The past couple Q3’s have been very busy for Denver-based QEP Resources. With over $1.3 Billion spent on two deals in Martin County, QEP has gone all-in on the Midland Basin. In fact, these two deals are the largest in terms of price per acre in the Midland Basin since 2015, both exceeding $50k/acre. Now to be successful, QEP has to do a great job in developing their newly acquired acreage.
QEP will have to devote the time and science to best optimize spacing, drilling locations, and completions in several different horizontal benches to maximize returns. Thus, success of this purchase is centered around three main questions:
- Does QEP have the ability to quickly start drilling new acreage?
- How many benches of proven production are in the acquired acreage?
- Is the high price per acre justified?
But before jumping to any conclusions, let’s start by looking at the two QEP acquisitions side by side:
At first glance, the most recent purchase actually looks like a better deal for QEP than last year’s acquisition. The 2016 acquisition was about 40% higher per PUD, and other operators have landed deals for around $40k per acre in the northern Midland Basin in the past 18 months. QEP may have come in at a few percentage points in higher in terms of NRI versus their peers in the northern Midland Basin, which could explain the high price per acre. For example, Concho made a $600MM acquisition in July, which is an interesting comparison for another article. So did QEP make a good decision with last month’s acquisition? Let’s take a look at those three main questions from above, in order to answer that question.
The Past Two QEP Acquisitions in Martin County: June ’16 is Circled and July /17 is in Orange
QEP (Orange) and JM Cox (Blue) Well Spots with JM Cox drilling units in grey
Does QEP have the ability to start drilling new acreage?
At the start of 2017, QEP allocated capital for 80 completions in the Permian in 2017, with an initial guidance of five rigs running. Their CAPEX has increased by roughly $100MM from Q1 to Q2 across the lower 48, based on their earnings calls, and it appears most of this increase will be focused in Martin County in the Midland Basin. After taking a look at QEP’s drilling activity since the acquisition last June (see the historical Permian QEP rig count below), it seems like they may have increased their expectations for the Permian.
QEP Rig Count in the Permian by County
Source: DI Rig Analytics
Since the closing of the Mustang Springs acquisition, QEP has increased their rig activity every quarter. QEP has increased from one to seven rigs running since last June, with five now in the Mustang Springs area. They still have one rig in Pinedale, where they annouced a divestiture in July 2017. It is important to note that we are tracking seven QEP rigs in the Permian versus the five they claimed in the earnings call. At their current completions schedule and their assumed gross locations, QEP now has approximately 20 years of drilling inventory in the Permian versus the 12 years they had prior to the July acquisition. We are seeing several operators that are having incremental production increases year over year (YoY), based on advancing technologies and operator efficiencies. QEP has had a 25% average increase in production YoY, which leads to large EURs and more stable decline rates.
QEP Vintage Type Curve for Martin County
How many benches of proven production are in the acquired acreage?
The second question revolves around a firm understanding of the subsurface. We are hearing and seeing several operators slap on a high number of zones or benches during their press releases and earnings calls to justify the rising price per acre in the Permian. Traditionally, it would be necessary to have a robust geological model of the basin, married with production, to get an idea of the subsurface. Drillinginfo has developed geology zones that are determined using our subsurface model, created by our staff geologist using thousands of well logs and corrected directional surveys. If 60% or more of the well’s trajectory lands in a given zone we will assign the well to that actual bench.
By looking at Martin County, we can see production in four main benches, Lower Spraberry, Upper Spraberry, Wolfcamp A, and Wolfcamp B. The map below is made of wells that are sized by proppant intensity, with the JM COX acquisition highlighted in red. The scatterplot for these wells over the first 12 months of production (Boe) vs. the lateral length (production sized by proppant/ft) shows that proppant intensity has actually tailed off in Martin County, with operators now drilling longer laterals. An average well is now being completed greater than 7,500 ft with around 10MM lbs of proppant.
Left: Map of Different Benches in Martin, Well Spots sized by proppant intensity, July’17 acquisition in Red
Right: The Average first 12 months production (Boe) by geology zone, with the average oil cut. The effect of proppant normalization is seen in orange.
Average proppant/fit by geology zone, Martin County
To further validate that the drilled zones are producing in economic quantities, we created five type curves around the AOI. We refined the type curves to ensure that only newer wells were used. We also limited the data set to wells that began producing in the past two years and laterals of at least 7,500 ft for each bench, using WellCast, which gives decline curves for all wells in the United States that have at least six months of production. We normalized the type curve production to 15MM lbs of proppant.
Type Curves for the 4 benches and QEP are shown using a 2 stream 6:1 Boe
EURs and IP30′-s are normalized to a 15MM lb Frac
Based on current results, the highest-producing wells are in the Wolfcamp B, which is the deepest zone. This can be slightly skewed due to the number of wells online in the other benches, and the earlier point that the more wells an operator drills, the better the YoY results due to the learning curve. Nonetheless, EURs based on these initial results over 1,000 Mboe are reasonable, when you normalize it to a large frac job. The vast majority of the wells’ payout is in the first three years of production. Due to the time value of money, you are not even hitting single digit returns after three years of production.
Based on these assumptions, many of these benches are economical today at current D&C costs. Part of QEP’s initial plan will be to prove up some of these zones to prove to investors that the price paid was justified; they will also continue to delinate sub benches in some of the thicker zones of the Wolfcamp and Spraberry, which will add reserves over time. One of the most exciting things about the Permian is that the main benches can be delinated, such as the Wolfcamp A. We are able to find sub benches that are economical on their own accord such as the Wolfcamp X/Y or A1. QEP’s normalized type curve looks strong compared to other operators in their area.
Finally, is the high price per acre justifiable against offset operators?
The final question that most folks are asking is if the price paid per acre ($/acre) is justified. There are multiple factors that play into this including offset deals, proven benches, production curves, etc. We have answered some of these questions previously in that in QEP’s AOI, with four benches that have been drilled with reasonable results to date.
There have also been offset deals that are similar to QEPs in terms of costs; the benefits of QEP’s acquisitions are continuous acreage and NRI. Looking at the maps below one can see that the region that QEP is in has more proven benches compared to the southern part of the Midland Basin, which has higher GOR and is mostly just Wolfcamp B. Returns and economics are also better in their AOI due to the multiple benches and higher oil cut.
Source: Detring Energy Advisors, with Drillinginfo
Midland Basin Geology Zones, colored by zone, with the JM Cox Acquisition in red.
In determining whether a company has paid a fair value for their acreage, future production is often a major concern. Using data from DrillingInfo Rig Analytics and the type curve generated from Wellcast, we are able to combine QEP’s rig ramp up and future guidance on completions to determine a PUD forecast. One can see the wedge in new production, and how it will be necessary for QEP to continue production growth.
Their current assets are already on a decline but they have been able to see a large growth in production from the ramp up in the past few quarters. If we use the decline curves built prior with the completion schedule, we can see how fast production can grow moving forward. There are a lot of variables that cannot be taken into account, but using just this short-term forecast forward guidance allows us to get a fairly good idea of the production they can bring online.
QEP Production Forecast, based on guidance, using the type curve from Wellcast
While the two acquisitions QEP made were above market price to date, they did add drilling inventory to a successful ramping up of their drilling program. QEP could be producing over 50 Mbbl/d by the end of 2018 if this current drilling and completion pace continues.
Their second deal seems to be more justified compared to the 2016 deal due to economics, de-risked production, a contiguous acreage with eight more years of drilling inventory, and their increased rig activity in Martin County. With the success of an aggressive rig ramp up program, adding more inventory in the best part of the Midland Basin sounds like a win to us.
Latest posts by Enverus (see all)
- Enverus Knowledge Hub: On-Demand Energy Insights - October 20, 2021
- M&A Cools in Q3 From Last Quarter’s Scorching Pace - October 12, 2021
- Enverus’ SPARK Continues To Ignite Innovation in Energy - October 7, 2021