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Assessing Value in an Overheated Market


The level of financial dynamism in the oil and gas financial sector is fast approaching a tipping point.

As the industry begins to plan both CAPEX and OPEX around the perceived stability of $50-55 WTI oil and $2 gas, identifying winners, survivors, and losers in the upstream and midstream sectors has never been more challengingly complex.

How do you model the NPV of Drilled but Uncompleted (DUC) wells? What are the drilling capital commitments necessary for an operator to drill and hold large acreage blocks to avoid massive sunk cost write-offs for expiring acreage? Can you effectively determine the reserve base of a company’s operations? And how do you responsibly decline it, discount it, and model the cash flow from those reserves? Are you using an assumed WTI benchmark price, or are you actually using posted prices for the basin in which the assets sit?

These questions, of course assume that the context of an evaluation is static—that the reserve base is known or can be reliably extrapolated. Fair enough, but when an offset operator drills two thousand feet deeper than your target’s known producing reserve base, and completes a new formation at an IP of 1500 BOPD and 1000 MCFGD, how do you factor this into your potential bid price? And how will your potential acquisition target raise their asking price? Playing devil’s advocate, how do you re-evaluate a potential bid when a respected offset operator completes and produces at sub-median flow rates on acreage adjacent to your potential acquisition?

Suppose you are trying to assess the potential impact of DUC wells coming on line in Reeves county, TX .

Here’s where they are…

And the level of activity (and therefore potential increased product to markets) is still intense.

Now, let’s take a look at the pipeline/crude transportation infrastructure.

A fair number of DUCS in NW Reeves are still underserved by oil pipeline gathering, so lifting costs duie to trucking will affect margins.

Quick Due Dilligence on Reserves/Production Behavior

If we look at the production in this part of Reeves county , over 90% of the wells drilled in the last 24 months are producing from the Wolfcamp. We can see marked improvement year-over-year from 2015 to 2016 both in gross max month BOE and in decline rates.

The Wolfcamp type curve below indicates fairly predictable decline behavior

The longest producing well in the sample (first production date within last 24 months) has a P90 probabilistic EUR of 432,037 BO and nearly 2 BCF EUR. With Remaining Recoverable Reserves (RRR) of 103,000 BO and.5 BCF, this particular well with two years of consistent production is still producing at a rate of nearly 400 BOPD and 1700 MCFGD. This would imply that acquisitions of Wolfcamp reserves at midpoints in their producing lives could be expected to book +100,000 BO of consistently producing reserves over a time period that may capture any uptick in comodity prices.

Based on numerous reported api gravities in the Wolfcamp, the quality of produced Wolfcamp oil in the Delaware Basin should be in the upper API ranges

NGL distribution going forward will be weighted towards ethane and propane., with butane and isobutane expected to marginally increase starting in 2019. Therefore cash flow models can be constraiaed by posted price information for mid-high 40 gravity oil and high ethane content wellhead gas.

If these reserve, flow rate, and oil/gas quality metrics do not quite pass muster re: investment goals, or if AFE cost concerns are paramount, analysts can get an idea of breakeven pricing by basin to assess the likelihood of profitability at various WTI/Henry Hub price points for all basins in the US.

The example below is for various reservoirs in the Permian Basin. If the opportunity evaluator is convinced that oilfield services contractors have begun to achieve pricing power again, then a search for better breakeven pricing might lead the evaluator to consider looking at Spraberry targets in the Midland Basin.
Or the more prudent approach may be to look for a portfollio model that blends investment dollars into several plays –low cost + high production yield.

Is Your Potential Acquistion Operated by a Hidden All Star?

One of the key questions for anybody contemplating an acquisition is to understand comparative operator performance from first prodcution through 1 and 2 year production profiles. For example a high peak rate well may be outperfomred by a well that is not pulled so hard to maintain reservoir drive pressure.

For example, this graphic shows the +-20% operator differentials around median performance on peak rates, and shows that Panther Energy was a median performer in the Delaware Basin when measured on Peak Rates, but is a better than median performer when 12 month cumulative volumes are measured

By benchmarking operators, especailly when using graded acreage, it’s possible to identify operators that have underperformed on their drilled acreage. These operator’s assets, if acquired, could be expected to yield a higher ROI if operated according to the best practices of the operators within their common acreage grade.

What Did Our Very Quick due Diligence Uncover?

We’ve been able to quickly determine that any acquisition in NW Reeves county will involve initial production from the Wolfcamp , yielding between 200K and 400K of recoverable oil, high in methane NGLS, with wellhead prices consistent with 40-55 api gravity oil. Remaining recoverable volumes imply that good returns can be achieved even if wells/properties are acquired in the midlife of their producing history.

We’ve also learned that a good volume of recoverable reserves are waiting to come to market, and when those reserves enter the transportation chain, they will probably be discounted in price due to trucking costs.

Knowing that various benches of reservoirs like the Wolfcamp or Bone Spring have different breakeven prices helps to quickly differentiate short term and long term acquisition opportunities, and may even dictate buying reserves under a portfolio management perspective.

The additional ability to understand how to look beyond Initial Potentials as reported in press releases to see how well an operator is performing against its peers unmasks massive amounts of semi-hidden opportunity.

As we said before, the number of analytical crosschecks can be daunting. But the tools to work faster, smarter, and comprehensively are available to you on DrillingInfo.

Your Turn. Comments?

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Mark Nibbelink

Mark Nibbelink is co-founder and director of university outreach at Enverus. Before co-founding Enverus (formerly Drillinginfo) in 1999, Mark had a long career as a prospect geologist at Gulf Oil before beginning work as an independent geologist. Mark is responsible for quality control and data integrity. He received his Bachelor of Arts in geology and his master’s in geology and geophysics from Dartmouth College.