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

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Includes: AREX, CPE, EGN, ESTE, FANG, LPI, PE, PXD, RSPP
by: Andre Kovensky
Summary

CPE and FANG are the most attractive investment opportunities.

PXD, LPI, PE and EGN are also undervalued.

ESTE is overvalued.

AREX is a special situation, undervalued on an asset basis but overvalued on a DCF basis.

RSPP is being acquired by CXO in a stock-for-stock transaction and will trade in line with CXO.

This is the third in a series of reports I am publishing.

First Report (4/24/2018): US Shale: NAV Analysis of Diversified Oil-Weighted E&Ps, covering EOG Resources (NYSE:EOG), Devon Energy (NYSE:DVN), Continental Resources (NYSE:CLR), QEP Resources (NYSE:QEP), WPX Energy (NYSE:WPX), Cimarex Energy (NYSE:XEC)

Second Report (4/27/2018): US Shale: NAV Analysis of Permian Basin – Delaware Basin E&Ps, covering Concho Resources (NYSE:CXO), Halcon Resources (HK), Matador Resources (NYSE:MTDR), Centennial Resource Development (NASDAQ:CDEV); Jagged Peak Energy (NYSE:JAG) and Resolute Energy (NYSE:REN)

These reports value about 50 US shale exploration and production companies (“E&Ps”) based on their net asset values (“NAV”). Each quarter, I expect to publish new reports with updated quarterly information. Also, because I track a substantial amount of information on each company, from time to time I also intend to publish E&P sector wide trends reports.

This report values the E&Ps focused on the Permian Basin – Midland Basin: 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 (NYSE:ESTE) and RSP Permian (NYSE:RSPP) (on March 28, 2018 CXO announced the acquisition of RSPP but I will still include RSPP in this report)

Williston Basin (aka Bakken): Whiting Petroleum (NYSE:WLL), Oasis Petroleum (NYSE:OAS), Northern Oil and Gas (NYSEMKT:NOG) and Abraxas Petroleum (NASDAQ:AXAS)

Eagle Ford Shale: Carrizo Oil and Gas (NASDAQ:CRZO), SM Energy (NYSE:SM), EP Energy (EPE), Sanchez Energy (SN) and Penn Virginia (OTC:PVAC)

Denver-Julesberg (“DJ”) Basin (aka Niobrara): PDC Energy (NASDAQ:PDCE), Extraction Oil and Gas (NASDAQ:XOG), SRC Energy (NYSEMKT:SRCI) and Bonanza Creek Energy (NYSE:BCEI)

Anadarko Basin: Newfield Exploration (NYSE:NFX), Jones Energy (JONE) and Gastar Exploration (NYSEMKT:GST)

Marcellus+Utica Shale – Dry Gas: Cabot Oil and Gas (NYSE:COG), Gulfport Energy (NASDAQ:GPOR), EQT Corporation (NYSE:EQT), Southwestern Energy (NYSE:SWN) and Eclipse Resources (ECR)

Marcellus+Utica Shale – Wet Gas: Antero Resources (NYSE:AR), Range Resources (NYSE:RRC) and Rex Energy (NASDAQ:REXX)

Other Dry Gas E&Ps: Chesapeake Energy (NYSE:CHK), Ultra Petroleum (UPL) and Comstock Resources (NYSE:CRK)

Summary Results

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

In evaluating the various criteria, FANG and CPE are the most attractive investment opportunities among the Midland Basin E&Ps. PXD, LPI, PE and EGN are also attractive investment opportunities but less so than FANG and CPE. ESTE is over-valued.

On March 28, 2018 CXO announced the acquisition of RSPP via shares of CXO, so RSPP trades in lock-step with CXO (as of April 27, 2018 RSPP trades at a 2% discount to the merger price).

AREX is a mixed bag. Relative to its resource base, AREX is very inexpensive. But, AREX has too much debt which prevents it from producing resource base fast enough. As a result, the NPV of the cash flows is low and the resulting equity value on a DCF basis is negative. AREX’s largest shareholder, Wilks Brothers, owns 47.96% of the common shares outstanding and holds $60 million of AREX’s $85 million outstanding 7% notes due 2021. In a April 12, 2018 13D Filing, Wilks disclosed its interest in converting the notes to common shares but this requires agreement on an exchange ratio and waiving of a current agreement whereby Wilks Brothers is restricted from owning more than 48.61% of the common shares outstanding. These discussions appear to be on-going. Assuming a debt for equity swap, AREX could reduce its debt sufficiently such that they could potentially increase their drilling program, pulling forward the value of their large asset base. At this point, AREX is a call option on a recapitalization or buyout.

For the most part, the entire group of Midland Basin focused E&Ps are attractively priced relative to their asset base and on a DCF basis. CPE, FANG and RSPP generate some of the highest EBITDA per BOE of all the US shale E&Ps. CPE, FANG, RSPP, PE and PXD have some of the lowest drilling and completion costs per BOE across all the US share E&Ps. Despite having some the best assets generating the highest returns, the group trades in line with or at a discount to shale E&Ps focused on other shale basins.

I am long FANG, CPE, PXD, RSPP, LPI, PE and AREX.

Valuation Methodology

In the report, all market value analyses apply April 27, 2018 stock prices. Financial and operating data are based on December 31, 2017 results and are adjusted, as appropriate, for transactions occurring after December 31, 2017. Assumed commodity prices in 2018 are $65 oil WTI at Cushing, $35.75 NGL at Mont Belvieu and $2.75 natural gas at Henry Hub. In 2019 and beyond I assume $62.50 oil, $35.94 NGL and $2.75 natural gas. These commodity prices are before basis differentials.

As it relates to basis differentials, for 2018 estimates I apply current discount levels to different basins, but for DCF analysis I assume that sufficient infrastructure is built such that differentials normalize. Where the Williston Basin recently experienced discounts to WTI oil of $10 per barrel, with the addition of the DAPL pipeline in 2017, basis has now come down to $4 or so. Currently, the Permian Basin lacks sufficient pipeline infrastructure and oil is trading at $8 to $12 discounts to WTI oil at Cushing. In time, though, new pipelines will be built and these discounts will normalize back to $2 or so. Since I am doing NAV valuation analysis, which takes into account 20 to 30 or more years of production and cash flows, a year or two of $10 discounts to WTI does not really matter.

Like any resource company, an E&P is worth the net present value of its projected cash flows from the extraction of a finite resource, in this case oil and gas. Without purchasing additional extraction rights, an E&P can only produce a finite amount of oil and gas and thus a finite amount of cash flows. With this idea, NAV analysis (forecasting the cash flows from an E&P’s asset base) is the most appropriate way to value an E&P company. Using earnings and cash flow multiples to value E&Ps can be very misleading because they do not capture the volume of oil and gas that can be extracted, but instead simply value the profitability of the oil and gas currently being extracted.

For the past four years, I have been modeling about 50 E&Ps to assess the quality and quantity of their oil and gas resources. Each company requires about 5,000 rows of inputs and formulas in Excel to determine:

  1. The amount of potential future oil and gas that can be extracted and associated annual future production levels until all the potential resource has been extracted
  2. The amount of capital expenditures required to extract the oil and gas
  3. The revenue and cost per barrel of oil equivalent (“BOE”) related to the production of the oil and gas
  4. The net present value of the cash flows resulting from the prior three analyses
  5. The value the market is assigning to the E&P’s oil and gas assets

This report will walk you through the results of these five analyses for each company, enabling you to view relative and absolute valuations for each company.

Finally, I do not focus on E&Ps’ commodity hedging position as it relates to an investment thesis, unlike many readers on Seeking Alpha. Hedges are basically in place for 12 months, and sometimes 24 months for some volumes. But, when you are valuing 20-30-40 years of production, whether 2018 is hedged or not is irrelevant to the NAV value. Instead, I capture the value of the hedges, whether net assets or net liabilities, via the value on the balance sheet transferred through to the calculation of enterprise value.

Oil and Gas Resource Potential

Each E&P’s oil and gas resource potential is a function of two things: wells that have already been drilled and leased and/or owned land that can be drilled in the future. Wells that have already been drilled are represented by company proved developed reserves disclosures. Resource from land that can be drilled in the future must be calculated. While companies provide proved undeveloped reserves (“PUDs”), representing resource potential that has not yet been drilled, PUDs do not account for all of the land upon which an E&P is entitled to drill. Thus, I ignore PUDs. Instead I do the following:

  1. Determine the number of acres upon which and E&P can drill
  2. Estimate the number of future drilling sites on such acreage and, based on the E&P’s ownership interests, estimate the net number of future drilling sites
  3. Estimate the average estimated total oil and gas resource that will be extracted from each well (“EURs”)
  4. Estimate the net royalty interest per well that must be provided to the land owner whose land is being leased, which is “paid” in production not cash, and thus reduces the amount of oil and gas the E&P can sell for itself
  5. Estimate what percentage of the resource extracted is oil vs. natural gas liquids (“NGLs”) vs dry natural gas (“nat gas”)

By adding the proved developed reserves that the E&Ps disclose in their regulatory filings with the calculation of resource potential from undrilled acreage, I can estimate the total volume of oil and gas that an E&P can produce from their existing asset base. I can also estimate how much of the resource will be oil vs NGLs vs nat gas. This distinction is very important because the value of oil, NGLs and nat gas are not the same. While 1 barrel of oil is the energy equivalent of 6,000 cubic feet of nat gas, 1 barrel of oil is currently worth about $68 where 6,000 cubic feet of gas is worth about $17.10 ($2.85 per 1,000 cubic feet, “mcf”). Thus, oil generates about four times more value per the same energy equivalency as nat gas. As a result, when I evaluate an E&P's oil and nat gas resource, I do not treat them as 6:1 energy equivalents but instead as 23.6:1 economic equivalents (my long-term oil price forecast is $62.50 per barrel and my long term nat gas price forecast is $2.75 per mcf). Likewise, I forecast a barrel of NGLs to be worth $35.94 in the long term and thus treat oil as 1.74:1 the value of a barrel of NGLs.

Chart 1 below shows the Proved Reserves and potential resource from future drilling sites for each company in this report. The chart also shows the aggregate amounts for the group of companies I follow that focus on a particular geography. For example, MTDR is included in the Permian Basin – Delaware basin group, so all of MTDR’s resource base is included under this column, even though some of the resource base is from the Eagle Ford and Haynesville shale basins. Please keep this concept in mind as you review all the charts to follow.

With the exception of PXD, the eight other Midland Basin E&Ps operate exclusively in the Permian Basin. A few have land positions in the Delaware Basin, but all nine are primarily focused on or derive the preponderance of their production from the Midland Basin. PXD is in the process of selling all its non-Permian Basin assets and by year end should be a Permian pure-play. All of PXD’s numbers in this report assume the sale of the non-Permian assets for total sale proceeds of $851 million. Thus, the production, proved reserves and potential resource base from these non-Permian assets are excluded from PXD.

FANG, CPE, RSPP, PE, PXD, EGN and ESTE have acreage primarily in the Northern Midland Basin which has a very high oil content. AREX has acreage in the Southern Midland Basin which is has a very low oil content but reasonably high NGL content. LPI’s acreage is in-between the Northern and Southern Midland basins so its oil content is better than AREX’s but still far below E&Ps such as CPE, FANG and RSPP.

From a size standpoint, PXD is about the same size as the other eight companies combined. Among the large cap E&Ps I follow (EOG, CLR, CXO, DVN), PXD has the second largest market cap. It also trades at one of the lowest valuations despite having arguably the best assets, profitability and balance sheet of the group. All nine of the Midland Basin E&Ps have a large asset base to drill. PE, PXD and LPI, in particular, have accumulated pretty massive asset bases.

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

While more oil and gas resource is better than less, the weighting of oil vs NGL vs nat gas production, the prices received for each, the cost to drill and complete (“D&C”) a new well and the operating expenses required to produce the resource determine how profitable the resource is to extract.

First, I provide estimated D&C costs per adjusted BOE (adjust the volume of natural gas using 23.6:1 and the volume of NGLs using 1.74:1, as described above).

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

PXD, PE, FANG, RSPP and CPE has some of the lowest D&C costs of any E&P I follow. These are some of the best shale assets there are. AREX has a pretty high D&C cost per BOE because the resource base is so heavily weighted to nat gas and NGL. LPI’s D&C costs are actually quite good considering how high the resource base is weighted to NGLs and nat gas. Considering EGN’s and ESTE’s oil cut, their D&C costs are somewhat disappointing.

Next, I analyze the profitability of each BOE produced. This analysis considers production weightings across oil, NGLs and nat gas, prices realized for each and operating expenses. The result is EBITDA per BOE. This is the purest number to assess the quality of the E&P as operator and/or the quality of the E&P’s land position (not all land is the same regarding the volume and type of resource and cost to extract the resource). I make an adjustment to the historical EBITDA per BOE results disclosed by every E&P by removing the impact of hedging. Hedging has nothing to do with operations, so if hedge settlements are included in the EBITDA results, it distorts how productive the assets and operator are, as opposed to how good the E&P is at financial matters. Also, by excluding hedging, we can compare the E&Ps on an apples-to-apples basis.

Chart 3 below shows EBITDA excluding hedging per BOE for each company and companies focused on the various geographies for the past four historical quarters and my 2018 full year estimate. I also provide the breakdown between oil, NGL and nat gas 2018E production since these weightings have a strong influence on operating profitability.

CPE consistently has been the most profitable of the group and is the most profitable shale E&P I follow. In addition to having excellent assets with a high oil weighting, CPE has invested heavily in infrastructure to drive down operating expenses. FANG, RSPP and PE have also been some of the most profitable E&Ps I follow, although PE’s profitability has been progressively trailing CPE, FANG and RSPP over the past four quarters. EGN’s profitability is a bit disappointing when considering how much of its production is oil. PXD’s profitability is a bit misleading since it includes production outside of the Permian Basin that is relatively low profit. Looking at PXD’s 2018E EBITDA per BOE gives a better sense of the profitability of its Permian assets. ESTE is forecasting strong profitability in 2018 but they will have to prove it given they have rolled up several acquisitions and have the most execution risk of the group. LPI and AREX are the least profitable given they have the lowest oil weightings in their production.

E&P Equity and Enterprise Values

Finally, I calculate the value the market is ascribing to each E&P’s resource base. I do this by determining the number of fully diluted common shares to calculate the equity market value. I then add the following liabilities and subtract the following assets to determine the market’s value for the E&P’s oil and gas resources (“Enterprise Value” or “EV”).

Liabilities added: Debt, Preferred Stock, Out-of-the-money convertible debt and preferred stock, minority interest ownership in the oil and gas resource, hedging liabilities and asset retirement obligations.

Assets subtracted: Cash, hedging assets, net present value of net operating loss carry-forwards, equity interests in assets other than the E&Ps oil and gas resources (such as an investment in a pipeline system or shares held in a publicly traded company). To the extent an E&P consolidates the operations of another publicly traded company (such as FANG does with Viper Energy (NASDAQ:VNOM)), I adjust the E&P’s resource assets and operating results to exclude the consolidated subsidiary but include the value of the subsidiary’s shares owned by the E&P in the E&P’s Enterprise Value.

Chart 4 below shows the equity value and enterprise value for each E&P and companies focused on the various geographies.

PXD is one of the five largest shale E&Ps I follow. PE, FANG, EGN and RSPP are Mid-Caps, CPE and LPI are larger Small-Caps and ESTE and AREX are Micro-Caps. FANG has about $2 billion in equity value attributed to its VNOM share holdings. ESTE does not own 100% of the entity that owns its assets, thus it has a large minority interest. Same situation for PE, although its minority interest is much smaller than ESTE as a percentage of equity value.

Relative and Absolute Valuation Analysis

We now have the total future resource production potential, the cost to drill future wells, the profitability of extracting the resource and the value that the market places on each E&P’s resource base. With these, we can calculate ratios and evaluate relative valuations for the E&Ps. We can also perform a DCF of the future cash flows from extracting the oil and gas resource to compare the markets assessment of an E&P’s equity value relative to the intrinsic equity value derived from the NAV analysis.

Every E&P discloses proved developed reserves, representing wells that have been drilled and are producing oil and gas. The proved developed reserves are an estimate of how much oil and gas will be produced over the life of these already drilled wells. And, while the ultimate amount of oil and gas that is produced can vary from the numbers the companies disclose, it is as close of an estimate as we have. So, to value the proved developed reserves, I multiply each E&Ps 2018E EBITDA excluding hedges per BOE by the proved reserves. With this, I can forecast the total cash flows that will be generated by the already drilled wells. I use 2018E EBITDA instead of a historical EBITDA because 2018E EBITDA better represents my long-term views on commodity prices and production levels. Also, historically, my forecasted EBITDA numbers have been quite accurate. Lastly, given proved developed reserves take varying years to produce, I apply a time value discount factor to the EBITDA multiplied by proved developed reserves to calculate a present value of the cash flows from extracting all the proved developed reserves.

If I take the E&P’s Enterprise Value and subtract the value of the proved developed reserves as I just described, I can back into the value the market is assigning to each E&P’s future drilling locations. This is the key number is assessing relative valuation.

The challenge with this analysis is knowing how long it will take to produce the proved developed reserves. So, another way to evaluate the markets’ implied value for each E&P’s future drilling locations is to subtract the E&P’s PV-10 from Enterprise Value and divide that number by the estimated future drilling locations adjusted resource amount exclusive of PUDs (since PUDs are included in the PV-10 calculation).

Regardless of which method I use, this analysis is my primary guide in determining relative valuations among the US shale E&Ps. While I perform DCFs, and present them below, DCFs are very difficult to do. Forecasting the production schedule associated with specific D&C capital expenditures has substantial risk of error since the production of a shale well declines significantly over time. To accurately forecast production, I would need to forecast production for every well drilled by each E&P. While its possible to do this, it simply is not practical from a time standpoint for me to do this for 50 companies (modeling E&Ps is not my primary profession). So, due to the error risk in forecasting 10 or 20 plus years of capital expenditures and related production, I focus more on valuing the relative values of the undrilled resource base, in which I have a much higher confidence level.

Of the two analyses, I place more weight on EV Less PV-10 since the reservoir engineers calculating this number have significantly more detailed information than I do. Chart 5 below shows the two calculations described above for each E&P and companies focused on the various geographies.

CPE and RSPP trade at somewhat high prices relative their resource base, but this is understandable given how profitable their assets are. Same goes for FANG, but its valuation is pushing it. PXD and PE are extremely cheap relative to the size of their resource base. Same goes for LPI and AREX, which are valued at some of the lowest levels of all the E&Ps I follow. EGN is also attractively valued. Given ESTE’s execution risk, its valuation is quite high, especially when compared to a CPE.

The consistent trend you will see in the above analysis is the larger the future drilling site resource base, the cheaper the valuation. The market either treats all E&Ps the same and values current production levels independent of how long those production levels will last. Or, the market places a large discount on the future drilling site resource base. But, the net effect is to undervalue E&Ps with large future drilling site resource bases.

Finally, I perform a DCF analysis to value each E&Ps equity. I perform DCFs with levered (after interest expense and preferred dividends) and unlevered (excluding interest expense and preferred dividends) cash flows. I use a 10% discount rate, so if a company’s cost of debt and preferred is lower than 10% then the levered DCF will result in a higher equity value than the unlevered DCF. If you assume that the debt and preferred can be perpetually refinanced, then using levered cash flows is reasonable. At the same time, the more consistent approach is to value the E&P assets independent of capital structure using unlevered cash flows and then adjust for capital structure to derive an equity value. This way, E&Ps are compared on an apples-to-apples basis without varying capital structures distorting the analysis. There are merits in both approaches. I will provide you the results and you can choose for yourself which has more merit. Following what I wrote above, I want to emphasize again there is a high level of error around the DCF analysis because it is very difficult to forecast the production schedule that results from D&C capital expenditures and the existing proved developed reserves.

A key assumption for the DCF analysis is the oil and gas production rate in the future. The faster the oil and gas is produced, the higher the net present value of the associated cash flows (the DCF analysis estimates the capital expenditures required to produce increasing amounts of oil and gas). In Chart 6 are the production growth rate assumptions for the E&Ps and various geographies.

All 2018 production estimates are based on E&P company provided guidance. If an E&P offers guidance beyond 2018, I use such guidance as a reference and modify it, as appropriate, based on how realistic I believe the guidance to be. PXD is forecasting a production decline because they expect to sell all their non-Permian Basin assets in 2018.

Chart 7 provides the levered and unlevered DCF analysis equity results.

CPE and FANG are undervalued, EGN is somewhat undervalued, PXD, LPI and PE are about fairly valued, and ESTE and AREX are over-valued on a DCF basis. While RSPP is undervalued on a DCF basis, it will trade in line with CXO given CXO is acquiring RSPP in a 100% stock for stock transaction.

Lastly, from a qualitative standpoint, the market discounts E&Ps for excessive debt and capital expenditure budgets not funded by free cash flow. In Chart 8, I provide these metrics for the E&Ps and companies focused on the various geographies.

Net Debt is calculated as debt and preferred plus hedging liabilities less cash and hedging assets.

PXD and ESTE have pristine balance sheets with basically no debt net of cash. PE, FANG, RSPP, CPE, EGN and LPI also have extremely strong balance sheets. AREX has much too much debt which prevents AREX from investing sufficiently on capital expenditures to grow its production.

The Midland Basin group is living within cashflow, producing operating cash flow 5% above capital expenditures. That said, the group is mixed. PXD, FANG, RSPP and LPI are forecast to generate positive free cash whether or not you include the impact of hedges. PE, CPE, EGN, ESTE and AREX will all mildly burn more cash than they generate in the range of 5% to 15%. What is most impressive, though, is that FANG is growing production by 41% and will still be free cash flow positive. CPE, RSPP and PE are growing production 35% to 50% and will be free cash flow positive or not far from it.

Overall, the Midland Basin E&Ps have made investments over the past few years in arguably the best shale assets in the US and now are reaping the rewards through highly profitable growth.

Disclosure: I am/we are long CPE, FANG, PXD, LPI, RSPP, PE, 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 author's 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 author's best judgment as of the date of publication, and are subject to change without notice.