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

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Includes: CDEV, CXO, HK, JAG, MTDR, REN
by: Andre Kovensky

Summary

HK is deeply undervalued.

CXO and JAG are fairly valued.

CDEV, MTDR and REN are over-valued.

This is the second 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)

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 – Delaware Basin: Concho Resources (NYSE:CXO), Halcon Resources (NYSE:HK), Matador Resources (NYSE:MTDR), Centennial Resource Development (NASDAQ:CDEV); Jagged Peak Energy (NYSE:JAG) and Resolute Energy (NYSE:REN).

Future reports will value:

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 (NASDAQ:ESTE) and RSP Permian (NYSE:RSPP) (on March 28, 2018 FANG 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 (NYSE:EPE), Sanchez Energy (NYSE: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 (NYSE: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 (NYSE:ECR)

Marvellus+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 (NASDAQ: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, HK is the most attractive investment opportunity among the Delaware Basin E&Ps. JAG and REN are about fairly valued. CXO and MTDR are a bit over-valued and CDEV is highly over-valued. In looking at EV less PV-10 divided by the price adjusted future drilling site source excluding PUDs, HK trades at $0.11 per BOE. This means, you can buy HK and get the entire undrilled land position for $0.11 per BOE, which effectively is free. HK is the best value of any of the 50 shale E&Ps I follow. I am long HK but have no positions in any of the other Delaware Basin E&Ps.

Valuation Methodology

In the report, all market value analyses apply April 20, 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.

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&Ps 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 as well as by geography for the companies I research.

CXO is the largest of the Delaware Basin E&Ps. All of CXO’s resource base is within the Permian Basin. CXO’s resource base is a bit low in oil content at 60% compared to others in 70% to 80% range. CXO only reports its production and reserves on a 2-stream basis, meaning the NGLs are included in the nat gas. CXO’s numbers in this report are stand-alone and do not include RSPP which CXO announced in March 2018 it would acquire. After the acquisition closes, I will update CXO’s numbers. HK is the second largest. In 2017, HK emerged from bankruptcy, bought Delaware Basin land leases and sold off all its non-Permian assets. HK now has an unlevered balance sheet and ample cash to develop its large exclusively Delaware Basin resource base. At 2018E production levels, it would take HK 379 years to produce all its potential resource. CDEV, JAG and MTDR are comparably sized and have good weightings to oil. Relative to current production levels, JAG has twice the resource base of CDEV and MTDR. JAG and CDEV have land leases exclusively in the Delaware basin. Like CXO, MTDR reports on a 2-stream basis. MTDR has land leases in the Eagle Ford and Haynesville shales, but 90% of MTDR’s oil production and proved oil reserves come from the Delaware Basin, and future drilling is also focused on the Delaware Basin. REN has a small resource base and has a low oil weighting and high nat gas weighting. REN sold off assets in 2017 and is now exclusively focused on the Delaware Basin.

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 various geographies.

HK has the lowest D&C costs, whether compared to the other Permian-Delaware companies or the other basin averages. CXO, JAG, MTDR and REN all have about average D&C costs. CDEV’s D&C costs are on the high side.

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 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.

JAG consistently has been the most profitable of the group and is one of the most profitable shale E&Ps I follow. CXO and CDEV are solidly profitable. MTDR’s profitability is about average historically, but in 2018 is forecast to increase as its past investments in infrastructure lower costs. REN’s historical profitability is impacted by the assets it sold in 2017. In 2018 REN will need to prove its ability to profitably operate its Delaware Basin assets. REN also suffers from a low oil weighting, which drags down profitability. HK is in a transition given it sold all its non-Delaware Basin producing assets and used the proceeds to buy its Delaware Basin land position. This is why HK’s EBITDA per BOE was only $2.17 in Q4 2017. HK has work to do to prove to investors it can profitably develop its resource base.

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 various geographies.

CXO is one of the five largest shale E&Ps I follow. CDEV and MTDR are mid-sized, while JAG is a smaller mid-sized. REN is a good sized small cap.

HK is a small cap. HK also suffers from a huge overhang of shares. Franklin Resources (“Franklin”) was a debt holder whose debt converted to equity in the recent bankruptcy. Franklin is selling down all its HK holdings via open market sales. Franklin’s mandate is to invest in debt and income securities, not shale E&Ps. Since last year through to the present, Franklin was actively sold shares, putting substantial pressure on the stock price. As of Franklin’s April 3, 2018 13D filing, Franklin still owns about 10.9 million shares, or 6.8% of the shares outstanding. Until Franklin sells down all its shares, the overhang is a drag on the share performance. Ideally, HK management could negotiate with Franklin to buy back the final shares and remove the overhand. Given the significant discount in the share price and HK’s low leverage, buying the Franklin shares would be very value accretive. Pro forma for transactions in 2018, HK has about $380 million in cash exclusive of 2018 year to date operations. At $5.50 per share, it would cost HK about $60 million. As an HK shareholder, I hope they do this.

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 it's 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.

Chart 5 below shows the two calculations described above 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 this number have significantly more detailed information than I do. CDEV and MTDR trade at high prices for their future drilling site resource base, relative to the other Delaware Basin companies and the other basin averages. Permian Midland Basin E&Ps trade at $1.83, less than half the valuation of CDEV and MTDR. REN is also quite expensive. CXO and JAG are appropriately valued. HK trades at only $0.11 per BOE of future drilling site resource. This means when you buy HK you basically get the undrilled land position for free. On this metric, HK has the lowest valuation of any E&P I follow.

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 required, based on how realistic I believe the guidance to be. HK is growing production very rapidly because they are starting from a very small base.

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

HK is greatly undervalued, JAG and REN are about correctly valued, CXO and MTDR are a bit over-valued and CDEV is overvalued on a DCF basis.

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 the various geographies.

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

CDEV and JAG are the least levered of the Delaware Basin E&Ps, as well as compared to the various geographies. CXO, MTDR and HK all have low leverage. REN’s leverage is little above average but not alarming. As REN grows its production and thus its EBITDA, it will bring down its leverage.

The Delaware Basin group is not living within cashflow, producing operating cash flow 6% below capital expenditures. CXO is the exception, estimated to generate operating cash flows 31% in excess of capital expenditures (excluding the impact of hedging settlements). Given CXO’s size, without CXO the group’s cash shortfall would be much worse. Also, CXO and MTDR are both forecasting about 18% production growth in 2018 yet MTDR is forecast to generate operating cash flows 15% below capital expenditures. CDEV and JAG are in massive growth mode, forecasting 86% and 74% production growth, respectively, and thus the negative free cash flow. In 2017, REN and HK sold large producing asset bases and thus must spend heavily to re-grow production.

Disclosure: I am/we are long HK.

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.