Penn Virginia Corporation
Q1 2018 Earnings Call Transcript

Published: 9 May 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia's First 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; 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 most recent 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 in Slide 1 of our presentation. We will use this 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 back 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% of 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 and pure leading cash margins. We're currently three rigs and one dedicated frac spread supplemented with a spot frac spread brought in periodically as our DUC inventory builds. Penn Virginia's targeting year-over-year production growth of 125% and we're [technical difficultly] to achieving that target. As evidenced by our first quarter results, which we issued yesterday afternoon. Moving onto 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 deep into our deeper and higher pressured acreage which we call it Area 2. As we continue to delineate our Area 2 acreage, we've now completed 13 wells on six pads with impressive results that are outperforming our most recent Area 1 well. Recently we brought four of these pads online in Area 2 which help drive up total production for the quarter and I'll provide a little bit more color information about these Area 2 results later in the call. We also brought two 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're hitting on all cylinders. On the drilling side, we continue to see significant improvements 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 drill to-date. The McCreary-Technik 2H was drilled to a total depth of more than 22,000 feet with 9,100-foot lateral in just under 18 days. On a 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 fracing the three well McCreary-Technik pad where we completed 122 stages of an average of 7.4 stages per day. These improved operational efficiencies help drive our strong production growth, which in turn generated an impressive financial performance. Adjusted EBITDAX was over $50 million for the quarter which was up 35% over the fourth quarter of 2017. Penn Virginia is 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 $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 help drive down our unit to 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 yield the strong cash operating margin of $39.94 per barrel of oil equivalent. We're firmly committing to meeting our articulated goals for 2018 which is growing production by 125% to be drilling within cash flow by fourth quarter and report a leverage ratio of 1.5 times or lower by year end. So moving onto Page 4, I'd like to focus in on the wells we've 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 the Lager pad. In May 2017, we turned the sales of the 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 is our second confirmation test, the slick water completions in Area 2. The Geo Hunter results like the Lager have been very positive to-date. The two-well Geo Hunter pad had a 24-hour IP of 5,465 BOE per day and produced 30-day average IP rate of 3,767 BOE per day. Our third successful test in Area 2 was our two wells 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 two units that allowed us to drill two wells with average laterings over 8,100-feet and it enabled us to access reserve that would have likely otherwise been left in the ground. On the last day of the first quarter, we turned the sales our fourth Area 2 test the McCreary-Technik pad yet another PSA opportunity. This three-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 link 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 two-well pad which had a preliminary 24-hour IP rate of 3,073 BOE per day with 88% of its crude oil. And finally just 14 days ago, we turned to sales the three-well Medina pad which recently recorded a preliminary 24-hour IP rate of 5,208 BOE per day with 63% oil. We saw initial flow casing pressures ranging from 5,400 to 5,800 PSI on these three wells. These are the highest pressures we've seen in our Eagle Ford acreage. So we're not getting very aggressive with the flow back. Maintaining high flowing pressures to try and maintain higher initial production for a longer period of time. The Medina pad is actually in DeWitt County and it is in the Southern most portion of the leasehold position on the acreage repurchased from Devon last year. Penn Virginia's working interest in these 13 Area 2 wells laying from 71% to 100%. As you can see, we've 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. Now turning to Page 5, let's talk about the drilling results from our Area 2 wells in aggregate. To-date we've drilled and completed 13 wells in Area 2 using the slick water completion design and for the five wells for which we had 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 we're 6,000 foot lateral. The blue and yellow line is the average production rate for all of the wells over four and half 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 with limited data set. We're obviously very encouraged by these results to-date, but still had 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 curve, the anticipated rate of returns for our inventory range from 45% to 150% as shown by the columns above the table. The economics for this inventory was $56 oil and $3 gas. Another take away from this slide is that, it illustrates the value proposition of drilling the XRLs which is the 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 drilled each year and maintain our location inventory. First two charts on the left to 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 drilled two stream wells our average effective feet per day has improved 40%. In Area 2, where we drilled three stream 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 three 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 two 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 the one of the oiliest [ph] companies in the E&P sector with 78% of our production stream being oil which overall average is 43 degree to 45 degrees API gravity. The recent move up in oil prices has benefited all producers with HDI hovering around $70 per barrel. Penn Virginia is very fortunate and all of our Eagle Ford oil production is currently sold into the LLS market, 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 $4 premium to WTI. Moving onto 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 a balance directed primarily towards facilities, pipelines and land. We expect to drill a total of 55 to 60 gross wells in 45 to 50 net wells. As it stands today, we anticipate the 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 the higher numerical well count in Area 1. While this is our current plan drilling schedule tend to change and our 2018 drilling schedule also reflects the 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 inspect that to increase 33% over the prior year to last 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 allocated more capital to Area 2 relative to Area 1. Moving onto Slide 10, I want to walk you through the Penn Virginia value proposition over the next four 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 36% increase over the first quarter. I'm pleased to report that we're already off to a great start for the second quarter with estimated production for April coming 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 virtually of our increased working interest throughout big part of Area 1. We aren't giving third or fourth quarter guidance yet, but we expect meaningful growth each quarter. The enter result is full year guidance at 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 in cash, G&A adjusted for some time one-time items which is reconciled in the appendix with 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 result of the recent acquisitions in 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 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 of WTI of zero to one. 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, $39.44, 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 2.6 times at yearend 2017. And you've already seen improvement to that leverage ratio posting 2.4 times number as of the end of the first quarter and we expect that downward trend to continue throughout the year, with the target leverage ratio of 1.5 times 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 administrative expenses per BOE. The midpoint of guidance improves cash margin by $1.50 per BOE. With oil production growth, our improving cost structure we see that leverage 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 125% anticipated production growth. These are our financials goals that are committed to achieving in 2018. With the plan laid out for you, let's look at how we compare to our small-to-mid size 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're not endorsing or conforming any of the consensus estimates on the next several slides, but include them from illustrative purposes. Turning to Slide 15, we're projected to have 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're targeting a growth of approximately 125%. On Slide 16, given our high percentage of oil percentage, lower cost per BOE and LLS pricing. We're projected to have one of the highest EBITDAX per BOE ratios in Penn Virginia's peer group in 2018. Now turning to valuation metrics, let's move to Slide 17. Here we look at the multiples of companies that operate across different basins. The Permian generally [indiscernible] trading multiple and the Eagle Ford focused companies on average trade for 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 onto Slide 18, what is Penn Virginia's value proposition. Well we're pure play Eagle Ford company with a large de-risk continuous acreage position. We're focused on returns and we have the drilling inventory that provides a nice runway for delivering those returns. We have quality assets that are all rich centered in the volatile oil window of the Eagle Ford and well positioned geographic [indiscernible] take advantage of Louisiana Light Sweet premium pricing. We're committed to financial discipline with a well-defined plan to give us the leverage of 1.5 times by year end and drilling within cash flow and we're 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're growing rapidly. We have a multi-year inventory of drilling locations with superior economics especially with the 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:]

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

[Neal Dingmann:]

John, one question I had given all the success you've had recently in Area 2. Can you talk about the cadence going forward? You know how you see between two and one, kind of for the remainder of the year and next year given all the success you've had now in both areas. Thank you.

[John Brooks:]

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're 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 as we're drilling an XRL pad right there. Our Hawn Holt pad we've got two wells that will have laterals over 9,000 feet, almost 10 that we're drilling right now. So we wanted to continue to test the XRLs both in Area 1 and Area 2. So we're very happy with the results we're seeing, but we want to be cautious and judicious in the way we allocate our capital.

[Neal Dingmann:]

Thanks guys.

[Operator:]

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

[Brian Corales:]

Going back to Area 2, I guess is this 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 traffic on Area 2?

[John Brooks:]

No, I think that's a separate issue on itself, to help optimize returns in Area 1. It's just early days except for small handful 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 leading that way.

[Brian Corales:]

Okay, fair enough. And then is there acreage, I mean just adding I guess acreage the open leasing. Is there other small littler bolt-on deals in the general neighborhood that you're looking at or is there lot of opportunities can you maybe talk about the M&A at landscape.

[John Brooks:]

There's several smaller packages in an around us as well as handful of larger packages held by others. We think the Hunt and Devon were real good and solid singles and doubles and to the extent we can replicate 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've 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 tracks as they come available. Quite honestly there is not whole lot of the smaller track available that's a fairly slow pace of getting that. But to put in perspective, so I think we've guided to between what 45 to 50 net wells this year. So if you're assuming 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 [indiscernible] units and make sure you can get a drillable lateral in there. It generally allows us to keep a rolling inventory forward without too big of a depth [ph].

[Brian Corales:]

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

[John Brooks:]

Yes we are, we've seen it in the day rates of the drilling rigs, we've got 3H [indiscernible] drilling rigs out there, that are staggered six-month term 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 the information, but we use a lot of that in the drilling, in the completion and in our oil base 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 [ph] cost that are probably headed to 10% to 15% increase that's 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 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 mostly all of that on contract.

[Brian Corales:]

All right, guys. Thanks and congrats on the quarter.

[Operator:]

Thank you. 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.

[John Brooks:]

Well I'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.

[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.