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Marty Thalken - Generating Free Cash Flow in the Eagle Ford

Moneymakers Business Forum | 2019 Oklahoma City

Moneymakers Business Forum | 2019 Oklahoma City


Generating Free Cash Flow in the Eagle Ford. A Moneymaker Forum talk given by Marty Thalken, Protégé Energy III in Oklahoma City, Oklahoma on 4 April, 2019.

This presentation tells the story of Protégé’s entry into the Eagle Ford shale. Protégé began to focus its growth efforts on the Eagle Ford shale in late 2015 and acquired its initial asset position in September 2016. After comprehensive geotechnical study, including obtaining whole core and developing 3D models of existing wellbores, Protégé began a “testing of concepts” development plan. New concepts for these fields included aggressive completion optimization, a stack-stagger development in the Lower Eagle Ford, single bench tests of the Upper Eagle Ford, adding the Austin Chalk as a target, and current study of miscible gas injection EOR. All of this work and bolt-on acquisitions has resulted in over a 100% increase in production with very attractive well economics and free cash flow generation in 2019 and beyond.

Full Transcript

I'm going to talk about Protege III, which is our third private equity backed company sponsored by EnCap. You know, what I want to do is tell you our story. It's an interesting story, but one that many of you may not have heard. We started our business sort of looking everywhere, and ended up, in 2013 and 2014, beginning to build a position in the Utica and Protege II was a Marcellus and Utica focus company in southeast Ohio. And many of our team had experience in the Marcellus, primarily WPX, but I had experience in Protege II, and we built a position which we thought is very attractive. It was largely geologically-focused.

We had 3D seismic, we felt the rocks were good, the reserves were there, the economics would be good, and we'd be we began a program of development. And that was back when natural gas prices were north of $4 an m. NGL prices were very strong relative to WTI. Oil prices were also are very strong. And so the economics were good, and the problem in appellation, as you probably all know, the basin has just turned out to be too good.

You know, there's been too much gas found, and not enough takeaway capacity so the basis differentials really widened, and the economics just ran away from us. And so we had to refocus our efforts, and look elsewhere to find economic opportunities. And the good thing was our team had experienced pretty much everywhere we had worked, every basin in the US and Canada. We had worked internationally, Latin America, West Africa, and Europe. And so we had a lot of experience.

We knew what to look for, and so we began to decide where can we make money? And I think I trace it back to attending DUG Eagle Ford in the fall of 2015 in San Antonio. I attended the conference, I was the only one from Protege there, and the Eagle Ford just seemed to me to be a basin that was in the early innings, of a baseball game maybe third inning, and there was a lot of game left to be played, a lot of meat left on the bones. And so we began to focus our efforts on the Eagle Ford.

The hot plays at the time where the SCOOP and STACK, Permian, initially Midland basin, then Delaware, and somewhat the Bakken. And Eagle Ford was a bit out of favor, so we began to focus our attention there, which turned out to be good for us. Our first acquisition was after close to a year's worth of study. We acquired the new field assets in South Texas in the Eagle Ford play. In September of 2016, and at the time production was around 72 BOEs a day, roughly 120 wells. Pretty high rates per well. And we felt like there were over 300 plus drilling locations that we could economically develop, and then we also felt like there was upside opportunity for completions, and maybe even down spacing wells even further than what we had thought.

And so we went about executing on our thoughts and plans, and we did what a lot of companies do, and we created a plan for implementing much higher intensity completions in the wells we drilled. So we looked at, from a geologic perspective, obtaining whole core, picking landing points carefully, looking at new benches, build 3D models of the wellbores that existed, and then looked at tighter stage spacing, higher sand concentrations, tighter perf cluster spacing, the use of diversion, all those kinds of things that many companies do. And then went about drilling wells and implementing that plan. And so today, our production is around 13,000 BOEs a day.

We've grown our acreage position to about 46,000 acres, and we have over 400 plus remaining economic locations. So we actually have grown during the time that we've owned the assets. This map shows you where assets are located. We have three major field areas, one in West Asherton, in Dimmit county there to the southwest. Another significant position in southeast Atascosa county called Fashing Field, and then another position that we acquired through a merger with Cinco Oil and Gas, which is another EnCap portfolio company, now part of Protege, and sort of central to Western Atascosa. And area that we call Turkey Creek. So from a production perspective, west Asherton is around 52% of what we have, Fashing is around 35%, and Turkey Creek is around 13%.

So what do you do when you acquire an asset? Well, you study it technically, and you, I'm an engineer so I still like to build spreadsheets, and look at economics, and look at reserves, and talk about recovery factors and all those kinds of things. And so what we did was we began a methodical process of testing the concepts that we thought going into the acquisition. So in the first year we tested the southwestern area of this field, drilled a couple of wells, they were there infill wells between parent wells. And then also, in sort of the northeast central portion of the field, we drilled a four well pattern of stack stagger and in the lower Eagle Ford.

So we had two benches in the lower Eagle Ford we wanted to test. And we watched that performance for close to nine months, and then we began to drill some additional wells. In And the next round was in the northwest part of the field, as well as the southeast part of the field. And watched the performance of those wells, and then now this year, we're drilling more wells in the southwest, and more wells in the southeast. So a very methodical approach.

One of the things that was critical to us was we drilled a vertical pilot well in the center of the field, and we had the core analyzed by Von Gonten's lab. Very, very impressive lab by the way, if you're not familiar with it. And did a very, very thorough analysis of landing points, and where it was best to land these wells, and stay in zone. So we would pick landing points, and we had 10 foot windows within which we wanted to stay as we drilled those laterals. And that's a pretty tight window, and I would say on average we're probably in that window 95% to 98% of the time. So that's been successful.

Here is a look at our production for West Asherton. We were able to raise production 120% with 16 wells. That is from pre-acquisition rates, to the peak of the post-acquisition drilling program. And then we're currently still about 25% above the pre acquisition rate for this field.

Again, landing point was very critical to us. We took all of the existing directional surveys in the wells, we built histogram of each well's lateral to determine how much time each well spent while it was being drilled within a one foot interval within the targets that we saw. And so these histograms represent the length of time within each one foot interval, not time, the amount of footage within each interval that we drilled. So that was important to us, to make sure that we were spacing wells properly and landing in the right zones.

And then we also built three dimensional models of existing well bores. Now, we did all of this work before we drilled our first well. And so it's really, really important, you might think big companies do this kind of work. I started my career at Exxon, and you know we did a lot of big projects, we did a lot of technical work. This didn't exist and we acquired the property. There was no 3D model. The targets that the prior operator stayed within were probably 50 feet or so, 50 to 60 feet. So the wellbore is meandered a bit. And so it's important for us to know exactly where each wellbore was, so that when we plant a new wellbore, that we maintained standoff distances properly between the new ones, th4 child wells and the parent wells.

And then on the completion side, I mentioned that we looked at higher intensity completions. We acquired an asset that was developed with 602,000 pounds per foot fracs, and that's just the way they did it for probably three or four years, and didn't change. We pump 2,200 pound per foot fracs. We now pump a pretty much 100% 100 mesh sand in our fracs. We pump higher fluid rates, about two times what the prior rates were. We use 100% slick water, whereas they were hybrid gel for fracs before.

We had 200 foot stage lengths, prior stage lengths were 300 feet. Cluster spacing prior was 75, we use around 20 foot spacing. And we use diversion, primarily TTS wellbore diversion pods that you pump during your frac job. We are now experimenting with both wellbore diversion, as well as far fi4ld diversion, to see if we can get even better performance. And the results, we're drilling on average 10% longer wells or IP's 30s, or 30% better than before. IP30 is two-phased, 35% better in cum 12 month rates. Or 12-month cums are 32% better than they were before.

These graphs show in each quadrant of West Asherton, the relative performance of our wells versus the offsets in those specific areas. So in each area, we've done better. In some areas, we've done substantially better.

This graph shows an overall average of our wells versus the overall average of the prior wells. And we have over 400 days of history. And the average well is showing that it's maintaining a cum of greater than 25% above the prior well rates or prior well cums. And that leads to higher reserve recoveries and obviously better economics.

Some people ask about parent-child impacts and what do you do and how does it look. And for us, what we've done is we are very careful in shutting in existing parent wells prior to fracking child wells. And we'll do it on a timing basis.

So if we're drilling a child well, we'll shut in the parent wells offsetting some time in advance. And then the next layer out, we'll shut those wells in some less time in advance. And then the next layer out, we may or may not shut those wells in as well.

And so you can see in this graph, in this particular area, you can see the shut-in time prior to when that yellow curve shows new well production. So we had some amount of shut-in time. And you can see after those wells were fracked and brought on production that those parent wells have come back to the pre-production rates.

And then we had a second phase of drilling in this area. And you can see we had shut-in time. And you can also see that those parent wells are making a comeback. And they're effectively at the former decline rate that we had on all those wells.

So on an individual well basis, we certainly see frac heads. We certainly see some wells don't come back to pre-frac rates or pre-child frac rates. Other wells come back to levels above what they were producing before. But on average, we get back to where we were.

And so let's look at another area. Sort of the same story, we are pretty careful in shutting in wells to prevent as much impact as we can to the parent wells. You can see the two layers of infills and how those parent wells have recovered.

And so for us, it amounts to production deferral, not really reserve loss. And we've been pretty pleased. Now we attend technical conferences and we hear what others do about protecting parent wells. We would like to do even better than this, so we're testing areas where we actually pump into offsets during those frac jobs to see if that helps protect those parent wells even more. But I think so far we've done we've done pretty well.

Let's move to the other field. This is Fashing Field in Southeast Atascosa. It's jointly operated between us and XTO. And XTO has been very active here-- this is one of their focus fields.

In 2018, we had 12 new wells come online in that field. One was a chalk well, which was a new bench for us. We put no value on the chalk in this area in the acquisition, but the chalk is being developed in this area.

And to the east we're on trend with the really, really big chalk wells in the Karnes Trough. And we made some bolt-on acquisitions here as well. But this is to illustrate we're approaching this area of development methodically as well. We'll have 18 new wells turn online this year, 16 lower Eagle Ford, and two more chalk wells.

And this is a production performance of Fashing. We have increased production 85% with 17 wells from the pre-acquisition rate. And we're currently 52% above the pre-acquisition rate.

In the Fashing area, as I mentioned, we were developing the chalk as well as the lower Eagle Ford. It was important for us in our view to, again, look at landing points and make sure we're maintaining appropriate distances, standoff between the laterals.

We do think that the lower Eagle Ford here probably get some contribution from the lower Austin chalk, but certainly those wells don't drain the chalk. And so, again, it's important to look at what you're doing carefully, have very tight windows, be very precise in targeting, and then be very, very aggressive in your completions.

And this is the performance we see in Fashing Field. That lower curve is an offset group of wells that were drilled prior to our acquisition. The second curve, called A pad, those are the early 2018 wells. And you can see that those after not quite 300 days they are 25% better than the prior group.

And our late 2018 wells are doing even better. And having worked at Exxon years ago, and XTO obviously as is owned by Exxon, you might think that they're on the leading edge on what companies are doing in completions and targeting and things like that. To be honest, we spent a lot of time in their office convincing them to do things the way that we do things, the way we complete wells, the way we land wells, et cetera, et cetera.

And the reason we did that is because we own about 75% working interest in these wells that they drilled. So it was very important for us for them to get it right, and do it right. And you can see the results of us working together. XTO is a great operator, but I just would not necessarily put them on the leading edge of what companies are doing completion-wise.

This is the area of Turkey Creek, northwestern Atascosa. We have completed six wells in this area in 2018. We have one well that's a duck that's waiting on completion. That should happen within the next two months.

And in this area, we've increased production 170% with those six wells. So I would say it's another example of a methodical approach to testing an area that needs to be drilled and tested, and testing southwest, southeast, northwest, northeast, and doing it very methodically.

When I was at Exxon in Midland, Texas in the early '80s, one of my responsibilities was miscible CO2 EOR projects. And so EOR is how I grew up in the business as a reservoir engineer. And we're very intrigued by Enhanced Oil Recovery in the Eagle Ford.

And what I'm talking about is injecting produced gas, hydrocarbon gas, to above miscibility pressure, allowing that trapped oil to swell and reduce its viscosity and produce it to the wellbore.

And we are on trend with about 52 projects that so far are showing good success-- there's certainly a range of outcomes. But we're very, very interested. We're very, very excited about EOR on our acreage.

We've done all the PVT work, miscibility studies. We know it should work technically. And it's just a matter of doing the project.

So the title of my talk was generating free cash flow in the Eagle Ford. I've explained to you our history, what we've done, how we got to where we are. This page tells you a little bit from a cost perspective what how are we doing.

We acquired the asset in late 2016 on a going-in basis. We thought wells were going to cost a certain amount. We were in this ballpark in terms of cost per stage or fracking-- that's around $40,000 per stage, maybe slightly below.

And during the course of implementing all those projects, drilling all those wells, we saw frack stage costs go to $80,000 a stage. And that happened in a very short period of time. And what really drove that, it was the lack of sand. It was just the supply and demand driver that drove sand costs really, really high.

And then the other driver was the competitive nature of getting frac crews. The frac spreads were in limited supply and you had to pay up to get them, particularly if you're a small company and drilling and completing one-off wells, or maybe two small groups wells.

So we lived through that. And then we've also seen a lot of new sand mines come on production over the last 18 months. And our sand costs are now in the $.03 per pound ballpark. And so our costs are about what we expected them to be in 2016 for 2019. So that's a good thing.

The chart on the right is return on capital employed. And this is really a measure of the efficiency of how you invest capital. Early in this business, we were in the 15% to 16% range. The last two quarters we've tremendously improved that. The rates of return on our wells are in the 50% to 60% range and the efficiency of using capital right now is in excess of 25%.

And then this is my last chart. It shows Protege's growth. Since 2017, we've averaged 46% per year production growth on a net basis. On a going forward basis, what we're doing is we're looking at a more modest pace.

You've heard the equity investors today are really looking for free cash flow generation and yield, returning cash to the investors. And so that's what we are transitioning to. And by the way, we've increased our reserves or improved by 57% and our 3P reserves by 27% since we've acquired the assets.

But this year, we expect to yield around 60 million of surplus free cash after CapEx. And that's going to grow substantially over the next several years, even at a modest growth of 12% production growth per year. And over the next five years, we expect to generate $430 million of free cash. And we expect our equity value, based on a measure of what we think the company is worth today, we expect to raise that equity value by 55%.

And so when you translate that into returns, it's very attractive. It is very, very attractive to private equity. It's going to be very, very attractive to public companies. It's going to help.

And obviously we're a private equity-backed company, so we need to look for our exit. And I think created a business that I think that's going to be very attractive to whoever the buyer is. So with that, I'll close. Any questions?


Question. Here. Hi, I'm Dan Newman from JX Nippon. Wonder if you could comment a little about your operations expense? Do you have an estimate of what your OpEx is per BOE? And how are you keeping your operations expense minimized?

Good question. I mean, our LOE per BOE, that's total lifting cost plus taxes-- it's just under $8. Our revenue on a BOE basis is just over $40-- $41 to $42.

The way we keep it low is our well count is low. And the wells generally are flowing. We have a fair amount of wells on gas lift, but many of the wells are flowing.

And so it's a great business, it's a low cost business. One thing that was really, really good in the Newfield acquisition is we acquired an infrastructure capable of producing 40,000 to 50,000 barrels of oil a day. All we have to do is drill wells, connect them to three-phase separators, time into the gathering system, and we're off producing new production.

We also acquired a very substantial water source infrastructure-- source wells, frac ponds, distribution systems. So those infrastructure costs that many companies have when they enter a new play, it's already there for us. So we don't have to invest dollars in those things.

Any questions?

And as you neared your target window from 50 to 10 feet, did you give up a rate of penetration? And did that affect your day's drilling?

Well, I would say initially we did, but we got better at it. It's amazing-- our time to spud rig release is around eight and 1/2 days at this point. We're drilling laterals with a penetration rate of over 2,500 foot per day, approaching 3,000 feet per day and staying within that zone.

Joe Brevetti, Charter Oak Production, engineer by background. And actually, I've worked on some wells in that field back in the '70s in the early days. You cited three methods for improving your production. One being removing the gel, one being the increase in sand, the third one being the decreasing in your per cluster spacing. Did you do any testing to see how those ranked, which was having the most effect?

No, we really haven't. We've experimented with different types of sand. We went from one pod drop in a stage to as many as three for a diversion. We have changed the kind of high vis FR that we're using. But we've not done anything with regard to testing one of those parameters and see how it compares to changing another parameter. We've not done that.

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