it stands, we are mostly forecasting per well LOE growth consistent with what we've observed. Your third question? I'm sorry.

[Wayne Cooperman:]

Just can't take it down by 2020, if I took here kind of '19 exit rate is that - or is kind of a good starting point, the assessment growth for 2020?

[John Brooks:]

I don't think we're ready to issue 2020guidance at this point,'19 is probably far in the future I can see over the horizon right now.

[Wayne Cooperman:]

Okay. And [indiscernible] before, but as long as I got you. We're starting to see some guys take some money and spending out of the Permian for, given the differentials, is some of that equipment heading your way and maybe that will help out on some of the inflationary cost pressures? Are you seeing any evidence of that?

[John Brooks:]

It could. The challenge for us, though, as we go to area two is that we're dealing with a higher pressure environment than what you're going to see in the Permian. So we're more likely to benefit from equipment being released from the Haynesville than we will be from the Permian on the completion side.

[Wayne Cooperman:]

All right. I know you guys are doing a pretty good job. And then I assume when you got something to say on the strategic alternatives, we'll hear about it and until then we won't?

[John Brooks:]

Correct.

[Wayne Cooperman:]

Okay. Thanks.

[Operator:]

Thank you. And our next question comes from the line of David Snow with Energy Equity. Your line is now open.

[David Snow:]

Yeah, I believe all my questions have been answered for the moment. Thank you very much.

[John Brooks:]

Thank you.

[Operator:]

Thank you.[Operator Instructions] our next question comes from the line of Jeff Davis [ph]. Your line is now open.

[Unidentified Analyst:]

Congrats on the quarter and thanks. Just kind of curious how you reconcile the EUR program for you guys potentially kind of starting up mid '19 with being in the midst of this strategic review now, how you kind of - if there was any type of sale, how you ensure that you would get value for that. How you think about that?

[John Brooks:]

Well, you said EUR. I assume you meant EOR?

[Unidentified Analyst:]

EOR, excuse me EOR, yeah.

[John Brooks:]

Well, we still got to run the business. Even though we have a strategic alternative process that's been announced and we're going to continue to run the business and what's best for shareholders. That includes drilling and completing the wells and finding ways to maximize value if EOR is a viable opportunity for that. So we've got an earth model project underway that we've had underway for this year that sets the stage for the EOR where we can get a three dimensional sub-surface picture that not only helps on EOR, it helps define the targets for the upper Eagle Ford and the upper Eagle Ford - none of that inventory which is reflected in our current inventory. But those modeling projects should set the stage for a good framework for implementing any EOR program if indeed we determine to be applicable here. So we're going to continue to add maximum value wherever we can if it's through drilling XRLs, if it's through EOR, all of the options available to us.

[Unidentified Analyst:]

Okay and specific to the strategic review and I'm sure you don't want to say too much on that, but when you think of obviously a couple of options where you get bar or you go buy assets or do nothing I guess. When you think about the option of potentially buying assets, how do you think about kind of using cash and potentially over the short-term increasing leverage versus potentially doing a larger deal using equity just kind of optically the equity does look undervalued, how you would think about potentially using equity for a larger deal just to effectively create better liquidity, create more coverage, more kind of interest in the story so to speak, when the stock is trading less than a 100,000 shares a day, a few days of last week, ideal to kind of improve liquidity and improve interest in the story, I think would be helpful?

[John Brooks:]

I'll go back to my opening remarks where we would refer you to our website to see the press release that we issued on the strategic alternatives process and not really comment beyond that.

[Unidentified Analyst:]

Yeah, that's very [indiscernible] and I appreciate it. Thank you.

[Operator:]

Thank you and I'm showing no further questions at this time. So I'd like to return the call to Mr. John Brooks for any closing remarks.

[John Brooks:]

Thanks, Sandra and thanks everybody for participating in the call. I look forward to talking to you next quarter. And once again thanks for your time and interest in Penn Virginia. Thank you.

[Operator:]

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