Ranger Oil Corp (ROCC) 2018 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia's second quarter earnings conference call. (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.

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; and 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 the forward-looking statements section of our 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 and EUR, 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 information and risk factors in our most recent annual report on Form 10-K and other SEC filings. Cautionary language is also included on Slide 1 of the presentation, and we will use the presentation to go through today's discussion. Finally, after our prepared remarks, we will answer any questions you may have. Before I 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 2 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 461 net. I should point out that this inventory count only reflects the lower Eagle Ford opportunity set. Our goal is to continue refinishing that inventory through organic lease acquisitions as well as equity swaps with adjacent operators. In the first half of 2018, we leased our 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 Sweet pricing, or more commonly known as LLS, and generates very attractive realized pricing in pure leading EBITDAX margins. We're currently running 3 rigs in 1 dedicated frac spread, supplemented with a spot frac spread periodically as our drilled but uncompleted inventory builds. Penn Virginia is targeting year-over-year production growth of a 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 3 and take a closer look at the strong operational and financial performance for the second quarter. Our second quarter 2018 production averaged 22,200 barrels of oil equivalent per day, which exceeded second quarter midpoint guidance. This represents a 39% increase over first quarter of 2018. Even more importantly, we grew our oil production by 33%, which receives 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 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 to 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 laterally footage. We're excited about our continued success as we move down-dip into our deeper, higher pressured 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 30 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 averaged realized price was $67.89 per barrel, which is essentially what WTI averaged for the quarter. We recorded adjusted direct operating cost of a $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 costs, 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 by production -- growing our production by a 120% or more, adjusted for the recent asset sale, drilling within cash flow by fourth quarter and reducing our leverage ratio to 1.5x or lower by year-end. Looking ahead into 2019, we expect to grow production between 40% and 60% while drilling within cash flow.

Moving to Page 4. I'd like to focus in on certain of the recent wells we have drilled in Area 2, which have been completed using our slickwater 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 30-day average of 1,899 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, pressured 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 slickwater completions in Area 2. The Geo Hunter results, like the Lager, have been very positive. The 2-well Geo Hunter pad had a 24-hour IP of 5,465 barrels of oil equivalent per day and produced a 30-day average IP rate of 3,767 barrels of oil equivalent per day. Our third successful test in Area 2 was our 2-well Southern Hunter Amber pad, which had a peak 24-hour IP rate of 5,092 barrels of oil equivalent per day and a 30-day IP rate of 4,018 barrels of oil equivalent per day. The production from this pad is more than 80% oil. The Southern Hunter Amber pad was a result of forming a PSA or production sharing agreement across 2 units that allowed us to drill 2 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 3-well McCreary-Technik pad, another PSA opportunity, recorded a 24-hour IP rate of 5,425 barrels of oil equivalent per day and a 30-day IP rate of 3,843 barrels of oil equivalent per day. The production from this 3-well pad is approximately 80% oil. Early in the second quarter, we brought on yet another PSA pad, our Schacherl-Effenberger 2-well pad, which added 24-hour IP rate of 3,073 barrels of oil equivalent per day with 88% of its production in crude oil. The 30-day IP for Schacherl-Effenberger pad was 2,117 barrels of oil equivalent per day. And finally, also in the third -- second quarter, we turned to sales the 3-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 30-day IP of 3,827 barrels of oil equivalent per day. The 3-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 a 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 place is recovered during the primary recovery phase, leaving behind a significant amount of 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 84,000 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 into 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 in applying EOR to our acreage position where appropriate.

Now turning to Page 5. Let's talk about the drilling results from our Area 2 North well in aggregate. To date, we have drilled and completed 13 wells in Area 2 North using the slickwater completion design for which we have at least 30 days of production history. The graph depicted on Page 5 is a plot of cumulative oil produced versus the time. For simplicity and consistency, we've normalized the production rate to a 6,000-foot lateral. The black line is our original type curve projection for Area 2 North. The dashed blue line with yellow squares is the actual average production rate over the 7-plus months for the 13 wells for which we have at least 30 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 profit loading but also by focusing on fluid pumped and perforating schemes. In the second quarter, we also conducted trials of some specialty additives such as diverters and nanosurfactants that had some non-negligible costs. We intend to observe all of 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 could also manifest their effects over the next few months.

As our choke management protocol, or actually a better term is drawdown management, has demonstrated, sometimes, the most significant effects are not realized until 3 to 6 months after initial production as our type curve uplift demonstrates. We are obviously very encouraged by these results. And so given this continued exceedance of the type curve, we have elected to raise our Area 2 North 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 XRLs. On Page 6, 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 inventory count is up to date as of August 3 and reflects our increased estimates for the Area 2 North type curve.

Based on our current type curves, the anticipated rates of return for our inventory range from approximately 80% to more than a 150%, as shown by the columns above the table. The economics for this inventory will remain at $60 WTI oil and $3 gas. Another takeaway from this slide is that it illustrates the value proposition of drilling the extended reach laterals or XRLs, which is the more capital efficient approach to monetizing our inventory of a net treatable lateral fee. Another one of our goals is to continue organic lease acquisitions to replace this inventory that we drill each year and maintain approximately 10 years of inventory.

Moving to Page 7 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 oil 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 a $67.91 per barrel. Our realized price was $67.89 per barrel, which is just a couple of pennies below WTI. As of yesterday, LLS is trading at more than a $3 premium to WTI and more than $20 compared to minimum pricing.

Turning to Page 8. I would like to discuss several of our 2018 highlights and goals and the progress we have made to date. We have 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 1.5x 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 a 2- or 3-rig program for 2019.

Running a 3-rig program will maximize production growth for 2019 Penn Virginia while a 2-rig program would maximize free cash flow generation. Given these parameters, we expect production to grow by between 40% and 60% for next year. We are 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 9. 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, in the generally higher cost environment facing the industry, we anticipated 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 spud 20 XRL wells in the second half of 2018 with 10 of those turned in line by year-end and another 10 in process of drilling or completing at year-end. So there'll be some carryover associated with those 10. As illustrated in the chart at 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 revised capital plans called 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 1 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 stream of casing, will increase our capital requirements for the year by an estimated $32 million. As you are aware, the industry is experiencing cost inflation across the spectrum of services, which we estimate at approximately 5%, and that translates into an increase to the capital budget of around $16 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 1.5x or lower by year-end. This increase in capital builds 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 4 slides. We start with production growth. Production growth in 2018 is the heart of the Penn Virginia story. We expect at least a 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 23,500 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 24,000 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 costs on a per barrel of oil equivalent basis. In 2017, we saw a $14.41 per barrel of oil equivalent for our adjusted direct operating expenses, which is the sum of LOE, GPT production and 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 a $11.63 per barrel of oil equivalent in the 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 costs down and cash margin up. These lower costs 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 of 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 these strong cash margins, combined with strong production growth, lead us to the next slide, Slide 13. Balance sheet improvement.

Pro forma for the Hunt and Devon acquisitions, we had debt to adjusted EBITDAX ratio of about 2.6x at year-end 2017. We have already seen improvement to our leverage ratio, posting a 2.2x 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 1.5x by year-end 2018.

Turning to guidance on Page 14. We have 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 costs going forward. With our production growth and our improving cost structure, we see that leverage ratio coming down to about 1.5x 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 midsized 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 of the consensus estimates on the next several slides.

Turning to Slide 15. We are 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 16, 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 our 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 trading at one of the lowest multiples for 2019 within that group of companies. With the growth I have 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 derisked 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 Sweet premium pricing. We're committed to financial discipline with a well-defined plan to get leverage down to 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 are targeting production growth of at least a 120% for 2018 and 40% to 60% in 2019. 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 in 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 Instructions) And our first question comes from the line of Neal Dingmann with SunTrust.

John, first question is more just kind of on your most recent guide to boost in CapEx. I'm just wondering with you and 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.

Well, we just saw some great well results in Area 2 with superior returns, and we wanted to focus our drilling program in that part of our acreage. So obviously, those wells cost a little bit more but they generate higher returns. If you look at it in terms of net turned in line treatable lateral feet, we're actually going to add 16,000 feet to our completed laterals by the end of '18 by drilling 1 less well. So it really goes to the capital efficient part of the development program and 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'll spend funds for, but we won't have them turned in line. So a significant part of that will be some carryover capital. Well, the production will be carryover in 2019, but the capital will be spent in 2018.

Good detail. And then, John, just my follow-up sort of leads into what you were 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 are going to be putting things, and how you see sort of that playing out?

I think we're still planning on being in the mid-70s for percent oil. That's -- bounce around from 74%, I think we saw it something at 76% in one quarter this year, but that's where we think it's going to land.

How different is 2 versus 1, just when you think about from a gas perspective? I know Steve and I were talking about it, but just to hear if you could reiterate that as well?

Well, the GORs in Area 1 are quite a bit less than Area 2. So in the updipped most portion, it'll be close to that 200 would be the GOR and gets down to maybe a 1,000 basis at the deepest. And then once we get into Area 2, it'll scale up from a 1,000 all the way down into Area 2 South of around 5,000.

And our next question comes from the line of Brian Corales with Johnson Rice.

I wanted to hit on just on '19 to start. I know you sounds like you're looking at a 2- or a 3-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?

Well, yes, 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 2- and 3-rig case out there showing a range of growth, and one of them favors 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.

Okay. No, that's helpful. And then the EOR. I thought that was a good map you'll had on your presentation. It shows you how close those projects are. Is this something -- you said should be a fast follower and you're closely watching, but is this something you'll want to test to try to get value from or can you maybe expand on that?

Absolutely. There's a lot of technical challenges and hurdles to implementing it. We probably are not going to be out in front of the pack leading that but trying to observe best practices and come in on 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. Where you -- 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, well, 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 it out of the ground and most economically as possible.

Can you guesstimate on when you try to test it?

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

And our next question comes from the line of Jeff Grampp with Northland Capital.

John, a question just kind of building on Brian's last topic here on the EOR. Could you give us a ballpark sense in understanding it's early, kind of what capital cost would be associated with the pilot 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.

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 offset operator's releases and other [recurring] of the developing play is that the PVT of the oil plays a big part and the ability to mobilize or 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're in a highly faulted 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 faulted up. So the 2 things that I mentioned so far is the PVT, the oil include characteristics is 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 injecting -- 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 with where it appears to be working for other people, I think it bodes well for us.

Great, that's really helpful. I appreciate that. And from 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 EUR per foot basis? Just kind of curious how that's kind of changing things at all while understanding I'm sure you're still getting some cost efficiencies from the longer laterals as well.

Well, actually, I think, if you look at the fact that we've changed our type curve by 8%, on Page 5, you can see what we're maintaining the -- or anticipating the 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 6,000-foot lateral. If I apply to that one 7,000 or 7,500, 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 specially as we get deeper. And some of these wells, as they traverse 2 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 interest those early time declines.

And our next question comes from the line of Brian Steck with Mangrove Partners.

Thanks for a good quarter, and particularly, thanks for your comments regarding 2019 and the production profile and the intended rig program, a range of rig programs. Related to that, I'm just thinking about the kind of growth that you can develop off of a 2-rig program or a 3-rig program, and wondered if you could comment a little bit about it. I'd like to better understand what your expectations are as they relate to rig productivity, and how that's changed since you put the 2018 plan together.

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 2-rig case is going to probably generate or basically will maximize free [cash flow duration], and the 3-rig case will maximize production growth, and really, that's kind of the extent of the analysis for 2019 that we're really prepared to release at this time.

Got it. And I know it's early to say, but the 2- to 3-rig plan on a gross basis, can you give me a sense of what that would look like on a net basis, a range? And if that's not handy, we can cover that off-line.

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

Yes. If it's a 2- to 3-rig gross program, I'm just curious as to what that looks like in terms of net rigs.

Okay, I got you. Well, our average working interest is about 85% to 87% across the asset. I think, as you get down in Area 2, it tends to be a little higher. So it would probably be skewed towards that higher working interest. Does that help you there?

That does. And 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?

Well, the inventory slide on Page 6 really speaks to the XRLs that we have -- already have executed PSAs for or are close to meeting 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 chit numbers change and hopefully, we have some news to report on that in the third quarter, and they're not insignificant, but some -- probably the biggest change that we will have to move those meaningfully forward with some of the acreage swaps that we have pending.

And our next question comes from the line of Wayne Cooperman with Cobalt Capital.

Just for next year, you guys did give some guidance for 50% growth. A, I think you said that your -- the composition between oil and gas should be pretty similar to where you are now. 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, if I was so bold as to model out 2020, would we see sort of growth from the exit rate of '19 into '20? Would that not be unreasonable?

Well, let me tackle the first 2. Yes, we anticipate our percent oil to stay in the mid-70s. And on costs, 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 seek continued gains on the cost front. A couple of 3 items that -- I'm glad you talked about it, it gives me a chance to talk about our LOE reduction and what we've been doing in that regard. Number one, we completed a smart gas lift intermitter project that we started a little over a year ago, and smart gas lift intermitters are basically a way to control your gas injection volumes to minimize the amount of lift gas you inject while maximizing fluid lift. So what we've seen is our gas lift cost come down successfully because of the implementation of that project. Field-wide, it's the largest implementation of Weatherford smart gas lifting emitters that they put in place, and we're really happy with the results. The other big competent in our LOE is saltwater disposal. We produced 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 third-party versus injecting it to our into our own, when we inject it into our own, we're going to save about a $1.25 a barrel. So to the extent we can grow that, that helps as well. The other component of our cost 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 we'll 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...

Just kind of take a stab on 2020, if I took your kind of '19 exit rate, if that was kind of a good starting point to show some growth for 2020.

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

Okay. And -- I didn't ask this 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 you see? Are you seeing any evidence of that?

It could. The challenge for us, though, as we go to Area 2 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.

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

Correct.

And our next question comes from the line of David Snow with Energy Equity.

Yes, I believe all my questions have been answered for the moment.

(Operator Instructions) Our next question comes from the line of [Jeff Davies].

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 do you think about that?

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

EOR, excuse me. Yes, EOR.

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 is what's best for our shareholders, and that includes drilling completing 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 3-dimensional subsurface picture that not only helps on EOR, it helps define the targets for the upper Eagle Ford, in the upper Eagle Ford net of that inventory of which is reflected in our current inventory. But that earth-modeling project should set the stage for a good framework for implementing any EOR program if, indeed, we determine it 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.

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 that you get bought 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, given just kind of optically, the equity does look undervalued. How would you 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. Again, with the stock trading less than a 100,000 shares a day, a few days of the last week, a deal to kind of improve liquidity and improve interest in the story, I think, would be helpful.

I will 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.

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.

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

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.