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Quantifying Operator-Level Remaining Inventory by Breakeven

4Q 2019 – The number of remaining drilling locations and the estimated economics of those locations is a fundamental element in commodity market analysis and price forecasting. BTU Analytics has published US shale inventory estimates by breakeven on a play level since 2016. With the publishing of the 4Q’19 E&P Positioning report, more granular estimates of inventory are now available to E&P Positioning Report Data subscribers, with the launch of the “BTU View” web interface and datasets.

The new functionality in the BTU View tool helps users quantify and qualify the inventory runway for both public and private companies and their acreage. Most public E&Ps disclose inventory figures to help investors quantify their company’s runway through “remaining locations” or “number of years of remaining inventory”. However, what these locations represent is often unclear, and specifics around assumptions used in calculating these disclosures absent. This makes it difficult to compare across operators and basins. To bring comparability, consistency, and transparency to inventory estimates, BTU Analytics is now providing remaining inventory by breakeven estimates that can be filtered down to individual grids representing 9 square miles, and tagging those grids to operators allowing for granular operator-level analysis. The analysis that follows highlights both the strengths and limitations of the model and its use, comparing model outputs to disclosures from operators.

Methodology

BTU Analytics’ inventory first overlays 3×3 mile grid boxes over key US shale plays and then averages historical breakevens for wells turned to sales in each box by reservoir. From there, for each grid box in each reservoir, BTU Analytics estimates the drainage of historical wells within the grid and reservoir using spacing assumptions. Then BTU estimates the number of future remaining locations that could be drilled within the grid and reservoir taking into account the footprint of previously drilled wells along with lateral length and spacing assumptions for future wells. At this stage, each grid has a number of remaining locations by reservoir with estimated economics assigned to locations by reservoir.

Assigning these locations by grid to an individual company requires additional assumptions. In most basins, 60%-85% of grid/reservoir combinations have wells drilled by a single operator. In this case, all locations are assigned to that operator. For grid/reservoir boxes with more than one operator, BTU Analytics assigns remaining locations using a weighted average of historical drilling activity. For example, if there are 100 remaining drilling locations in the Wolfcamp A formation in a Midland Basin grid box and Encana historically accounted for 80% of activity and QEP accounted for 20% of activity, then 80 out of the 100 remaining locations would be assigned to Encana and 20 to QEP.

 

How might BTU Analytics’ estimates compare to company reported figures?

Below is a list of disclosures from E&P companies on their remaining drilling locations. Where possible, BTU Analytics categorized these into net or gross locations. Unfortunately, most operators do not always distinguish this key detail. Note that the BTU View methodology estimates gross operated locations, which is different from gross locations as well. Another key piece of information that is often missing from company disclosures is what price deck is assumed and whether the remaining locations are economic in today’s price environment. In the company disclosures below, BTU Analytics has noted if such disclosures were mentioned in the “notes” column of the table. Further complicating matters is it is not always clear how many productive horizons are being considered and what spacing assumptions are being applied.

Using BTU Analytics’ new BTU View web visualization and analysis tool, users have access to a transparent and standard methodology to calculate inventory, making it possible to not only cross check but also to gain a better understanding into how a company thinks about their reported inventory. As an example, a slide from natural gas producer EQT from October 2019 is included below.

 

The slide is more detailed than most and EQT lays out “Core Net Undeveloped Locations” for the Marcellus and OH Utica totaling 1,805 locations. It also contains a map that highlights EQT’s acreage and shades areas the company consider to be core. Additionally, EQT provides spacing and lateral length assumptions. Pulling BTU Analytics’ inventory estimate for EQT via the BTU View tool results in a number of remaining locations higher than what was provided by EQT. BTU Analytics estimates that EQT has 1,884 remaining gross operated locations in Southwest Appalachia. Of these 1,884 locations, BTU Analytics estimates that there are 650 wells that breakeven below a $2.00/MMBtu wellhead price.

Beyond digging into an individual operator’s inventory, it is valuable to compare operators in the same regions or even across regions. However, as highlighted earlier, comparing reported figures from two different operators is full of pitfalls and murky assumptions. For example, both Antero and EQT operate in Southwest Appalachia and disclose remaining drilling locations estimates, but upon first glance it is unclear if the two figures are comparable. In the case of EQT, looking at the highlighted core areas provided in investor materials compared to a map of historical activity since 2013 as seen through the BTU View tool, shows that there is significant overlap. This suggests that estimating remaining inventory using the company’s delineated drilling is likely to provide a reasonable inventory estimate.

 

On the other hand, a side by side comparison of Antero’s investor map and Antero activity since 2013 in the BTU View tool shows that Antero’s stated inventory likely includes locations associated with acreage that has not seen any recent activity. For example, zooming in on Harrison County, WV, shows that Antero has only been active in the southeastern portion of the county. However, their map highlights over 80% of Harrison acreage as “core” and thus it appears likely that a material number of locations in Harrison county are included their inventory disclosures.

This comparison highlights that BTU Analytics’ inventory is often conservative and can vary from reported figures because BTU Analytics’ model is based solely on historically delineated acreage and delineated productive horizons. To the extent that acreage positions are well-delineated, BTU Analytics’ model will tie more closely to reported figures, as is the case for EQT. However, for Antero, the model only credits Antero with 637 gross operated remaining locations with breakevens estimated, compared to reported figures of over 3,000 which likely include non-delineated acreage and horizons.

Another producer example highlighting the important nuances and insight that can be gleaned through use of the BTU View web tool and data is WPX Energy. WPX holds acreage in the Bakken and the Delaware Basin. The Bakken is a well-delineated play where operators have extensively tested and developed the extent of their acreage and producing horizons. As such, remaining estimates of core Bakken drilling locations would have a higher probability of tying out to BTU View estimates of locations by breakeven. Conversely, while operators have continued to test and develop more acreage and horizons in the Delaware Basin, it is not as far along in the development lifecycle as the Bakken, and all else equal, BTU’s inventory by breakeven model is more likely to be conservative than operator-reported figures that likely include horizons and acreage that are yet to be delineated. Additionally, the classification of productive reservoirs can vary dramatically.

Below are two slides from WPX Energy’s investor materials highlighting inventory estimates. The first slide, released upon WPX’s announced intent to acquire Felix Energy, highlights almost 5,000 drilling locations across multiple Permian benches. The second slide, from 2016, states more than 500 remaining drilling locations in the Bakken.

The BTU View estimates that WPX has 591 gross operated remaining locations with assigned breakevens in the Bakken and almost 2,500 gross operated locations with assigned breakevens in the Delaware Basin including the Felix acquisition. As expected, BTU Analytics’ estimate for remaining Bakken locations is close to WPX’s reported figure.

However, in the Permian, based on investor materials, WPX is likely giving credit for at least three horizons worth of drilling across most of their acreage as seen in slide to the right. For easier comparisons across operators, BTU Analytics standardizes and accounts only for activity in seven main inventory horizons across the Delaware Basin: Wolfcamp A, Wolfcamp B, Wolfcamp C, Wolfcamp D, Bone Spring 1, Bone Spring 2, and Bone Spring 3. If there has been no delineation activity in each of those horizons, BTU Analytics does not account for undrilled inventory in the given grid in that horizon.

Maps on the following pages derived from BTU View data show that while WPX has tested up to seven different benches across their acreage, not all benches have been delineated across their entire footprint. Using historical activity, on average only 2.5 horizons have been tested and would be accounted for in inventory by breakeven estimates, rather than the four outlined in WPX’s slides.

 

 

Additionally, doing a side by side comparison of BTU View activity maps compared to WPX acreage maps shows that, like Antero discussed earlier in the piece, WPX estimates likely include locations beyond the reach of their recent activity.

Quantifying and comparing remaining inventory on a net basis for companies will always be a challenge. The granular inventory by breakeven estimates for operators available in the BTU View offers new transparency into an opaque subject. Reviewing Antero, EQT, and WPX/Felix’s stated inventory figures compared to BTU Analytics’ estimated remaining inventory by breakeven highlights the strengths and biases of using the new BTU View tool at its most granular level. Access to the Macro and Insights sections of BTU View are now available for all current E&P Positioning Report subscribing companies at no additional cost.

 

Examining the Impact of Corporate Costs in Conjunction with Half-Cycle Economics

Energy markets’ demands for capital discipline in 2019 led several operators to tout improvements in capital efficiency. These incremental gains are captured in the updated well cost assumptions for BTU Analytics’ economics model each quarter. Despite these improvements in drilling, completion, and operating costs, half-cycle economics only tell part of the story when quantifying E&P companies’ performance. Weighing corporate costs in addition to BTU’s breakeven estimates differentiates operators further as priorities continue to shift to free cash flow generation instead of production growth at all costs.

 

Corporate costs affect breakeven levels differently depending on operator size and strategy. Oil-focused operators with low corporate cost to breakeven ratios, such as Pioneer, see little impact from corporate costs in their combined breakeven. Several operators have disproportionately higher hurdles for their wells to overcome as a result of their corporate cost management.

There is a natural break in the corporate breakeven distribution of the oil-focused operators shown near $55 that yields roughly the same number of operators above and below this threshold. Using this grouping, BTU Analytics aggregated operators’ stock price performance over the past two years to examine stock prices’ sensitivities to changing oil price environments.

 

Indexed to January 2018 levels, stock prices for higher breakeven operators outperformed operators breaking even at sub-$55 WTI prices when oil prices exceeded $65 per barrel. Contrastingly, when oil prices fell below $65 per barrel in late 2018, it was higher breakeven operators whose share prices underperformed compared to their peers with sub-$55 breakevens. Despite oil price recovery in 2019, the sub-$55 corporate breakeven group’s shares have performed consistently better at sub-$65 WTI.

Capital discipline will likely continue to be a priority in 2020, which increases the importance of considering corporate cost impacts in addition to half-cycle breakevens. Merger and acquisition activity will drive changes in corporate costs in addition to breakevens, reminding energy markets that there is no such thing as a free lunch when it comes to cost reduction by creating economies of scale.

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