This is the first in a series of reports I will publish. These reports will 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 first report values the E&Ps focused on oil in multiple basins: EOG Resources (NYSE:EOG), Devon Energy (NYSE:DVN), Continental Resources (NYSE:CLR), QEP Resources (NYSE:QEP), WPX Energy (NYSE:WPX), and Cimarex Energy (NYSE:XEC).
Future reports will value:
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).
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).
Here is a summary of the results I will describe in this report.
In evaluating the various criteria, CLR and QEP are the most attractive investment opportunities among the Diversified Oil E&Ps. As QEP sells its non-Permian assets, its EBITDA per BOE should increase to $35 to $40 and its leverage should decline. EOG, WPX and XEC are highly overvalued. DVN is about fairly valued.
In the report, all market value analyses apply April 20, 2018, stock prices. Assumed commodity prices in 2018 are $65 oil, $35.75 NGL, $2.75 natural gas and in 2019 forward $62.50 oil, $35.94 NGL, $2.75 natural gas. These commodity prices are before basis differentials.
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:
- 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.
- The amount of capital expenditures required to extract the oil and gas.
- The revenue and cost per barrel of oil equivalent (“BOE”) related to the production of the oil and gas.
- The net present value of the cash flows resulting from the prior three analyses.
- 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 land that can be drilled in the future. Wells that already have been drilled are represented by company proved developed reserves disclosures. Leased 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 leased land upon which an E&P is entitled to drill. Thus, I ignore PUDs. Instead I do the following:
- Determine the number of acres leased.
- 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.
- Estimate the average estimated total oil and gas resource that will be extracted from each well (“EURs”).
- 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.
- 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 also can 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 one barrel of oil is the energy equivalent of 6,000 cubic feet of nat gas, one barrel of oil is currently worth about $65 where 6,000 cubic feet of gas is worth about $15.90 ($2.65 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 as well as by geography for the companies I research.
CLR has a large resource base split between the Williston and Anadarko basins and a reasonably high weighting of oil and NGLs. EOG has a very small resource base relative to its current production level. The resource base is spread over the Permian basin, Eagle Ford, Williston basin, Anadarko basin and Powder River basin (Wyoming). DVN has a large resource base primarily spread over the Permian basin, Eagle Ford, Barnett shale, Anadarko basin and Canada. DVN is highly weighted to low profitability nat gas and a significant volume of oil production is low margin Canadian heavy oil. XEC has an average sized resource base split between the Permian and Anadarko basins, but like DVN has a high nat gas weighting, which is a negative. WPX has a relatively large resource base split between the Willison and Permian basins and a reasonably high oil weighting but also a high nat gas weighting. Finally, QEP currently has a small resource base spread over the Permian, Williston and Uinta basins, and the Haynesville shale. On February 28th, 2018, QEP announced its intention to sell all assets other than the Permian basin assets. Given the value of the non-Permian assets are unknown until the sale processes finish, for now I treat QEP as a “diversified” E&P but upon sales of the targeted assets, I will move QEP to the Permian Basin – Midland Basin category.
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.
CLR has very low adjusted D&C costs, whether compared to the other diversified companies or the geographic averages. XEC has very high adjusted D&C costs because of its high weighting to nat gas. DVN also suffers from a high nat gas weighting. EOG and QEP have attractive adjusted D&C costs and WPX has about average adjusted D&C costs.
Next, I analyze the profitability of each BOE produced. This takes into account 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 should note that I make an adjustment to the historical EBITDA per BOE results disclosed by every E&P. I remove 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.
CLR consistently has been the most profitable of the group. EOG has solid profitability. WPX is forecast to increase its profitability in 2018 as its production weighting turns more to oil, going from 56% oil in 2017 to 64% oil in 2018. DVN, XEC and QEP suffer from higher nat gas production weightings.
E&P Equity and Enterprise Values
Finally, I will 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 of 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.
EOG is the largest E&P I follow. CLR and DVN also are among the five largest E&Ps by market value. WPX and XEC are mid sized and QEP is more toward a small cap.
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 also can 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's produced can vary from the numbers the companies disclosed, 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).
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. DVN’s future drilling sites trade at the lowest price, even after adjusting for the lower value of nat gas and NGLs relative to oil. DVN also is relatively inexpensive relative to the various geographies averages (which are weighted, not simple averages). CLR, QEP and WPX are all comparably valued and in line with the Permian Basin E&Ps, more than the Eagle Ford, Willison and Anadarko E&Ps and a discount to the DJ E&Ps. In summary, this group trades in line with the sector. XEC trades at a premium to the sector but not wildly so. EOG trades in a world of its own. I call EOG the Tesla of shale because its valuation is completely disconnected from any other E&P. As you will see in a future note, PXD, a large cap, world class E&P trades at $1.74 per BOE of future drilling resource, compared to EOG at $15.13.
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.
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 does take into account 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. While QEP’s production is declining in 2018, this is due to asset sales. In 2019, QEP should be a Permian pure-play and accelerate production.
Chart 7 provides the levered and unlevered DCF analysis equity results.
CLR and QEP are highly undervalued, DVN is about correctly valued, EOG and WPX are overvalued and XEC is wildly overvalued relative to their intrinsic NAV values.
Lastly, from a qualitative standpoint, the markets 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. DVN, EOG and XEC are the least levered of the diversified oil E&Ps, as well as compared to the various geographies. CLR and QEP are highly levered relative to their price adjusted proved developed reserves and 2018E EBITDA. As QEP sells its non-Permian Basin assets, it should bring down its debt levels. WPX is highly levered relative to price adjusted proved developed reserves but not relative to 2018E EBITDA.
The diversified oil group is living within cash flow, producing operating cash flow 20% in excess of capital expenditures. CLR, DVN and EOG are estimated to produce operating cash flows 50% to 27% greater than capital expenditures. XEC’s estimated operating cash flow is in line with capital expenditures. WPX would cover capital expenditures with operating cash flows if not for its hedges which will drag on cash flows. QEP’s operating cash flows will only cover 67% of capital expenditures, putting QEP at the bottom of its peer group and near the bottom of all the geographies.
Disclosure: I am/we are long CLR.
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.