Very glad to be here today. As Rick mentioned, my name is Chris Carson. I'm
the Vice President of Exploration and Geology at Casillas Petroleum. And when
you're a CEO as a geologist, you get to get cool fossils as your logo and on
your slide background. Again, very happy to be here today-- I'm going to step
through a few aspects of our play and what we've accomplished on our asset-- on
our SCOOP asset over the last four years.
I'll open up with a little bit of who we are today, who we've become over
the last four years; discuss our corporate track, which is just our pathway to
achieve what we've done so far; and close with a few bullet points on what we
feel like our keys to execution and what we feel life has been the foundation
of how we built this company. We do like to see ourselves as a bit of a
contrarian in the private equity energy space in our philosophy approaching
assets, in our philosophy approaching staffing, and really our staffing and the
way that we built the company for an investment time frame.
In 2016, we were initially funded by Kayne Anderson around a 10,000-acre
Chesapeake acquisition. We're currently at about 46,000 acres. It's 100% HBP.
We've drilled 50 wells. We've completed 42 of those. Our current net daily
production has a little over 17,000 BOE per day. We have three rigs running. I
think it's actually four today. We started making hole with a fourth rig and
are currently in the middle of developing the second of three co-development
The company was originally founded by Greg Cassius in 1986 and run as
largely a standalone shop. It's very successfully growing throughout the
mid-continent. In 2014, we reformed the company around a new management team
designed to focus on lower 48 unconventional resource exploration.
Inspired by some results we were exposed to in the STACK Meramec Play, we
initiated a regional exploration study of the clastic phases of the Mississippi
and reservoir, employing our exploration model that I'll discuss in a little
more detail for roughly six months until we've defined and tiered several entry
points into what we thought were economic plays that met the criteria of our
Starting in September of 2015, we were approaching those entry points. By
October of 2016, we had closed on roughly 45,000 acres-- the initial 10,000
from Chesapeake and additional 30,000 acres from Continental in the SCOOP Play.
The slide that you see here is an integration of our corporate timeline, our
BOE per day growth through time calibrated to that timeline.
And juxtaposed in the background here is WTI Oil. The management team had
come together right about here. So we had several months of this roller coaster
looking, you know, at JP Morgan every day trying to speculate where the oil
price floor was, just like everyone else.
We were negotiating PSAs to close on 45,000 acres about here. Thanksgiving
and Christmas was a difficult time there for a couple of months for everybody
in the office. But obviously, you know, belief in the commodity, belief in the
industry really-- we kind of wiped that little low point out of our memory
right there. And we all kind of felt like we had a vision for moving forward.
So where we find ourselves today in January of 2019 is a corporate shift to
spacing test and development density testing to define drainage areas and
appropriate density spacing so that our next shift occurring at the end of this
year full road development of the asset.
A little bit about our reservoir construction and orientation-- we are in
core SCOOP. The core SCOOP Basin really initially developed the Woodford here
by Continental and Newfield, starting, I think, in 2012 is bounded on the west
by the Carter Knox Anticline, on the east by the Pauls Valley Uplift, where the
Pennsylvania nonconformity truncates all of our reservoirs-- all of our current
The SCOOP Basin is really kind of-- is a sub-basin that bridges the gap
between the structurally controlled basins of southern Oklahoma and the broad
Anadarko Basin of central and northern Oklahoma with properties-- pressure,
temperature, gradient properties more appropriate to compare it to I feel like
the southern Oklahoma basins.
The Woodford and Sycamore Reservoirs range from about 16,000 to 8,000 feet
across this structural ramp. The Source Rocks-- the Woodford and Caney Source
Rocks have been dropped into a fantastic hydrocarbon kitchen here. The adjacent
reservoirs in the Sycamore, the Upper Woodford, and the Hunting provide a
migration pathway-- flow unit migration pathway for hydrocarbons exiting the
kitchen here, migrating upward, and trap against the young conformities, where
to the east up against the Pauls Valley Uplift-- again, more components of our
exploration model definable trap that satisfied on a regional scale in this sub-basin.
The Sycamore, as I mentioned, was the focus of our early study on the
clastic Mississippian facies. The Sycamore is the reason that we're here.
Components of the Sycamore that we analyzed that satisfy our exploration model
are lateral continuity for execution, TDD and pressure range that indicate
hydrocarbon deliverability, a thickness in porosity that indicates sufficient
storage volumes for unconventional potential, calculatable storage volumes. We
had our definable regional trap that I had mentioned and an identifiable source
of migration pathways.
The Sycamore itself we pick at the tops of this resistivity spike and the
top of the Woodford. The Sycamore, then, is bound by the organic rich oil
mature Caney above and of course, the organic rich oil mature Woodford below,
as well as having interbedded TOC in the upper part of the Sycamore that is
its-- additionally oil mature providing carriage and porosity and storage in
those zones too.
One important tier of our exploration model is identifiable or definable
hydrocarbon deliverability from the reservoir. And we typically rely on
vertical wells if you don't have core analysis, sample analysis, et cetera to
define that. The decline curve on the top right is an average of about 150
vertical Sycamore wells in the Golden Trend that is across a 30-year-- their
time normalized across a 30-year production life. The terminal decline on those
wells is less than 10%-- single digit terminal decline.
If I can define a resource in place-- a pressure regime-- and understand
that the vertical wells are doing a very ineffective job of draining the
reservoir, our red flags go up on unconventional resource Play potential. The
Woodford Play underlying the Sycamore-- the map on the right shows the status
of the Woodford Play when we got here in 2016.
The deeper part of the SCOOP Sub-Basin was being developed by Continental
Newfield and Marathon in the gas window-- again, multiple components of our
exploration model satisfied by this-- consistent thickness, lateral continuity
across the acreage block, definable regional trap, known maturity and product
mix within the Woodford. So our Play concept was quite simply expanding the
Play from the gas mature window in the deeper part of the basin towards the
east into the shallower updip oil mature portion of the Play.
So across the West-- what, would I say 2 and 1/2, 3 years-- the 42 wells
that we've drilled are arranged as such across this acreage block. The table on
the left side of this slide only numbers the wells that have an IP30 of greater
than 1,000 BOE per day. You can see a range of product mixes on this IP30 if
you can read those percentages. They range from 11% to as high as 70% oil on
the IP30 on these 1,000 barrel a day wells.
Those wells are landed across four different flow units in the Woodford and
Sycamore-- Upper Sycamore, Lower Sycamore, and Upper Woodford, and a Middle
Woodford target. We've completed 16 Sycamore wells, 26 Woodford wells using
core analysis and mostly sonic logs-- log analysis, mechanical properties.
We've identified mechanical barriers internal to the Sycamore between the
Woodford and Sycamore and internal to the Woodford, giving us confidence that
we are exploiting reasonably discrete flow units in multiple benches in each
As we move forward into this, I've mentioned moving into our spacing tests
and our co-development. We firmly believe that STACK Stagger co-development is
going to be required for maximum capital efficiency in development of the
asset-- that while the reservoirs don't necessarily drain each other, you don't
want to come try to develop Sycamore on top of previously developed Woodford.
So those 42 wells across simply we've drilled since 2016 have resulted in a
production growth that we're pretty proud of. We started out 2016 at about 200
barrels a day. Today we're at about 8,000 barrels a day, 8 million a day in
gas, and over 100 million in gross gas today. We exited the year at 17,000 BOE
per day. We plan to exit 2019 at over 30,000 BOE per day. That is the result of
two of our co-development spacing tests coming online-- one this summer and one
My VP of engineering threw out this fun fact yesterday-- that since 2016,
our horizontal wells alone have contributed 3.9 million barrels of oil and 42--
49.2 BCF of gas to the hydrocarbon market. He actually told me by Friday, it'll
be 450 million Bs. That production growth is supported by the shallow decline
nature of the wells. We didn't plan for this. This was, I guess, a pleasant
surprise. Our initial type curves entering the area had a much steeper initial
decline, more in line with what you'd expect to see in an unconventional Play.
The-- Sycamore on the top-- the top two wells are Sycamore wells. The bottom
two are Woodford wells. We're seeing it across the reservoirs. Those declines
are in the range of 25% to 35%, first 12 producing months of declines. Flat
declines like that produce type curves that look like this.
We have multiple type curve areas since we have a broad range of depths of
reservoir. The product mix changes. Deliverability doesn't change
significantly. But we do have a range of type curves. These represent averages
for our Woodford and our Sycamore type curves. The wells included here are not
simply our operated wells-- as it notes, 52 wells included to create this
Woodford type curve, 23 wells to create the Sycamore type curve.
Type curves produce around 1,500 BOE per day, EURs between 2.5 and 2.9
million barrels. That's a three stream EUR that is heavily reliant on the
liquids rich nature of the gas. So there are a lot of NGL barrels in that 3
million barrel EUR-- rates of return from 60% to 80% with a $24 break even at a
15%-- pretty sure it's a 15% rate of return and those 26% to 37% first year
declines that I mentioned.
Those break even rate of return when adjusted to kind of a more industry
comparable average-- let's say this a 30% a tax rate of return put our asset,
our type curves right in line with Midland Delaware Basin economics, outpacing
most of the Plays currently being pursued in the lower 48.
Supporting the economics that we saw, the 60% to 80% rates of return-- we
have been turning knobs since day one on our drilling completion styles. Our
first-- two of our very first wells that we produced or that we completed are
honestly a couple of-- are in the top quarter of our best wells. So we have
been able to adjust our frac style in an attempt to change volumes, change
procedures, while attempting to maintain those EURs.
To date, we have not seen an EUR degradation with our cost saving measures
we've implemented to date. Our original AFE when we entered the project for
between a 5,000 to a 10,000 foot lateral was $6.7 million to $10 million
dollars. We've dropped those AFEs. That $10 million AFE we believe now with
changing fluid volumes, changing proppant sizes, local sand availability, et
cetera-- we've cut $1 million off of that AFE.
Our go forward development plan includes 877 total locations-- 563 Woodford,
314 Sycamore. That's executable, I think, at a 5 rate program over the next
some 15 years, I believe. Our takeaway availability-- we've entered into
hydrocarbon takeaway agreements for both oil and gas.
ONEOK has been a great partner for us out here. They have invested
significantly in gas takeaway infrastructure. They've constructed 3 new plants
in and around our asset, installed loops, 20-inch trunk lines between those
plants so that if we have a shutdown at any one point, we simply flow at the
other direction, ultimately delivering to their Maysville facility in Garvin
We'd initially entered into an agreement with Velocity Midstream, which is
now enable after their acquisition. And Velocity invested significant capital
in their infrastructure out here. We have dedicated oil takeaway to CVR's
refinery in Wynnewood with additional dedicated space in case we need it to
CVR's refinery in Coffeyville through Cushing.
The spacing tests that we've been working on that we're moving, that we're
using to test our full development schedule-- the first of which was our Bud
Dilly Spacing Test, which if you watched the Super Bowl commercial, you know
how we named our wells-- it will be the first co-development in SCOOP.
We're testing at 12 well per unit spacing in the Woodford by drilling 6
stacked staggered wells. We're testing 8 well per unit spacing in the Sycamore
by drilling 3 stack staggered wells. Right now we have 8 of those wells drilled
and cased. We have one well still drilling. And we're expecting first
production to come online this summer after a-- what do I want to call it-- a
massive industrial completion operation on 3 surface locations for 9 wells,
which is starting right now. We're staging that now.
Our second co-development spacing test we have spud right now-- the Titan
PAPI. We are, again, turning a knob, testing 10 open unit spacing in the
Woodford and 6-wall per unit spacing in the Sycamore. If 2 wells drilling,
obviously 7 wells remaining-- that pad will come online in October of this year. We'll see first production on that.
Since 2016, we've brought on wells at a pace of about 2 per month-- 2.5 per
month on average. Dedicating all three of your rigs to singles spacing test
development takes us off of this fairly steady growth trajectory and puts us on
this spiky trajectory that we see going forward as our projected. We honestly--
like I say, we've been in at about 2 per month. And now we haven't brought on a
wells since February right now, which is a long time for us-- also creates a
spiky nature in your quarterly EBITDA, which we'll see our first quarterly
EBITDA decline in Q1 of 2019 with that kind of delay in production volume increase.
What will be nice in the last half of 2019, when we bring on both of those
pads, we will enter into cash flow positive territory for the first time. We
may just-- it may be a temporary getting our head above water there for a
moment. But in 2020 with the third pad coming online, we expect to be cash
flow-- solidly cash flow positive for the remainder of the year.
So I'll touch on a couple of notes about how what we felt like were the
important keys that we implemented to create the corporate growth that you've
seen here. The flat structure of multidisciplinary teams has been key to this.
We do not have geology engineering and land silos-- no silos by discipline. We
have multidisciplinary teams that have defined area of responsibility but
overlapping areas of execution.
These teams have to have open communication with shared goals that has to be
demonstrated by the leadership. I can't say enough about my, what, five now--
five business partners on our management team and the level of communication
that we have and really the selfless nature of the guys that I work with. I
think the demonstration of that leads to team behavior-- that is, people you
want to work with. We have to have professionals that want to come in and want
to work with the people that they are assigned to create value for every day.
We invest in a culture-- by invest, I mean time, money, and resources. We
invest in our culture that inspires camaraderie-- camaraderie that creates
accountability, accountability that is addressed with intellectual integrity.
My colleagues that are here today will tell you that I use those two words ad
nauseum-- intellectual honesty-- approaching our problems with intellectual
honesty, quitting when you need to quit, moving ahead when you need to move ahead.
And then you can see how our teams overlap in so many ways. And I like to
think that the overlap bubble here-- that is where the execution is-- our
reservoir teams made up of engineers and geos, our operations team with
influence from geology and engineering-- land and legal likewise. And behind it
all, providing a foundation to make sure that the track is still being laid
ahead of the train is our finance group.
I mentioned our exploration model. It's a model that we implement not to
create barriers but-- or stifle creativity or certainly not to dampen
enthusiasm. Largely, our exploration model keeps managers from asking stupid
questions ahead of their time. You don't want-- you can't have a new ventures
guy asking where your oil in place map is when you're sitting there sketching
on the back of a napkin during a work session and trying to be enthusiastic and
generate enthusiasm about an idea. It's something that we believe in. It's not
Source charged trap storage deliverability hazards-- we evaluate those
differently for source-- we weight those differently for Source Rock versus
migrated Plays. And it's something that we implement when evaluating these.
Another key-- or the foundation I mentioned is our financial group. We were
initially funded by Kayne Anderson, as I mentioned, for that $250 million.
We've raised an additional $275 million from them. We've raised our own capital
alongside that. We have co-invest partners for a total of-- a little over $500
million in available capital. I think as it was mentioned earlier, they
obviously did not write us a check.
Our credit facility is led by Wells Fargo. We've been operating out of that
credit facility since December of 2017 when we had enough PDP base to justify a
credit facility that would fully fund our GNA and our operations. Our hedging--
we're currently hedged at about 75% of our crude NGL and natural gas volumes
are with a mix of swaps and colors that's adjusted seasonally based on product
available-- hedging product availability and market demand for product. We
employ Aegis Energy Risk advisors. They provide us market analytics, hedging
recommendations, hedging execution. And they also do our back office reporting
on our hedges.
I'll finalize this and conclude with the rules that I feel like that we
broke going into this to create a private equity company. First, we focused on
the reservoir. In our shop, rock is king. With the returns that we have to
provide in private equity energy space, tier 1 rock is about the only thing
that's going to work. We completely focused on the rock. We were unwilling to
do a deal simply to get a deal done, simply to cover our GNA, simply to get
investors signed up. We were unwilling to approach something that we did not
feel like was tier 1 rock.
Second, we formed a team and developed an idea before we were funded. We
actually even won a bid process before we were funded, which started our trip
on the road, as Barry mentioned earlier. Only I think ours was seven days. And
it was a whirlwind. We had a 260 page investment book. We are a very
technically oriented team. We took that investment book out and to most of the
private equity shops that you guys all know, put most of them to sleep, as I'm
doing to you right now. And it was definitely hit or miss.
I haven't known the Kayne Anderson guys nearly as long as Barry has. So I'm
going to say some nice things about them.
When Kayne Anderson came into our office for that meeting, they had as many
industry experienced petroleum engineers at the table as they did finance guys.
We started in on our 260 page book. And they were the first team that stayed
with us page for page through 260 pages of very detailed technical analysis
with backups of backups, type curve construction, everything we could muster to
put in that book. We didn't want to have to remember anything. And all of us
knew, you know, every word on that page in the book. So we were flipping that
constantly. It was an interesting meeting. Kayne Anderson's been a fantastic
We have never failed to raise the capital that we needed to go forward.
We're obviously operating out of our revolver now. But our additional
acquisition capital that we've raised over the last two years has been a very
partnership oriented relationship. I would say also we selectively hired the
best and brightest for a long term commitment.
Our initial vision for this company was not a yellow on the map, drill a
couple of wells, and get rid of it. It's just not in the DNA of the managing
partners to do that. We also have found that the type of people that we want to
work with if are on a management track, say, at a large publicly traded company
have difficulty leaving for that type of business model-- the old private
equity business model. So we were able to go pursue the people that we wanted
to pursue with a longer term commitment and I think maybe a longer term support
from the management team, which all goes into that long term vision that we
It's kind of the soup du jour of private equity right now is that we've all
realized that-- you know, in 2014 when we realized it was going to be lower for
longer, we assumed that the business was going to be lower for longer. We
assumed that we were going to need to build a legitimate, fully integrated,
fully functioning upstream E&P company. And that's what we did. We have
in-house accounting, in-house back office, in-house completions managers,
in-house drilling managers-- all of our land, legal, and geoscience in-house,
I'm here with a couple of my colleagues today-- Drew Thomas and Johannes
Dumar here. I'd be glad to answer a few questions. And if I'm out of time, I'll
answer them later. And those gentlemen would be glad to, as well. Thank you
guys very much.
Questions out there?
I have a question.
So having a geologist CEO and how have you been able to take advantage of
and profit from the knowledge of the rocks?
I would say that our geology-- or our reservoir analysis team doesn't know
how spoiled they are.
We're allowed to-- my technical research budget is more than would probably
be allowed at a lot of private equity companies simply because of our focus on
the rock. You know, a lot of people in this room know Greg Casillas and know
his track record. He's a Oklahoma State geologist. He go to school with you,
And that has dictated a lot of our focus on the reservoir for sure.
Has it really-- so they work in teams as engineers, et cetera?
Yeah, we don't try to silo it. I don't-- you know, modern unconventional
resource Plays are far too complex for any one person to fully understand and
fully champion. It requires team integration. It requires well functioning
co-invested teams. And I don't know a geologist that can understand all the
aspects of it that they need to nor an engineer. So we integrate those teams--
geology, engineering, and land. We have a reservoir team. We do not have geoscience