Q3 2019 Earnings Call

Good day and welcome to the Penn, Virginia third quarter 2019 earnings Conference call.

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Please note this event is being recorded.

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

Thank you Andrew and good morning, everyone. We appreciate your participation in today's call I'm Clay you also director of Investor Relations and I'm joined this morning by John Brooks, and Virginia's President CEO and Ben Mathis, Our senior Vice President of operations and engineering.

We will discuss non-GAAP measures on this call.

The nations 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 and the forward looking statements section of the press release, which was released yesterday afternoon.

Comments today will contain forward looking statements within the meaning of the federal Securities Law. This statement. 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-Q 's.

Cautionary language is also included on slide one 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 .

Thanks <unk>.

Let's start on page three with a quick company overview.

Penn, Virginia, as a pure play Eagle Ford shale, operator, and Gonzales fat Lavaca into it counties in South Texas.

We have approximately 100200 gross acres and 87300 net acres in the Eagle Ford, which is approximately 91% held by production and 99% of which is operated by Penn Virginia.

Our estimate of drilling inventory on September Thirtyth, 2019 was 500 gross or 440 net locations.

And I want to point out that this inventory count is only for the lower Eagle Ford one of our goals for our land in technical team is to continue replenishing that inventory through organic acreage leasing small acquisitions as well as acreage swaps with Jason operators. Yeah. We also hope to increase that count by identifying identifying additional look.

Okay should inventory in the upper Eagle Ford and chalk from our recently constructed Earth model.

Our product mix and the third quarter was 88% liquids.

Which 73% was oil.

Penn, Virginia as oil production receives premium, Louisiana light Sweet, which we sometimes referred to as LLS or Magellan East Houston also referred to as MGH pricing, which enhances our adjusted EBITDAX margins.

Currently running two rigs in one dedicated frac spread we are targeting year over year production growth for 2019 of 25% to 30% and we're well on our way to achieving that target based on the first nine months results.

So let's move on to page four take a closer look at our solid operational and financial performance for the third quarter.

For the first nine months of 2019 production averaged 27196 barrels of oil equivalent per day.

Which represents a 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 MGH markets, which resulted in a third quarter realized oil price to $57 in 12 cents.

This is approximately 68 cents higher than or 101% above the average W.G.I. price for the third quarter.

For the balance of the year, we expect about premium to moderate and expect realized pricing to be at parity with W.T.I. or up to $1 off.

The judge 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 be are we.

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 you for the first nine months of 2019, and that's a 6% improvement year over year.

Our growth in adjusted EBITDAX allowed us to improve our leverage ratio to 1.7 times as compared to 1.9 on September Thirtyth 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 five we believe there four keys to Penn Virginia has 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 the MP.

Secondly maintained strong margins.

As I mentioned previously our close proximity to the Gulf Coast allows Penn Virginia to access premium priced markets.

This includes accessing Gulf coast waterborne market, such as Corpus Christi by truck and the LLS and MGH 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 in our strong balance sheet growing production, while drilling within cash flow is a great example of that.

And finally, the most important measure generate free cash flow ultimately you must live within your means 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 approving small cap with a clear path to free cash flow generation in the near term.

On page six and turning to our capital budget for 2019.

Our capital budget is currently estimated at 350 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 entities small working interest in three.

Recently proposed wells.

These increases in working interest account for approximately $4 million to $5 million an 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 in 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.

In turn in line 48, gross and 43.2 net wells.

In the fourth quarter, we expect to drill 11 gross wells 9.6.

Net wells in turn in line 11, gross and 9.9 net wells.

We continue to realize significant drilling and completion efficiencies due the outstanding work of our operations team our previous estimates had Penn Virginia, ending the year with zero drilled, but uncompleted or ducs, but given these efficiencies we expect the in the year with up to five Ducs now.

We have seen significant decreases in overall drilling and completion costs comparing the third quarter of 2019 to the third quarter 2018, we saw drilling and completion costs were reduced by approximately 18% to 21%. We're benefiting from additional service cost reductions in the fourth quarter is some of our service contracts have been renewed.

Associated and we expect these service cost reductions to continue into 2020.

Moving on to slide seven organization is committed to lowering cost 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 few slides in the third quarter. We have continued to improve upon our drilling and completion metrics.

Drilling exceeding our drilled feet per day targets and completions exceeding our target for stages pump per day.

The two charts on page seven illustrate to improved operational execution of our technical team over the last several years and in the third quarter.

In area, one where we primarily drill two stream wells, that's where we've seen the biggest picked up our average feet per day has improved dramatically by approximately 69% over 2017.

In area to where we drill three stream wells our average fee per day is 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 a running casing and this compares 2017 to the first three quarters of 2019.

The three will add 600 pad that was drilled in the third quarter was the best drilling performance to date and everyone 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 support improvement of roughly 119% over 2017 performance in area one.

The cost to drill complete and equip the attics hundred wells on a cost per completed lateral foot basis averaged about 20% less than area. One wells drilled in the first half of 2019.

Moving on to slide eight 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 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 two 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 in the previous pages illustrate that we've continued to focus the organization ways to improve efficiencies and drive cost down while still maintaining a safe work environment.

On slide nine.

As I mentioned in my brief comments on the company overview slide one of our goals for the Penn Virginia land in technical teams 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 3000 to 4000 net acres per year.

In 2017, and 18, we added 3366 and 4336 net acres respectively.

So far in 2019, we have added approximately 3321 net acres. We continue to work on several additional transactions 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 in 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 has a solid black line plodded above the net location bars in the graph at the bottom right. We refer to that as total net treatable lateral feet. We have also been successful increasing that number the last several years.

We can increase net treatable lateral feet in several ways by adding inventory through leasing swaps acquisitions, including the acquisition of additional net interest in our existing gross inventory and through delineation drilling.

Another part of the ground game has defined areas, where we can increase lateral links, thereby increasing total treatable lateral feet.

As previously discussed we recently made an acquisition of approximately 1420 net acres, which included additional working interest in 109, producing wells as well as an additional 43000 feet of net treatable lateral.

We've completed the first phase of constructing our Earth model as you may recall from prior discussions the Earth model combined petrophysical data the seismic data well logs and other downhole information to more accurately mapped to subsurface geology of our acreage position.

This allows us to generate a three dimensional view of the sub surface 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 well most of our early technical.

Efforts have been focus we look forward to keeping everyone apprised of our efforts on this important initiative.

Moving onto page 10, unlike other basins in the US the Eagle Ford has many crude oil delivery points and virtually no pipe on constraints.

Penn, Virginia is an enviable position geographically as well as geologically as all of our production receives premium pricing that is either Ll F MGH Dwt Houston.

We have access to kinda Morgan in enterprise products pipelines, which delivered directly into the Houston markets.

We also have the ability to deliver crude to the Phillips 66 refinery and Sweeney into 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 68 cents above WT.

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 MP 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 EMEA each market.

And as of yesterday LLS is trading at a $4 premium to W. tie in EMEA is trading at $3.41 premium to WT.

Moving onto page 12, we believe Penn Virginia has one of the lowest levels of LOE per BOE, we in our peer group and the industry, especially given our heavy weighting to oil.

For the first nine months of 2019 LOE per BOE. He was at $4 at 48 cents per BOE eight down 3% from the same period last year.

And we focused on three initiatives to keep Ela, we at low levels.

First we continue to implement field wide smart gas lift intermittent system.

Which optimizes volumes of lift guest currently approximately 85% of our wells are on gas lift and this helps reduce cost associated with downhole repairs and maximizes well uptime.

Second we also continue to expand our salt water disposal system or SWT system.

Which consists of a 20000 barrel per day injection well approximately 25 mile. Obviously as me 22 mile water gathering system for every barrel of produced water, we transport on pipe, we save approximately a $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 SWT system more cost effectively expand centralized gas lift delivery maximize third party pipeline takeaways for oil and gas and reduce labor costs by optimizing our workforce effectiveness also.

Should be noted that substantially all oil and gas pipeline buildout costs are borne by our midstream partners.

Turning to slide 13 are 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 a day for our adjusted directed direct operating expenses. This is the sum of low 80.

PT, which is gathering processing and transportation production and AD valorem taxes and cash DNA adjusted for some one time items all of which is reconciled in the appendix on the presentation.

That's down from $14.40 per BOE in 2017, we continued 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, we overtime for full year 2018, we generated $37 in 70 cents per Boe easy.

For the third quarter, we still generated strong margins, even though WT 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, a for the fourth quarter.

On slide 15, we showed the cadence of improvement in our financial position over the past couple of years, we've successfully driven our net debt to adjusted EBITDAX ratio down from 2.6 times at year end 2017 to 1.7 times at year end 2018, we expect downward trend to continue.

With the targeted leverage ratio of approximately 1.6 times by year end 2019.

The company is committed to maintaining financial discipline strong balance sheet.

Now over the next several slides Weve provided capital one's comparison of Penn, Virginia to a large group of S&P companies that range from slots cap to small cap I should note that we are not endorsing are confirming any of capital one's data.

As you can see though at capital one has us projected to be one of the highest percent liquids producers in this large set of S&P companies.

And moving onto page 17.

We look at how capital one ranks been Virginia as compared to the same group of companies. When it comes to EBITDA per BOE. We based on this data we had the second highest EBITDA per BOE ratio in this group.

Bottom line, our relentless focus on copper cost optimization is continuing to drive expenses down and generate strong cash margins.

On page 18, as we turn devaluation metrics capital one ranks Penn Virginia is 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 in the trial.

Active investment that yields an upside opportunity for trading multiple expansion.

On slide 19, we summarize the attributes that we believe make Penn Virginia quality investment in this volatile commodity price environment, you need to be profitable through all cycles, you must maintain a lean in low cost structure and we believe Penn Virginia has one of the lowest cost structures for an oil weighted MP his input exemplified by our third quarter two.

Thousand 19, adjusted direct operating expenses of $11.98 for B.

Our proximity to waterborne markets allows Penn Virginia to access premium priced markets as our crude oil realized 101% of WT.

Access to Corpus Christi by truck in the LLS in EMEA H. markets by multiple pipeline access points.

Helped to maintain our strong price and combined with pure leading low operating costs. Our third quarter 2019, adjusted EBITDAX was $32.64 per be a week.

To survive and grow doing 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 1.7 times and we expected to decline further.

Finally, Penn Virginia is unique in the small cap space with the anticipated 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 and a portion of the call.

We will now begin the question and answer session to ask a question you May Press Star then one on your Touchtone phone.

If you're using a speakerphone please pick up your handset before pressing the keys.

If at any time your question has been addressed and you'd like to withdraw your question. Please press Star then too.

At this time, we will pause momentarily to assemble our roster.

The first question comes from Irene Haas of Imperial capital. Please go ahead.

Hello, My question has to do with them.

The upper Eagle Ford You said model has been completed and just wondering how stake it is sort of how extensive it is over your.

Thanks.

Thanks, Irene Yes, we've identified.

Roughly between 5900 upper 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 to exact data that test.

As I said, its 50 to 100 locations across our acreage our acreage, it's not really a sickness 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 in the unconventional.

So that requires.

The conventional geologic approach of understanding the geology geophysics Petro physics to identify the sweet spot so.

None of our existing inventory reflects those ads, but we hope to get at least one test off next year.

Great. Thank you.

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

I guess.

Okay.

I was curious just kind of thinking about capex cadence going forward here just kind of based on.

Hi that you guys haven't and what you spent year to date seems to imply fourq you needs to be kind of like 60 65 million in that range, which is obviously a big drop from where you guys have had been app for the first few quarters of 19. So I guess first and just kind of wondering if you maybe walk us through kind of what what drives that big drop is that kind of a batched completion timing.

On a factor and maybe if you could talk about assuming that constant to rig pace, how to think about kind of run rate quarterly capex as we move into 2000 here.

Yeah Jets clay on the Capex range I think that is 60, knowing kind of range in the in the fourth quarter. When you kind of look at the guidance, we put out for a yearly basis.

You know that that significant decrease is relative to some of the service cost reduction nurse significant service cost reductions that we've seen in the fourth quarter. So that that is a significant movement of that yes, plus weve you might recall capex in the third quarter was a little bit higher as we 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 a momentum here in the fourth.

Got it as yet I just want to I'm, sorry, when I said, it's going be a little bit closer to 60 million on that on that point by low point was a low.

Okay on the got out under understood.

My follow up on the on the land side of things.

I got a nice active quarter. There can you guys talk about I guess kind of where that where that was within the footprint and where you see more opportunity. There are they more and area one versus area too or are there any kind of.

Trends if any that you guys are kind of seeing on where there's more opportunity.

I think the bulk of the third quarter.

Activity on the land was all focused in area one.

And I think probably that's where we see the most opportunities too.

Increase acreage in our working interest is going to be an area one area too.

Has some opportunity, but its little bit more tightly held.

All right appreciate it and I. Thank you.

Thanks, Jeff.

Well.

Done Mackintosh. Your line is open. Please go ahead with your question.

Hi, Good morning, this is done associate Oscar.

I was wondering if you all could provide some color around that 2020 pace of development ideal plan to complete the five bucks at the beginning of the year or defer completions to later in the year.

Well, we would hope to maintain the normal operational cadence going forward, we don't have a budget for 2020 yet.

So we're not releasing any guidance in that nature in along those lines.

Given the volatility in commodity price markets, but.

I think the idea would be to compete with those a normal operation pace right. Thank you and then as a follow up how do you all kind of use the free cash flow that you all the generate then delphine additional opportunities to continue to increase yells working interest.

I'll answer the first dancer. The second question first yes, we do see opportunities to increase the working interest out here in consumers continue to consolidate our position.

When we look at uses of free cash flow I think first and foremost is is getting there and we're well on our way to that we want to ring that Bell and then what we do it those proceeds I think at this point the highest priority would would be on paying down debt.

Gotcha. Thank you very much.

Thanks.

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

Thanks, Good morning, everyone.

John given the drilling efficiencies achieved over the past couple of quarters at least.

Any more net Eagle Ford Wells do you think possible for for Penn, Virginia to drilling completed 2020 compared to I guess, roughly 40 or so in 2019.

Well you know Richard we don't have any 2020 guidance out there, but because we don't really have a budget formulated but I can let me 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 thank.

And that was going to be around a 150 million and I think what we're seeing is that's probably going to be coming down probably in the neighborhood, maybe 15 or as high as 20, 20%.

On a on a per rig basis for the for the 2020, if we maintained a two rig program.

Okay. That's helpful.

And then how are you thinking about the enhanced oil recovery opportunity at this point any.

Any preliminary plans to may be included some work there in 2020.

Yes, you are as Weve.

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 as again, we don't have a budget for that yet okay. Let's off from me John Thank you.

Thanks Richard.

Again, if you have a question. Please press Star then one on a touchtone phone.

The next question comes from David Snow of Energy Equities, Inc. Please go ahead.

Yeah, I'm, just trying to do the math, but I guess, if you were.

Drilling.

At a 120 to 135 million per rig.

As the I guess it means you will reduce the capex and.

Probably.

Maintained or increased the number of wells.

And Tony.

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 noted that wouldn't be the case.

Any free cash flow generated from there would be used to reduce outstanding debt.

Okay, so you're going to drill more wells, because you're getting a better efficiency from your.

Program and versus the 40 or so in 2019.

Well remember 19, we had three rigs running through the first quarter. Okay. 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 little bit more detailed them.

And then I didn't understand the cadence for completing decide ducs that would be earlier in the year.

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

Thank you.

This concludes.

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.

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.