Ranger Oil Corp (ROCC) 2018 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Penn Virginia's First Quarter 2018 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 VP of Operations.

Prior to getting started, I'd like to remind you of the language in our forward-looking statement section of the press release, which was released yesterday afternoon. Our comments today will contain forward-looking statements within the meaning of the federal securities laws. These statements, which include, but are not limited to, comments on our operational guidance, are subject to a number of risks and uncertainties that could cause actual results to be materially different from those forward-looking statements, including those identified in the risk factors in our annual report on Form 10-K.

We will discuss non-GAAP measures on this call. And definitions and reconciliations of these measures to the most comparable GAAP measure are provided in the presentation posted on our website this morning. Cautionary language is also included on Slide 1 of our presentation. We will use the presentation to go through today's discussion. And finally, after our prepared remarks, we will have a Q&A session at the end of the call.

So let's start on Page 2 with a quick company overview. Penn Virginia is a pure-play Eagle Ford Shale-focused operator in Gonzales, Lavaca and now DeWitt Counties in South Texas. We had 83,800 core net acres in the Eagle Ford as of the end of the first quarter, which is approximately 93% held by production and 99% of which is operated by Penn Virginia. Our drilling inventory at year-end was 589 gross locations and 500 net pro forma for the Hunt acquisition. Our goal is to continue to replenish that inventory through our organic leasing efforts. And through the first quarter, we leased or extended approximately 2,700 acres. Our product mix in the first quarter was 89% liquids, of which 78% of that was crude oil.

All of Penn Virginia's Eagle Ford oil production receives Louisiana Light Sweet pricing, or LLS premium, and generates very attractive realized pricing in pure leading cash margins. We're currently running 3 rigs and 1 dedicated frac spread, supplemented with a spot frac spread brought in periodically as our DUC inventory builds. Penn Virginia is targeting year-over-year production growth of 125%. And we are (inaudible) to achieving that target as evidenced by our first quarter results, which we issued yesterday afternoon.

Moving on to Page 3. Let's take a closer look at the strong operational and financial performance we generated in the first quarter. We're really excited about our continued success in moving down-dip into our deeper and higher-pressured acreage, which we call Area 2. As we've continued to delineate our Area 2 acreage, we've now completed 13 wells on 6 pads with impressive results that are outperforming our most recent Area 1 wells.

Recently, we brought 4 of these pads online in Area 2, which helped drive up total production for the quarter. And I'll provide a little bit more color and information about these Area 2 results later in the call. We also brought 2 pads online in the shallower, lower-pressured portion of Area 1 in the first quarter that didn't quite meet our expectations. And early time results indicate that we need to continue to evolve our completion design in our shallower leasehold.

Our first quarter 2018 production averaged 16,145 barrels of oil equivalent per day, up 28% over fourth quarter of 2017, which exceeded first quarter midpoint of guidance. More importantly, we grew our oil production by 33%, which receives the benefit of LLS pricing. Operationally, we are hitting on all cylinders.

On the drilling side, we continue to see significant improvement since we expanded our operations team and changed service providers in the fourth quarter of last year. We continue to drill wells faster, improving drilling feet per day by more than 40% since that time. These improvements allowed us to drill our longest extended reach lateral drilled to date. The McCreary-Technik 2H was drilled to a total depth of more than 22,000 feet, with a 9,100-foot lateral, in just under 18 days.

On the completion side, we also continue to see meaningful improvements. Through the first quarter, our operations team completed on average 6.9 frac stages per day, an increase of more than 45% over full year 2017. This average was actually exceeded while fracking the 3-well McCreary-Technik pad, where we completed 122 stages at an average of 7.4 stages per day. These improved operational efficiencies helped drive our strong production growth, which in turn generated an impressive financial performance.

Adjusted EBITDAX was over $50 million for the quarter, which is up 35% over the fourth quarter of 2017. Penn Virginia is in an enviable position, with all of our Eagle Ford production receiving Louisiana Light Sweet crude pricing. Given the strong LLS pricing during the first quarter, our realized price for crude oil was $63.23 per barrel, which equates to a $0.36 per barrel premium to the comparable WTI pricing for the quarter.

On an aggregate basis, including natural gas and natural gas liquids, we had a realized price of $52.99 per barrel of oil equivalent in the first quarter of 2018. These strong production results also helped drive down our unit lease operating expenses to $5.02 per barrel of oil equivalent, with adjusted total direct operating cost of $13.05 per barrel of oil equivalent, and combined with robust realized pricing, yielded a strong cash operating margin of $39.94 per barrel of oil equivalent. We are firmly committed to meeting our articulated goals for 2018, which is growing production by 125%, to be drilling within cash flow by fourth quarter and to report a leverage ratio of 1.5x or lower by year-end.

So moving on to Page 4. I would like to focus in on the wells we have drilled in Area 2, which have been completed using our slick water design. First, a little history. We first tested this design in Area 2 in 2017 on a Lager pad. In May of 2017, we turned to sales with a Lager 3H well with a 24-hour 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, can somewhat reduce the steep declines typically seen in early time. To date, the Lager 3H has produced more than 286,000 BOEs, which is approximately 36% of estimated reserves. The positive Lager well results provided us the confidence to continue delineating Area 2 this year.

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 to date. The 2-well Geo Hunter pad had a 24-hour IP of 5,465 BOE per day and produced a 30-day average IP rate of 3,767 BOE 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 BOE per day and a 30-day IP rate of 4,028 BOE 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 enabled us to access reserves that would have likely otherwise been left in the ground.

On the last day of the first quarter, we turned to sales our fourth Area 2 test, the McCreary-Technik pad, yet another PSA opportunity. This 3-well pad recorded a preliminary peak 24-hour IP rate of 5,425 BOE per day, which was approximately 80% oil. As I previously mentioned, we drilled and completed our longest lateral to date on this pad. The McCreary-Technik 2H well had a lateral length greater than 9,100 feet and was drilled in less than 18 days. This was an important proof of concept of us to demonstrate we could effectively drill and complete and produce our longest extended reach lateral yet. Later in April, we brought on yet another PSA opportunity, our Schacherl-Effenberger 2-well pad, which had a preliminary 24-hour IP rate of 3,073 BOE per day, with 88% of its production in crude oil.

And finally, just 14 days ago, we turned to sales the 3-well Medina pad, which recently recorded a preliminary 24-hour IP rate of 5,208 BOE per day, with 63% oil. We saw initial flowing casing pressures ranging from 5,400 to 5,800 psi on these 3 wells. And these are highest pressures we've seen in our Eagle Ford acreage. So we're not getting very aggressive with the flowback, maintaining high flowing pressures to try and maintain higher initial production for a long period of time. The Medina pad is actually in DeWitt County and is in the southernmost portion of the leasehold position on the acreage we purchased from Devon last year.

Penn Virginia's working interest in these 13 Area 2 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 are optimistic this trend will continue for the balance of our 2018 plans.

Now turning to Page 5. Let's talk about the drilling results from our Area 2 wells in aggregate. To date, we have drilled and completed 13 wells in Area 2 using the slick water completion design. And for the 5 wells for which we have at least 30 days of production history, you can see that they have been exceeding our Area 2 North type curve.

The graph depicted on Page 5 shows our Area 2 North type curve in red. The production rate is normalized for a 6,000-foot lateral. The blue and yellow line is the average production rate for all the wells over a 4.5-month period from initial production. And as you can see, the average production line is significantly above our Area 2 type curve. The early data from these wells are indicating very favorable results for this limited dataset. We are obviously very encouraged by these results to date, but still have additional wells to drill and evaluate this year. We intend to evaluate the possibility of allocating more capital to Area 2, relative to Area 1.

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. Based on our current type curves, the anticipated rates of returns for our inventory range from 45% to 150%, as shown by the columns above the table. The economics for this inventory was run at $56 oil and $3 gas. Another takeaway from this slide is that it illustrates the value proposition of drilling the XRLs, which is a more capital-efficient approach to monetizing our inventory of net treatable lateral length.

One of our goals is to continue to replenish that inventory through our organic leasing efforts. I'm pleased to say that during the quarter, we leased or extended approximately 2,700 acres. We've acquired some of those new leases organically. And we've also extended previously non-core leases as we delineate Area 2 to replace the inventory we drill each year and maintain our location inventory.

First 2 charts on the left of Page 7 clearly illustrates the improved operational execution that our newly expanded technical team and upgraded drilling and completion service providers are achieving. In Area 1, where we primarily drill 2-string wells, our average effective feet per day has improved 40%. In Area 2, where we drill 3-string wells, our average effective feet per day has improved even more dramatically, up about 60%. And this is simply our average feet per day, from spud to rig release, comparing the first 3 quarters of 2017 to the fourth quarter of 2017 through year-to-date 2018.

The chart on the right-hand side of Page 7 also clearly illustrates the improved completion efficiencies since changing frac service providers, going from 4.7 stages per day to 6.9 stages per day. And while the average of 2017 was 4.7 stages per day, the average over the last 2 pads in 2017 was only 3.2. So we've had quite an improvement here lately.

Moving to Page 8 of the presentation. We believe Penn Virginia is one of the oiliest companies in the E&P sector with 78% of our production stream being oil, which overall averages 43 to 45 degrees API Gravity. The recent move-up in oil prices has benefited oil producers, with HTI hovering around $70 per barrel. Penn Virginia is very fortunate in that all of our Eagle Ford oil production is currently sold into the LLS markets, which is currently trading at a significant premium to WTI. During the first quarter, WTI averaged $62.87 per barrel. Our oil production realized $63.23 per barrel, which is a $0.36 per barrel premium over WTI. As of yesterday, LLS is trading at more than a $4 premium to WTI.

Moving on to Page 9. Our capital plan for 2018 is for an estimated $320 million to $360 million, approximately 95% of which is anticipated to be directed to Eagle Ford drilling and completion, with the balance directed primarily toward facilities, pipelines and land. We expect to drill a total of 55 to 60 gross wells and 45 to 50 net wells. As it stands today, we anticipate that 22 of the gross well count will be XRLs.

As you can see, capital allocation by area is pretty close to 50% in Area 1 and 50% in Area 2, with a higher numerical well count in Area 1. While this is our current plan, drilling schedules tend to change. And our 2018 drilling schedule also reflects a shift to drilling wells with the longer XRLs, as illustrated in the chart at bottom right. 2017, our average treatable lateral length was 5,250. And for 2018, we expect that to increase 33% over the prior year to about 7,000 feet. To the extent we're able to timely form additional PSAs that allow for drilling more XRLs, the drilling schedule is flexible enough for changes that allow us to most efficiently deploy capital. As I previously mentioned, with our success to date in Area 2, the company intends to evaluate allocating more capital to Area 2, relative to Area 1.

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 about 125% production growth in 2018 over 2017 with our development plan. Our guidance for second quarter of 2018 is from 21,000 to 23,000 BOE per day. And that's about a 36% increase over the first quarter.

I'm pleased to report that we are already off to a great start for the second quarter, with estimated production for April coming in at about 20,900 BOE per day. The second quarter will be the first quarter where we see the full effect of the Hunt acquisition, not just in PDP volumes, but also by virtue of our increased working interest throughout a big part of Area 1. We aren't giving third or fourth quarter guidance yet, but we expect meaningful growth each quarter. The end result is full year guidance of 22,000 to 25,000 BOE per day. And that growth leads us to the next slide.

Slide 11 is where we show you our cash operating cost on a per barrel of oil equivalent basis. In 2017, we saw $12.08 per BOE for our cash operating cost or the sum of LOE, GPT and cash G&A, adjusted for some onetime items, which is reconciled in the appendix of the presentation. We've made tremendous progress already, lowering our cash cost to $10.23 per BOE in the first quarter. And for 2018, thanks to higher working interest as a result of the recent acquisitions and substantial production growth, we expect our cash cost per BOE to be $9.88 at the midpoint of guidance. You may recall, we had to add very little G&A cost to support the Devon and Hunt acquisitions. So we're driving cost down and cash margin up on a per barrel basis. These lower costs lead to the next slide.

On Slide 12, you see our realized cash operating margin per BOE. For full year 2017, we realized $27.79 per BOE. We aren't giving realized cash operating margin guidance, but with WTI oil prices at $60, cash cost of $10.23 per barrel and premium LLS pricing, which gives us realized differentials off WTI of 0:1, you can see our cash margins are greatly improving. You can really see this in our first quarter 2018 realized number. Our cash margins per barrel of oil equivalent for the first quarter was almost $40 at $39.44, a 15% increase over the fourth quarter. 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, leads us to the next slide, Slide 13, which illustrates our balance sheet improvement.

Pro forma for the Hunt acquisition, we had debt to adjusted EBITDAX ratio of about 2.6x at year-end 2017. And we have already seen improvement to that leverage ratio, posting a 2.4x number as of the end of the first 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've modified our guidance slightly from the update we've provided during our fourth quarter conference call. Revised guidance now reflects higher anticipated realized oil price through lower oil price differentials, lower lease operating expenses per BOE and general and administrative expenses per BOE. Midpoint of guidance improves cash margins by $1.50 per BOE. With our production growth, our improving cost structure, we see that leverage coming down to about 1.5x by year-end. And we expect to be drilling within cash flow by the fourth quarter. Along with 125% anticipated production growth, these are our financial goals that we are committed to achieving in 2018.

With the plan laid out for you, let's look at how we compared 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 and presentations. I should note that we are not endorsing or conforming any of the consensus estimates on the next several slides but include them for illustrative purposes.

Turning to Slide 15. We are projected to have a very high growth rate for 2018 compared to that of our peers. As I mentioned, the chart is showing consensus estimates for our peers. And we are targeting a growth rate of approximately 125%. 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 2018.

Now turning to our valuation metrics, let's move to Slide 17. Here, we look at the multiples of companies that operate across different basins. The Permian generally garners the highest trading multiple, and the Eagle Ford-focused companies on average trade at a lower multiple. Within the Eagle Ford, consensus and for our peers' other public data, has Penn Virginia trading at the lowest multiple within that group of companies. With the growth I laid out for you, the low-cost structure and very strong cash margins, we believe that Penn Virginia provides an attractive valuation.

So on to Slide 18. What is Penn Virginia's value proposition? Well, we are a pure-play Eagle Ford company with a large derisked contiguous acreage position. We're focused on returns and we have a drilling inventory that provides a nice runway for delivering those returns. We have quality assets that are oil-rich, centered in the volatile oil window of the Eagle Ford and well positioned geographically to take advantage of Louisiana Light Sweet premium pricing.

We are committed to financial discipline with a well-defined plan to get us to leverage of 1.5x by year-end and drilling within cash flow. And we are protecting that cash flow along the way with hedges. Finally, we have growth potential. If you take away anything from this presentation, you should take away that we are growing rapidly. We have a multiyear inventory of drilling locations with superior economics, especially with a growing inventory of XRLs in Area 2 as well as Area 1.

And with that, Sandra, we can go to the Q&A portion of the call.

(Operator Instructions) Our first question comes from the line of Neal Dingmann with SunTrust.

John, just the one question I had. Given all the success you've had recently in Area 2, could you talk about the cadence going forward on how you see between 2 and 1 kind of for the remainder of the year and next year, given all the success you've had now in both areas?

Well, we're going to pretty much stay on track for where we've been so far. We like the success we've had in Area 2. We are currently completing and drilling wells in Area 1 as well. We like to get a little bit more production history in Area 2 really before we commit to a wholesale change of our drilling program. But it's certainly looking that way. One of the things we'll be doing in Area 1 as we speak is drilling an XRL pad right there. Our Hawn Holt pad, we've got 2 wells that will have laterals over 9,000 feet, almost 10,000, that we're drilling right now. So we want to continue to test the XRLs, both in Area 1 and Area 2. So we're very happy with the results we've seen. But we want to be cautious and judicious in the way we allocate our capital.

(Operator Instructions) Our next question comes from the line of Brian Corales with Johnson Rice.

And nice quarter, and clearly the market is saying that as well, so nice job on 1Q. Going back to Area 2, I mean, I guess, is this -- is more about -- before you add more or allocate more capital there, is it just more about how the extended laterals look in Area 1? Is that what you're waiting for before putting more capital on Area 2?

No, I think that's a separate issue unto itself to help optimize returns in Area 1. It's just early days, except for a small handful of wells in Area 2. I do think there's a high likelihood, though, that we'll continue to evaluate drilling more wells in Area 2. It's certainly leaning that way.

Okay, fair enough. And then is there acreage -- I mean, just adding, I guess, some acreage open leasing, is there other small, little bolt-on deals in the general neighborhood that you all are looking at? Or is there a lot of opportunities? Can you maybe about the M&A landscape?

There's several smaller packages in and around us as well as a handful of larger packages held by others. We think the Hunt and Devon were real good, solid singles and doubles. And to the extent we can replicate that from what's around us, we'd like to try. In the meantime, we're going to continue the organic leasing and extending some of the acreage that we had previously considered non-core. With the results that we've seen in Area 2, there's some previous non-core acreage that we didn't have inventory on that we're actually extending acreage now, as well as organically leasing smaller tracts as they come available. Quite honestly, there's not a whole lot of the smaller tracts available. That's a fairly slow pace of getting that. But to put it in perspective, so I think we've guided to between, what, 40 to -- 45 to 50 net wells this year. So if you assume an 80-acre spacing per well, then really just to maintain your inventory, you really only need to add 4,000 or 5,000 net acres a year to maintain that inventory. And while acreage doesn't necessarily equal inventory, because you've actually got to form units and make sure you can get a drill of a lateral in there, it generally allows us to keep a rolling inventory forward without too big of a dip.

Got you, okay. And one more if I could, just on the cost side. Are you all seeing much inflation? And I know we saw some last year. But have you seen any this year? And if so, what areas are you seeing the most pricing pressure?

Yes, we are. We've seen it in the day rates of the drilling rigs that we've got 3 H&P drilling rigs out there that are on staggered 6-month terms. Those have gone up a fair amount, I think around 14%. Diesel has gone up significantly. And that sounds like a rather mundane piece of information. But we use a lot of that in the drilling, in the completion and in our oil-based mud. So diesel is up, I think, 15%. Some of the other services has gone up as well. I think -- and I'm not talking about total well cost here, but when you look at the steel cost that are probably headed to a 10% to 15% increase, that's the kind of the general range we see on individual service lines going from 10% to 15%. But we haven't seen that total completely follow through to the total well cost yet. But those are the big items that we see. Sand logistics can be an issue. We do have most of our sand under contract for the year. So we can -- based on what we see, we know that the logistics of delivering sand and in providing sand throughout the Permian and the Eagle Ford is probably on a pretty challenging track. We're glad we have a lot -- mostly all of that on contract.

And that does conclude today's Q&A session. And I'd like to return the call to Mr. John Brooks for any closing remarks.

Well, we'd like to thank you for your time this morning as well as your interest in Penn Virginia. And we look forward to talking to you again next quarter. Thanks again.

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.