U.S. Shale: NAV Analysis Of Permian Basin - Midland Basin E&Ps - 2018 Q1 Update

Jul. 01, 2018 9:22 AM ETPXD, PE, FANG, RSPP, CPE, SM, EGN, AREX, LPI, ESTE24 Comments8 Likes
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Andre Kovensky


  • Pioneer Resources offers the best risk-reward profile.
  • Callon Petroleum is deeply undervalued and offers the highest return potential.
  • On a NAV basis, Parsley Energy, Laredo Petroleum, Earthstone Energy and Approach Resources are undervalued.
  • On a DCF basis, Diamondback Energy and SM Energy are undervalued.
  • Energen is somewhat overvalued on a DCF basis and about fairly valued on a NAV basis.

This report updates with 2018 Q1 results my initial report on the US shale Permian Basin – Delaware Basin E&Ps. For definitions of terms and explanations of methodology, please reference the initial report published on 5/2/2018 US Shale: NAV Analysis of Permian Basin – Midland Basin E&Ps covering Pioneer Natural Resources (NYSE:PXD), Diamondback Energy (NASDAQ:FANG), Callon Petroleum (NYSE:CPE), Parsley Energy (NYSE:PE), Energen (NYSE:EGN), Laredo Petroleum (NYSE:LPI), Approach Resources (NASDAQ:AREX), Earthstone Energy (NASDAQ:ESTE) and RSP Permian (NYSE:RSPP) (on March 28, 2018 Concho Resources (NYSE:CXO) announced the acquisition of RSPP but I will still include RSPP in this report until the acquisition closes; RSPP trades in line with CXO). In addition, I have moved SM Energy (NYSE:SM) from the Eagle Ford group to the Midland Basin group.

Summary Results

Here is a summary of the results I will describe in this report.

Since my last report on the Permian Basin – Midland Basin group, several changes occurred at the company level.

The prior report contained an error in calculating ESTE’s Enterprise Value (“EV”) and thus its equity value. I was double counting minority interest and the shares related to such minority interest. This error has now been corrected and leads to a meaningfully positive change in ESTE’s valuation metrics, both NAV based and DCF based.

On May 21, 2018, Carl Icahn and Keith Meister, an activist investor and former Icahn colleague, announced they had acquired about 10% of EGN and could bid for the entire company. Also, since my last report, based on EGN’s disclosures, I reduced EUR per well by about 10%. This had a large negative impact on valuation, as D&C Cost per Adjusted BOE has increased from $13.82 to $15.81, which is 30% to 50% higher than its Midland Basin peers. On a DCF basis, EGN’s implied stock price is now $62.46, versus $82.13 in the prior report. And EV Less PV-10 / Price Adjusted Future Drilling Site Resource Excluding PUDs has increased from a somewhat attractive $1.69 to a market level $2.11 per BOE. As a result, EGN is no longer considered undervalued.

On May 24, 2018, CPE announced a $570 million acquisition of acreage adjacent to some of its Delaware Basin acreage. The market has hated this acquisition, and CPE is the worst performing stock in the group since my last report, down about 21%. Here is what few shale E&P executives and boards seem to understand, which as an investor is very frustrating. Before this acquisition, CPE had already paid billions of dollars to lease acreage which currently has about 1,029 net future drilling sites. Based on CPE’s current capital expenditures, CPE will drill about 50 net wells per year, meaning it will take 20 years to drill its existing inventory. So, when CPE acquires even more acreage, either the new acreage won’t be drilled for 20 years or the existing acreage will be pushed out further into the future. Next, what did CPE get for $570 million? Current production of 6,800 BOE/day and 212 net future drilling sites. Using a market metric of $40,000 per flowing BOE, the current production is worth $272 million. Thus, CPE paid $298 million for the 212 net future drilling sites, or $1.4 million each. If CPE was going to drill them now, then it makes economic sense to pay $1.4 million per well for the drilling rights. But, if CPE is effectively not going to drill for 20 years, then using a 10% discount rate, CPE is really paying about $10 million per drilling site, and that my friends is called VALUE DESTRUCTIVE!

CPE has some of the best assets in the Permian and they have the highest EBITDA per BOE of any shale E&P, full stop. And yet, the stock is trading 42% below its December 2016 high of $18.53 per share. Conversely, since December 2016 FANG is up about 25%, EGN is up about 20% and RSPP is about flat. There is no reason for CPE to be trading at such a massive discount to intrinsic value, other than the market believes that management will continue to destroy shareholder value via ill-advised acquisitions versus doing the opposite and selling itself.

Carl Icahn is going after EGN, but I think he has it wrong. He should be going after CPE. CPE is crying out for an activist shareholder to join the board and replace the CEO, Joe Gatto. Mr. Gatto was previously CPE’s CFO and was only appointed CEO because CPE’s prior CEO, Fred Callon (as in Callon of Callon Petroleum), passed away last year. The CEO has no operational background and clearly does not understand finance and capital allocation or else he would not keep adding drilling inventory that has negative NPV when taking into account the time frame in which the added drilling inventory will actually be drilled. In short, relative to its asset quality and superior operational performance, CPE is the most mispriced shale E&P of any that I follow, assuming of course a CEO and board that does not destroy equity value though further acquisitions.

I moved SM from the Eagle Ford grouping to the Midland Basin grouping. While current production volumes are weighted toward the Eagle Ford, all the company value and future drilling resource are in the Midland Basin. I am also now assuming that SM will never drill in the Eagle Ford. Instead, it will run off its Eagle Ford proved developed reserves. Regarding the 165,000 net acres in the Eagle Ford, I assume SM can sell them for $1,000/acre, or $165 million. SM’s Eagle Ford wells produce 5% oil, 35% NGLs and 60% nat gas, thus they have modest value in the current commodity pricing environment and make little sense to drill. By assuming SM will not pursue negative NPV drilling in the Eagle Ford, SM’s valuation has increased materially. Using DCF analysis and assuming SM drills its Eagle Ford acreage, SM’s equity is only worth $5.97 per share. By assuming the Eagle Ford undrilled acreage is never drilled but instead sold off, SM’s implied stock price increases to $33.53, a 30% premium to the current price and a 461% increase from the prior report’s implied share value.

Finally, I want to discuss PXD, which the market seems not to understand. PXD is the only shale E&P among the Midland Basin and Delaware Basin companies I follow that has close to 100% of production from now until 2021 either under firm transportation agreements or with basis hedging. This matters because from Q2 2018 until 2H 2019, oil produced in the Permian is expected to realize prices about $15 below WTI at Cushing prices. The reason being there simply is not enough pipeline capacity to move the oil and the only way to get the oil to Cushing or the gulf coast will be via truck or rail, assuming there is even enough capacity of those. There is a high likelihood that well completions will slow down and/or wells may even have to be shut in. That is, unless you have already arranged for transportation of your oil, which PXD has.

Permian E&Ps are in one of three situations. Best case, they have already reserved pipeline capacity and can flow their oil to Cushing or the gulf coast, where they will sell the oil at the prices in those markets. Or, they bought basis differential hedges in 2017 or early 2018 when they were cheap, protecting themselves for differences in price between WTI Midland and WTI Cushing (Oklahoma) or Magellan East Houston (MEH; gulf coast) or Louisiana Light (LLS; gulf coast). As an aside, in 2018 MEH oil and LLS oil have been about $6 greater than WTI at Cushing (and thus $15 to $20 greater than WTI at Midland) because they can be sold to the export market or the gulf coast refineries and thus price off of Brent oil. PXD and PE and to a lesser extent LPI are in this situation. I expect PXD’s 2018 realized oil prices to be greater than WTI at Cushing since PXD has firm transportation agreements to the gulf coast and can access MEH and LLS pricing. Yet, despite this fact, PXD is trading as if it's any other Permian E&P exposed to WTI at Midland pricing. Given PXD's superior asset base, best-in-class infrastructure and operations and firm transportation agreements to access the gulf coast markets, PXD offers the best risk-reward of all the US shale E&Ps I follow. If I could only own one US shale E&P, I would buy PXD.

The middling case is where an E&P has arranged with a marketer to buy their oil, but at the local Midland WTI price. The E&P has a guaranteed buyer, but not a guaranteed price. To offset the price risk, the E&Ps buy basis differential hedges, but most only hedged about 50% of production and thus they are fully exposed to local Midland pricing for the remainder. This scenario applies to CPE, RSPP, EGN, SM and AREX. FANG was late to put on basis hedges, so while 53% of oil production as of 2018 Q1 was protected from WTI at Midland pricing, FANG had to pay a high price for the basis differential hedges. Where CPE, RSPP, EGN and AREX bought the basis differential hedges much earlier and thus at much lower prices.

The worst case is where an E&P has not arranged for a marketer to buy their oil and thus they have no way to guarantee they can find a buyer. Few publicly traded companies are in this situation and it is more likely the case for private companies. Which then raises the question of whether the expected production from the Permian in 2H 2018 and through 2019 will really be as high as forecasters project. My personal view is that production will be lower than forecast as we see WTI at Midland trading $25 or $30 below WTI at Cushing once all the transportation capacity out of basin is used up.

Later in the report, I provide detailed analysis on each Midland Basin E&P regarding basis differentials, pricing realizations and their hedging positions. Before moving to the specific analysis, one final point. The Permian E&Ps have traded quite poorly versus E&Ps in other basins due largely to the recent WTI at Midland price discounts. While I fully appreciate that most trading in shale E&Ps is done by computers or momentum-oriented hedge funds that do not understand underlying fundamentals, given spot WTI at Cushing is trading at $74 and Brent is trading close to $80, the equity valuations for the Midland E&Ps makes no sense. The market is pricing them as if WTI at Midland is going to trade in perpetuity at a $12 discount to WTI at Cushing. But, we know that in 2H 2019 and into 2020 pipeline capacity out of the Permian is going to double to around 6 million barrels per day. The pipeline projects are literally under construction now. And, since E&Ps are worth the NPV of future cash flows, and the cash flows will occur for 20-30-40 years, the idea that 12 to 18 months of pricing discounts should have such a huge negative impact on asset values strikes me as crazy! Investors will look back at the current period as a unique opportunity to have bought some of the best US shale assets in existence at massive discounts due to computers and momentum hedge funds trading headlines instead of fundamentals!

Regarding the specific companies and my investment views, CPE and PXD are the most attractive investment opportunities whether on a DCF basis or NAV basis. FANG and SM are attractive on a DCF basis but not a NAV basis. Conversely, PE and LPI are attractive on a NAV basis but not a DCF basis. This is because LPI and PE have large asset bases and it will take so long to drill all the future drilling sites that the NPV from the further out cash flows has little to no value today. But, a much larger company with a stronger balance sheet could accelerate PE’s or LPI’s drilling program and pull forward the value of the future drilling sites. The value in PE and LPI is as acquisition targets. The same can be said of AREX. On a DCF basis, AREX is worthless since its weak balance sheet prevents it from drilling fast enough to realize the value of its large asset base. But, on a NAV basis, AREX is very under-value. The value in AREX is based on it being acquired. EGN is overvalued on a DCF basis and fairly valued on a NAV basis. Finally, ESTE is about fairly valued on a DCF basis but wildly undervalued on a NAV basis. ESTE’s EV trades at a discount to its PV-10, meaning an investor is paid to own the future drilling sites. I currently do not own ESTE, but I will be taking a hard look at it in the near future. And, again, my apologies to Seeking Alpha readers and ESTE management for my calculation error in the prior report, which lead me to believe ESTE was very overvalued.

I continue to be long PXD, CPE, FANG, RSPP, PE, LPI and AREX. Since my last report, I reduced my position sizes in RSPP and AREX and increased my position size in PXD. My largest position is in CPE.

I continue to assume commodity prices in 2018 are $65 WTI oil at Cushing and $2.75 natural gas at Henry Hub. I reduced my assumption for NGLs at Mont Belvieu from $35.75 per barrel to $32.50 per barrel. In 2019 and beyond I assume $62.50 oil, $31.25 NGL and $2.75 natural gas, with NGL pricing decreasing from $35.94 in my prior report. These commodity prices are before basis differentials.

Share prices are as of June 29, 2018.

Oil and Gas Resource Potential

Chart 1 below shows the Proved Reserves and potential resource from future drilling sites for each company as well as by geography for the companies I research.

The information in the above table changed since my prior report for CPE, EGN and SM. CPE acquired 6,800 BOE per day in production and 212 net future drilling sites in the Delaware Basin. Based on EGN disclosures, I reduced future drilling site EURs by 10%. For SM, which was previously in the Eagle Ford group report, I now assume no future drilling sites in the Eagle Ford.

Oil and Gas Drilling and Completion Costs and Profitability of the Production

Chart 2 below shows the D&C cost per adjusted BOE for each company and the various geographies.

By changing my assumption for NGL prices, all companies’ D&C Costs per Adjusted BOE were slightly impacted. EGN’s D&C cost increased from $13.82 to $15.81 due to the reduction in drilling site EUR assumptions. EGN has the highest D&C cost of any Permian E&P I follow, with the exception of Centennial Resource Development (NASDAQ:CDEV). SM’s D&C cost increased as I eliminated Eagle Ford drilling sites.

Chart 3 below shows EBITDA excluding hedging per BOE for each company and the various geographies for the past four historical quarters and my 2018 full year estimate.

WTI at Cushing averaged $62.87 in Q1 2018 vs $55.40 in Q4 2017. At the same time, NGL prices decreased to $30.87 per barrel in Q1 2018 from $32.12 in Q4 2017. From Q4 2017 to Q1 2018, PXD and CPE realized about a $3 increase in EBITDA per BOE. CPE continues to generate the highest EBITDA per BOE among all the US shale E&Ps I follow. PE, FANG and EGN realized about a $4 increase in EBITDA per BOE. RSPP and SM realized about a $5 increase in EBITDA per BOE, and ESTE realized a $6 increase in EBITDA per BOE. On the other hand, LPI’s EBITDA per BOE was basically unchanged from Q4 2017 and AREX’s was actually down $1 per BOE. AREX Q1 2018 production was 35% NGL and 39% nat gas, thus the weak pricing of both eliminated the benefits of higher oil price realizations. LPI had the same experience as AREX but to a lesser degree.

I have updated Permian Basin basis since the last report. I am now assuming $12.50 in basis for 2018, but I am also including basis hedges put on by the various E&Ps. Thus, the 2018 EBITDA excludes commodity hedging but it does include basis hedging. As a result of this and my reduction in NGL pricing, 2018 EBITDA per BOE for the Permian Basin-Midland group is down from $35.91 in the last report to $33.46. And, the Permian Basin-Delaware group is down from $33.05 in the last report to $30.57.

Chart 4 below shows (1) the price discount or premium to WTI at which basis hedges, if any, are struck, (2) the % of Permian production with basis hedges and (3) the Permian price discount or premium at which oil is forecast to be sold in 2018 relative to WTI at Cushing taking into account basis hedges. Also, if an E&P has firm transportation agreements out of the Permian such that they will receive WTI at Cushing or gulf coast pricing, the below numbers take this into account.

PXD is unique from every Permian E&P in that 95% of oil production is protected from WTI at Midland pricing and PXD should realize oil pricing at a $3 premium to WTI at Cushing. Based on PXD’s poor recent stock price performance (down 11.3% from its 52-week high), the market does not seem to understand this fact. PE is also very well positioned with firm transportation agreements and basis differential hedges. PE has 100% of oil production protected at a $2 discount to WTI at Cushing. LPI and SM are also in good shape, with about 70% of 2018 oil production protected, resulting in 2018 oil price discounts of $3 to $4 versus WTI at Cushing. RSPP, CPE and EGN have protected about half of oil production around $1 below WTI at Cushing, but the remainder of production will be sold at spot WTI at Midland pricing. Therefore, RSPP, CPE and EGN should realize on average about a $6 discount to WTI at Cushing on all oil production in 2018. FANG protected 53% of oil production but did so too late and thus will realize over $6 in discounts on oil that is hedged for basis. As a result, FANG should realize 2018 oil price discounts of about $9 versus WTI at Cushing. AREX protected 40% of oil production at less than $1 resulting in 2018 oil price realizations at about an $8 discount to WTI at Cushing. ESTE is the worst positioned with only 28% of Permian oil production protected, leading to a $9 discount versus WTI at Cushing pricing.

Due to the changes in basis differentials and NGL pricing, 2018 estimated EBITDA per BOE changed compared to the prior report approximately as follows: PXD +$3.50, PE -$1, FANG -$5, RSPP -$3, CPE -$4.5, EGN -$2, LPI -$1.50, SM flat, ESTE -$3 and AREX -$2.50.

E&P Equity and Enterprise Values

Chart 5 below shows the equity value and enterprise value for each E&P and various geographies.

As previously discussed, ESTE’s minority interest was changed from $447 million in the prior report to $0 since the related shares were already included in the equity value calculation.

Relative and Absolute Valuation Analysis

Chart 6 below shows the two calculations to value future drilling sites for each E&P and the various geographies.

Of the two analyses, I place more weight on EV Less PV-10 since the reservoir engineers calculating PV-10 have significantly more detailed information than I do. The changes since the last report are due primarily to changes in equity values (i.e., share price) except for ESTE. As previously discussed, by eliminating $447 million from EV, the EV Less PV-10 / Price Adjusted Future Drilling Site Resources Excluding PUDs ratio declines from $2.55 in the prior report to -$0.25 now. This means that ESTE’s EV is less than its PV-10 and ESTE share owners are being paid for ESTE’s future drilling site locations, which are of very high quality. I do want to highlight that PXD and PE trade at discounts to pretty much all other geographies and Midland Basin peers despite the quality of their assets and the fact that they have no basis differential risk. It makes no sense.

Chart 7 provides the production growth rate assumptions for the E&Ps and various geographies.

There are no material changes since the last report other than for CPE due to its announced acquisition and associated 6,800 BOE per day of production. CPE’s 2018 estimated production growth is now 56.3% versus 34% in the prior report.

Chart 8 provides the levered and unlevered DCF analysis equity results.

Since the last report, DCF analysis implied stock prices changed as follows: PXD +21%, PE -8%, FANG unchanged, RSPP -7%, CPE -3%, EGN -24%, LPI -39%, SM +461%, ESTE +133% and AREX is not meaningful since implied equity value is still negative. EGN suffered from a 10% reduction in drilling site well EURs, reducing the economics of EGN’s future resource base. LPI suffered from my reductions in assumed future NGL prices. SM benefitted from my assumption that SM will no longer drill in its Eagle Ford acreage but instead will sell off the 165,000 acres for $165 million. ESTE benefitted from the change in EV calculation where minority interest of $447 million was eliminated, which accrued to equity value.

In summary, based on DCF analysis, CPE is extremely undervalued, PXD, FANG, RSPP and SM are undervalued, ESTE is fairly valued, PE, EGN and LPI are overvalued and AREX is worthless.

Chart 9 provides leverage and free cash flow metrics for the E&Ps and the various geographies.

There was little change from the last report other than a bit higher leverage ratios and worse cash flow ratios resulting from lower 2018 EBITDA expectations. Also, CPE’s leverage increased due to the debt component of its announced acquisition.

Chart 10 provides commodity hedging metrics for the group.

To derive the above numbers, I calculated swaps, 2-way collars and 3-way collars separately. Also, remember that my assumed commodity prices of $65 oil, $32.50 NGL and $2.75 nat gas impact the collars and thus the average prices realized in the above table.

The group is quite similarly hedged for commodity risk. PE, RSPP, CPE and LPI have the most attractive hedge positions, where reported EBITDA will decline by between 4% and 8% due to hedging loss settlements. PXD, FANG, EGN and AREX should experience between 9% to 11% declines in reported EBITDA due to hedging loss settlements. ESTE is a bit worse at 13% of reported EBITDA lost due to hedging loss settlements. SM is the worst positioned, with 78% of oil production hedged at $53.16. SM’s reported EBITDA will decline by 25% due to $225 million in hedging loss settlements.

Chart 11 provides price realizations by commodity during Q1 2018 for the group.

Oil price realizations for most of the group during 2018 Q1 are quite similar at around a $1 per barrel discount to the benchmark WTI at Cushing price. ESTE realized a slight premium as its Eagle Ford production goes straight to the gulf coast and thus realizes a premium to WTI at Cushing. AREX realized a nearly $3 discount to WTI at Cushing.

NGL price realizations vary widely. PXD has the best price realizations at a $3.13 discount to the benchmark OGIS price. PXD has the best infrastructure, takeaway agreements and processing agreements of the group, leading to the best price realizations. LPI, AREX, RSPP and EGN have very weak NGL realizations. This is a particular issue for LPI and AREX profitability since 28% and 34%, respectively, of their production is NGLs. For most of the group NGLs comprise 15% to 20% of production. PE, FANG, SM and ESTE all experienced about a $5 to $6 discount on their NGL price realizations. Since CPE does not break out NGL production but instead includes it in their reported nat gas production, the above NGL and nat gas analysis is not applicable to CPE.

For most of this group, nat gas realizations are not material to profitability. But, for those of you interested. PXD again had strong realizations. PE, FANG, RSPP, EGN, LPI and AREX all realized about a $0.70 to $1 discount to the benchmark Henry Hub price. SM realized a premium nat gas price, as the majority of its nat gas production is from the Eagle Ford, which has superior pipeline access to the gulf coast market. Since 42% of SM’s production was nat gas, it’s realizations actually do matter to profitability. Finally, ESTE also had strong nat gas price realizations, as its Eagle Ford production, like SM, can more easily access the premium gulf coast market given its proximity.


Since my last report, I made changes to assumptions for NGL prices and for 2018 Permian oil price basis differential to WTI at Cushing. The basis differential changes impact 2018 and 2019 EBITDA but have no material impact on DCF analysis since its just two years out of 20-30-40 years of production and cash flows. The change in NGL prices for 2018 and beyond had a negative impact on valuations across the board, and especially for LPI given its high weighting to NGL production. EGN’s valuation was negatively impacted by a reduction in assumed EURs per future drilling site. SM was positively impacted by the new assumption that SM will not drill new wells in its Eagle Ford acreage but instead will sell it. Finally, ESTE was positively impacted by correcting an error I made in the prior report related to the treatment of minority interest and resulting calculation of ESTE’s EV.

Relative to my prior report, CPE is still one of the most attractive investment opportunities and is deeply undervalued. CPE has some of the best assets and most profitable operations of any US shale E&P I follow. PXD has replaced FANG as the other most attractive investment opportunity. FANG, PE and LPI are still undervalued, although LPI is not as attractive as it was in my prior report. ESTE and SM are now undervalued versus prior reports where they were overvalued. EGN is now fairly valued to somewhat overvalued, versus the prior report where EGN was undervalued. AREX is unchanged from my last report, deeply undervalued on a NAV basis but worthless on a DCF basis.

This article was written by

Andre Kovensky profile picture
Andre Kovensky is the founder and President of Octavia Investments LLC. Previously, he was the COO and CFO of PGM Holdings (TSE:2466), a publicly traded owner and operator of golf courses in Japan. He also spent three years leading corporate buyouts for Lone Star Funds in Tokyo, as well as 10 years as an investment banker, the majority of which with Citigroup based in the San Francisco Bay Area focused on technology companies. Andre received his MBA from UCLA's Anderson School of Management and a BA in the Humanities from the University of Texas at Austin.

Disclosure: I am/we are long PXD, CPE, FANG, PE, RSPP, LPI, AREX. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

Additional disclosure: Disclaimer: Opinions expressed herein by the author are not an investment recommendation and are not meant to be relied upon in investment decisions. The author is not acting in an investment advisor capacity. This is not an investment research report. The authors opinions expressed herein address only select aspects of potential investments in securities of the companies mentioned and cannot be a substitute for comprehensive investment analysis. Any analysis presented herein is illustrative in nature, limited in scope, based on an incomplete set of information, and has limitations to its accuracy. The authors recommend that potential and existing investors conduct thorough investment research of their own, including detailed review of the companies SEC filings, and consult a qualified investment advisor. The information upon which this material is based was obtained from sources believed to be reliable, but has not been independently verified. Therefore, the authors cannot guarantee its accuracy. Any opinions or estimates constitute the authors best judgment as of the date of publication, and are subject to change without notice.

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