Penn Virginia Corporation (PVAC) CEO John Brooks on Q3 2019 Results - Earnings Call Transcript

Nov. 08, 2019 7:21 PM ETRanger Oil Corporation (ROCC)
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Penn Virginia Corporation (PVAC) Q3 2019 Results Conference Call November 8, 2019 11:00 AM ET

Company Participants

Clay Jeansonne - Director of Investor Relations

John Brooks - President Chief Executive Officer

Ben Mathis - Senior Vice President of Operations and Engineering

Conference Call Participants

Irene Haas - Imperial Capital

Jeff Grampp - Northland Capital Markets

Richard Tullis - Capital One Securities

David Snow - Energy Equities Inc.


Good day. And welcome to the Penn Virginia Third Quarter 2019 Earnings Conference Call [Operator Instructions]. Please note this event is being recorded.

I would now like to turn the conference over to Clay Jeansonne Director of Investor Relations. Please go ahead.

Clay Jeansonne

Thank you, Andrew, and good morning everyone. We appreciate your participation in today's call. I'm Clay Jeansonne, Director of Investor Relations. And I'm joined this morning by John Brooks, Penn Virginia's President CEO and Ben Mathis, our Senior Vice President of Operations and Engineering.

We will discuss non-GAAP measures on this call. Definitions and reconciliations of these measures to the most comparable GAAP measures are provided in our third quarter earnings press release and 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 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 Law. These statements 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 as they may be amended in subsequent Form 10-Qs. Cautionary language is also included on Slide 1 of the presentation. We will use the presentation to go through today's discussion. Finally after our prepared remarks we will answer any questions you may have.

With that I'll turn the call over to John.

John Brooks

Thanks Clay. Let's start on Page 3 with a quick company overview. Penn Virginia is a pure-play Eagle Ford Shale operator in Gonzales Fayette LaVaca and DeWitt counties in South Texas. We have approximately 100,200 gross acres and 87,300 net acres in the Eagle Ford, which is approximately 91% held by production and 99% of which is operated by Penn Virginia. Our estimated drilling inventory on September 30, 2019 was 500 gross or 440 net locations. And I want to point out that this inventory count is only for lower Eagle Ford. One of our goals for our land and technical team is to continue replenishing that inventory through organic acreage leasing, small acquisitions, as well as equity swaps with adjacent operators. And we also hope to increase that count by identifying this to find additional location inventory in the upper Eagle Ford in Chalk from our recently constructed earth model.

Our product mix in the third quarter was 88% liquids, of which 73% was oil. Penn Virginia's oil production receives premium Louisiana Light Sweet, which we sometimes refer to as LLS, or Magellan East Houston, also referred to as MEH pricing, which enhances our adjusted EBITDAX margins. We're currently running two rigs and one dedicated frac spread. We are targeting year-over-year production growth for 2019 of 25% to 30%, and we are well on our way to achieving that target based on the first nine months results.

So let's move on to Page 4 and take a closer look at our solid operational and financial performance for the third quarter. For the first nine months of 2019, production averaged 27,196 barrels of oil equivalent per day, which represents 33% increase from the same period last year. For the third quarter of 2019, we grew average daily production 4% over the second quarter. We continue to benefit from our close proximity to the LLS and MEH markets, which resulted in the third quarter realized oil price of $57.12. This is approximately $0.68 higher than or 101% of the average WTI price for the third quarter. For the balance of the year, we expect that premium to moderate and expect realized pricing to be at parity with WTI or up to $1 off.

Adjusted EBITDAX for the first nine months of the year was $255.8 million which was 21% higher than the same period last year or $34.46 per BOE. Looking specifically at the third quarter of 2019, adjusted EBITDAX was $87.1 million, slightly higher than the second quarter. We recorded adjusted direct operating expenses of $11.73 per BOE for the first nine months of 2019, and that's 6% improvement year-over-year. Our growth in adjusted EBITDAX allowed us to improve our leverage ratio to 1.7x as compared to 1.9x on September 30, 2018. Finally, increased production, lower cost offset by lower pricing yielded adjusted net income per share for the first nine months of the year of $6.20 per diluted share.

Looking at Page 5, we believe there are four keys to Penn Virginia's continued success. First of all is our focus on cost. In this volatile commodity price environment to remain profitable, you must maintain a lean cost structure and we believe Penn Virginia has one of the lowest cost structures for any oil-weighted E&P. Secondly, maintain strong margins. As I mentioned previously, our close proximity to the Gulf Coast allows Pen Virginia to access premium priced markets. This includes accessing Gulf Coast waterborne markets such as Corpus Christi by truck and the LLS and MEH markets through multiple pipeline access points. Third, ensure financial discipline. Given the current and expected continued volatility in the energy commodity markets, we remain hyper-focused on maintaining financial discipline and a strong balance sheet, growing production while drilling within cash flow is a great example of that.

And finally, the most important measure to generate free cash flow. Ultimately, you must live within your means and we expect to drill within cash flow in the fourth quarter, and generate significant free cash flow in 2020. We believe this makes Penn Virginia unique, a proven small cap with a clear path to free cash flow generation in the near term.

On Page 6 and turning to our capital budget for 2019, our capital budget is currently estimated at $350 million to $360 million, all of it in the Eagle Ford. This is slightly higher than previous estimates due primarily to two factors. First of all, we recently acquired additional working interest in a portion of our assets. We also acquired yet another entity's small working interest in three recently proposed wells. These increases in working interest account for approximately $4 million to $5 million in additional CapEx.

Also, due to increased drilling efficiencies, we now expect two additional pads to be completed in December of this year instead of next year, so the additional CapEx for those two pads will also likely be incurred this year, although, the contribution to annual production may be minimal due to timing. 97% of total spending is expected to be directed toward drilling and completion with the balance focused on facilities pipelines and grassroots acreage leasing.

As I mentioned previously, our plan assumes a continuation of the two-rig program. For the full year 2019, we expect to drill approximately 44 gross or 39.4 net wells and turn in line 48 gross and 43.2 net wells. In the fourth quarter, we expect to drill 11 gross wells in 9.6 net wells and turn in line 11 gross and 9.9 net wells. We continue to realize significant drilling and completion efficiencies due to the outstanding work of our operations team. Our previous estimates at Penn Virginia ending the year with 0 drilled but uncompleted or DUCs. But given these efficiencies we expect to end the year with up to 5 DUCs now.

We have seen significant decreases in overall drilling and completion costs. Comparing the third quarter of 2019 to the third quarter of 2018 we saw drilling and completion costs reduced by approximately 18% to 21%. We are benefiting from additional service cost reductions in the fourth quarter as some of our service contracts have been renegotiated and we expect these service cost reductions to continue into 2020.

Moving on to Slide 7. Our organization is committed to lowering costs by driving efficiencies throughout the organization and working with our service providers to reduce those costs. I will discuss the progress we have made on the next two slides. In the third quarter we have continued to improve on our drilling and completion metrics with drilling exceeding our drilled feet per day targets and completions exceeding our target for stages pump per day.

The two charts on Page 7 illustrate the improved operational execution of our technical team over the last several years and in the third quarter. In Area 1 where we primarily drilled 2-stream wells that's where we've seen the biggest pickup, our average feet per day has improved dramatically by approximately 69% over 2017. In Area 2 where we drilled three stream wells our average feet per day has also improved up about 6% since 2017. And this is simply our average feet per day from spud to rig release. So that also includes running casing. And this compares 2017 to the first three quarters of 2019.

The three well Addax 100 pad that was drilled in the third quarter was the best drilling performance to date in Area 1 by Penn Virginia. The wells averaged 6.7 days from spud to rig release which is an average of 2457 feet per day from spud to rig release or an improvement of roughly 119% over 2017 performance in Area 1. The cost to drill complete and equip the Addax 100 wells on a cost per completed lateral foot basis averaged about 20% less than Area 1 wells drilled in the first half of 2019.

Moving on to Slide 8 talking about improving efficiencies. These two charts illustrate the improvements in cycle time on both our two well pads and three well pads. The chart tracks the time from spud of the first well on the pad to flow back of the wells, clearly, a significant improvement over the last several years.

The time for rig moves from pad to pad has decreased 40% from the first quarter to the third quarter of 2019. Similarly skid times between wells on the same pad also improved 40% over the same time period. On the completion side of things stimulation service efficiencies have also increased with an 18% increase in horsepower availability over that same time period. This page and the previous pages illustrate that we've continued to focus the organization in ways to improve efficiencies and drive cost down while still maintaining a safe work environment.

On Slide 9, as I mentioned in my brief comments on the company overview slide, one of our goals for the Penn Virginia land and technical teams is to continue replenishing our drilled inventory and growing it further through organic acreage leasing small acquisitions acreage swaps with adjacent operators and delineation drilling. We call this our focus on the ground game. We believe we can replenish inventory for a two-rig program by adding 3,000 to 4,000 net acres per year. In 2017 and '18 we added 3,366 and 4,336 net acres respectively. So far in 2019 we have added approximately 3321 net acres.

We continue to work on several additional transactions and it give us confidence in our ability to accomplish our target for the year. Next let's take a look at our inventory over time. In 2017 and 2018 we were successful in not only replacing our net inventory of future drilling locations but also growing it. This year we have several projects we're currently working on to help us accomplish this goal.

Turning to the total length of lateral feet available in our drilling inventory, which is solid black line plotted above the net location and the graph at the bottom right. We refer to that as total net treatable lateral feet. We have also been successful in increasing that number in the last several years. We can increase net treatable lateral feet and several ways by adding inventory through lacing swaps acquisitions, including the acquisition of additional net interest in our existing gross inventory, and three delineation drilling.

Another part of the ground game is to find areas where we can increase lateral links, thereby increasing total treatable lateral feet. As previously discussed we recently made an acquisition of approximately 1,420 net acres, which included additional working interest in 109 producing wells, as well as an additional 43,000 feet of net treatable lateral.

We've completed the first phase of constructing our earth model. As you may recall from prior discussion the earth model combines petrophysical data seismic data well logs and other downhole information to more accurately map the subsurface geology of our acreage position. This allows us to generate a three-dimensional view of the subsurface to help optimize our Lower Eagle Ford drilling program identify Upper Eagle Ford targets, as well as other targets and guide our enhanced oil recovery evaluation. Initial results are promising indicating additional potential prospects in the Upper Eagle Ford where most of our early technical efforts have been focused. We look forward to keeping everyone apprised of our efforts on this important initiative.

Moving on to Page 10. Unlike other basins in the U.S. the Eagle Ford has many crude oil delivery points and virtually no pipeline constraints. Penn Virginia is in an enviable position geographically as well as geologically as all of our production receives premium pricing that is either LLS MEH or WTI Houston. We have access to Kinder Morgan and Enterprise Products pipelines which deliver directly into the Houston markets.

We also have the ability to deliver crude to the Philips 66 Refinery in Sweeny and to access other waterborne markets including Corpus Christi via truck or truck to pipe. These factors are the primary reason Penn Virginia is recording crude realization of $0.68 above WTI. In addition, we have ample takeaway capacity with multiple marketing options for both our oil and gas for the foreseeable future.

Looking at Page 11, we believe Penn Virginia is one of the highest-weighted oil companies in the E&P sector with oil comprising 73% of our production stream for the third quarter with an overall blended quality that averages approximately 45-degree API Gravity. We are especially well positioned as the entirety of our oil production is sold into the LLS or MEH market. And as of yesterday, LLS is trading at a $4 premium to WTI and MEH is trading at $3.41 premium to WTI.

Moving on to Page 12. We believe Penn Virginia has one of the lowest levels of LOE per BOE in our peer group and the industry especially given our heavy weighting to oil. For the first nine months of 2019 LOE per BOE was at $4.48 per BOE down 3% from the same period last year. And we focused on three initiatives to keep LOE at low levels.

First, we continue to implement fieldwide smart gas lift intermitter system, which optimizes volumes of lift gas. Currently, approximately 85% of our wells are on gas lift and this helps reduce costs associated with downhole repairs and maximizes well uptime. Second, we also continue to expand our saltwater disposal system, or SWD system, which consists of 20,000 barrel per day injection well and approximately 22-mile water gathering system.

For every barrel of produced water we transport on pipe, we save approximately $1.25 per barrel versus having to transport via truck. And third, we continue to focus on maximizing the competitive advantages of our contiguous acreage footprint. This allows us to build out our SWD system more cost effectively expand centralized gas lift delivery maximize third-party pipeline takeaways for oil and gas and reduce labor cost by optimizing our workforce effectiveness. Also, it should be noted that substantially all oil and gas pipeline build-out costs are borne by our midstream partners.

Turning to Slide 13. I'm going to walk you through the Penn Virginia value proposition over the next several slides. Here we show our adjusted direct operating expenses on a per-barrel of oil equivalent basis. In 2018 we recorded $11.99 per BOE for our adjusted direct operating expenses. This is the sum of LOE GPT, which is gathering processing and transportation production and ad valorem taxes and cash G&A adjusted for some onetime items all of which is reconciled in the appendix on the presentation. That's down from $14.40 per BOE in 2017. We continue to improve on that number by lowering our cash cost to $11.88 per BOE in the third quarter.

Slide 14 shows our adjusted EBITDAX per BOE over time. For full year 2018 we generated $37.70 per BOE. For the third quarter we still generated strong margins even though WTI oil prices declined 13% since the end of 2018. We've benefited greatly from lower cost and premium pricing which is reflected in our cash margins. Importantly we expect to generate robust adjusted EBITDAX per BOE for the fourth quarter.

On Slide 15 we show the cadence of improvement in our financial position over the past couple of years. We have successfully driven our net debt-to-adjusted EBITDAX ratio down from 2.6x at year-end 2017 to 1.7x at year-end 2018. We expect the downward trend to continue with a targeted leverage ratio of approximately 1.6x by year-end 2019. The company is committed to maintaining financial discipline and a strong balance sheet.

Now over the next several slides we've provided Capital One's comparison of Penn Virginia to a large group of E&P companies that range from large cap to small cap. I should note that we are not endorsing or confirming any of Capital One's data. As you can see though Capital One has us projected to be one of the highest percent liquids producers in this large set of E&P companies.

And moving on to Page 17. We look at how Capital One ranks Penn Virginia as compared to the same group of companies when it comes to EBITDA per BOE. Based on this data we had the second-highest EBITDA per BOE ratio in this group. Bottom line our relentless focus on cost optimization is continuing to drive expenses down and generate strong cash margins.

On Page 18 as we turn to valuation metrics Capital One ranks Penn Virginia as having one of the lowest trading multiples compared to this list of companies. With our low-cost structure very strong cash margins low leverage ratio and a clear path to free cash flow during the fourth quarter and beyond we believe that Penn Virginia is an attractive investment that yields an upside opportunity for trading multiple expansion.

On Slide 19 we summarize the attributes that we believe make Pen Virginia quality investment. In this volatile commodity price environment you need to be profitable through all cycles we must maintain a lean and low-cost structure. And we believe Penn Virginia has one of the lowest cost structures for an oil-weighted E&P is exemplified by our third quarter 2019 adjusted direct operating expenses of $11.88 per BOE.

Our proximity to waterborne markets allows Penn Virginia to access premium priced markets as our crude oil realized 101% of WTI. Access to Corpus Christi by truck and the LLS and MEH markets by multiple pipeline access points help to maintain our strong price and combined with peer-leading low operating costs our third quarter 2019 adjusted EBITDAX was $32.64 per BOE. To survive and grow during turbulent times you must maintain financial discipline and preserve the balance sheet and we will continue to do so.

Our third quarter 2019 net debt-to-LTM adjusted EBITDAX ratio was 1.7x and we expect it to decline further. Finally Penn Virginia is unique in the small-cap space with the anticipate ability to drill within cash flow in the fourth quarter and generate significant free cash flow in 2020.

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

Question-and-Answer Session


[Operator Instructions] The first question comes from Irene Haas of Imperial Capital. Please go ahead.

Irene Haas

My question has to do with sort of Upper Eagle Ford you said your earth model has been completed. I'm just wondering how thick it is and sort of how extensive it is over your footprint.

John Brooks

Yes, we've identified roughly between 50 and 100 Upper Eagle Ford locations across our acreage. We hope to test at least one of those in 2020. However, we don't have a 2020 budget yet so it's hard to pin down the exact date of that test. As I said, it's 50 to 100 locations across our acreage. It's not really a thickness issue as much as a sweet spot issue. We've got 45 producing Upper Eagle Ford wells. And about 20% of those are among the best wells we've ever drilled. But it has more of a conventional geology response than an unconventional. So it requires the conventional geologic approach of understanding the geology the geophysics and petrophysics to identify the sweet spots. So none of our existing inventory reflect those adds, but we hope to get at least 1 test off next year.


The next question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.

Jeff Grampp

I was curious just kind of thinking about CapEx cadence going forward here just kind of based on the guide that you guys have and what you spent year-to-date seems to imply 4Q needs to be kind of like $60 million $65 million in that range, which is obviously a big drop from where you guys have been at for the first few quarters of '19. So I guess first I'm just kind of wondering if you can maybe walk us through kind of what drives that big drop. Is that kind of a batched completion timing kind of factor? And maybe if you could talk about assuming the constant two-rig pace how to think about kind of run rate quarterly CapEx as we move into '20 here?

Clay Jeansonne

Jeff it's Clay. On the CapEx range yes I think $50 million to $60 million kind of range in the fourth quarter when you kind of look at the guidance we put out for a yearly basis that significant decrease is relative to some of the service cost reduction or significant service cost reductions that we've seen in the fourth quarter. So that is a significant movement of that.

John Brooks

Yes, plus you might recall CapEx in the third quarter was a little bit higher as drilling efficiencies pulled in some additional wells that were previously scheduled in fourth quarter and they came into the third quarter. And so there's that component of that as well. They came in late in the quarter gives us some momentum here in the fourth.

Clay Jeansonne

And Jeff, I just want to -- when I said it's going to be a little bit closer to $60 million on that point on my low point was a little low on the CapEx.

Jeff Grampp

My follow-up on the land side of things it seems like a nice active quarter there. Can you guys talk about I guess kind of where that was within the footprint and where you're seeing more opportunities? Are they more in Area 1 versus Area 2? Or are there any kind of trends if any that you guys are kind of seeing for this more opportunities?

John Brooks

I think the bulk of the third quarter activity on the land was all focused in Area 1. And I think probably that's where we see the most opportunities to increase acreage and our working interest is going to be in Area 1. Area 2 has some opportunity but it's a little bit more tightly held.


Hello Don McIntosh, your line is open. Please go ahead with your question.

Unidentified Analyst

This is Don's associate, Austin. I was wondering if you all could provide some color around the 2020 pace of development. Do you all plan to complete the 5 DUCs at the beginning of the year or the further completion still later in the year?

John Brooks

Well, we would hope to maintain a normal operational cadence going forward. We don't have a budget for 2020 yet and so we're not releasing any guidance along those lines given the volatility in commodity price markets. But I think the idea would be to complete those at normal operational pace.

Unidentified Analyst

And then as a follow-up how do you all plan to use the free cash flow that you all would generate? Then do you all see any additional opportunities to continue to increase your overall working interest?

John Brooks

To answer the second question first yes we do see opportunities to increase the working interest out here and continue to consolidate our position. When we look at uses of free cash flow, I think first and foremost is getting there and we're well on our way to that. We want to ring that bell. And then what we do with those proceeds I think at this point the highest priority would be on paying down debt.


The next question comes from Richard Tullis of Capital One Securities. Please go ahead.

Richard Tullis

John, given the drilling efficiencies achieved over the past couple of quarters at least how many more net Eagle Ford wells do you think possible for Penn Virginia to drill and complete in 2020 compared to I guess roughly 40 or so in 2019?

John Brooks

Well, Richard, we don't have any 2020 guidance out there, because we don't really have a budget formulated. I mean think about it this way. I think in months past when we've talked about CapEx associated with a particular drilling rig I think we were thinking that was going to be around $150 million. And I think what we're seeing is that's probably going to be coming down probably in the neighborhood of maybe 15% or as high as 20% on a per rig basis for the 2020 if we maintain a 2-rig program.

Richard Tullis

And then how are you thinking about the enhanced oil recovery opportunity at this point? Any preliminary plans to maybe include some work there in 2020?

John Brooks

As we've mentioned, the engineering work is continuing, the capital commitment is something we deferred last year and we hope to make that at some point in 2020. But again, we don't have a budget for that yet.


[Operator Instructions] The next question comes from David Snow of Energy Equities Inc. Please go ahead.

David Snow

I'm just trying to do the math. But I guess if you were drilling at $120 million to $135 million per rig is I guess that means you will reduce the CapEx and probably maintain or increase the number of wells in '20?

Clay Jeansonne

Are you referring to that could be from drilling efficiencies, but I don't think we would accelerate a program to go from like, if you're talking about going from two to three rigs, no that wouldn't be the case. Any free cash flow generated from there would be used to reduce outstanding debt.

David Snow

Look as though you're going to drill more wells, because you're getting a better efficiency from your program versus the 40 or so in '19?

John Brooks

Well, remember in '19, we had three rigs running through the first quarter. So that was a little bit skewed to the high side. So we hope to have a little bit more color on 2020 early in 2020, and we'll speak to that in a little bit more detail then.

David Snow

And then I didn't understand the cadence for completing the 5 DUCs that would be earlier in the year?

John Brooks

Yes, it would be maintaining a normal operational cadence. We don't want to have any DUC inventory build over time.


This concludes our question-and-answer session. I would like to turn the conference back over to John A. Brooks, President and Chief Executive Officer for any closing remarks.

John Brooks

Well, we thank everybody for your time this morning and your interest in Penn Virginia. We look forward to talking to you again next quarter. Thanks.


The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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