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 is the sixth 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)
Third Report (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 (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)
Fourth Report (5/4/2018): US Shale: NAV Analysis of Williston Basin (Bakken) E&Ps, covering Whiting Petroleum (NYSE:WLL), Oasis Petroleum (NYSE:OAS), Northern Oil and Gas (NYSEMKT:NOG) and Abraxas Petroleum (AXAS)
Fifth Report (5/7/2018): US Shale: NAV Analysis of Denver-Julesberg Basin (Niobrara) E&Ps, covering PDC Energy (NASDAQ:PDCE), Extraction Oil and Gas (NASDAQ:XOG), SRC Energy (NYSEMKT:SRCI) and Bonanza Creek Energy (NYSE:BCEI)
Future reports will focus on:
Here is a summary of the results I will describe in this report.
In evaluating the various criteria, CRZO is undervalued on a resource basis but about fairly valued on a DCF basis. SM is undervalued on a resource basis but overvalued on a DCF basis. EPE is about fairly valued on a resource basis but overvalued on a DCF basis. PVAC is about fairly valued on a resource basis but undervalued on a DCF basis. SN is about fairly valued on both a resource basis and DCF basis. Based on their proximity to the US gulf coast, the group should realize oil prices in excess of WTI at Cushing for several years, which is a huge positive when most investors (traders) in E&Ps are more focused on catalysts and themes than NAV. PVAC is the most profitable of the group generating some of the highest EBITDA per BOE of any of the US shale E&Ps I cover. This is largely because of PVAC's high oil production weighting and gulf coast proximity. CRZO is also quite profitable on an EBITDA per BOE basis, which also derives from its high oil production weighting. SM and SN have low oil production weightings leading to low profitability on an EBITDA per BOE basis. The group has relatively high D&C per Adjusted BOE costs.
Given PVAC's significant oil weighting and DCF value, I am long PVAC.
In the report, all market value analyses apply May 4, 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, especially since the Permian can directly access the US gulf coast. 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 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:
- 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.
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 typically 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:
- Determine the number of acres upon which and E&P can drill
- 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 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 $70 where 6,000 cubic feet of gas is worth about $16.50 ($2.75 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 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.
CRZO operates primary in the Eagle Ford, but also in the Permian Basin-Delaware Basin. Recently, CRZO sold its Utica shale and Niobrara shale assets. CRZO's Delaware Basin assets are split into two areas: in the western half in Culbertson county and the eastern half in Reeves and Ward counties. The Culberson country assets are very high in nat gas and of not much value, but the Reeves and Ward counties' assets production is about 50% oil. About 80% of 2018E oil production and 75% of proved oil reserves are from the Eagle Ford. CRZO's future drilling site oil resource base is about 45% from the Eagle Ford and 55% from the Delaware Basin.
SM operates in the Eagle Ford and Permian Basin-Midland Basin. In March 2018 SM closed on the sale of the Powder River Basin assets and should close on the sale of its Williston Basin assets in 2018 Q2. Excluding the PRB and Williston Basin assets, SM's production is about 54% from the Eagle Ford and 46% from the Midland Basin. SM's Eagle Ford oil production is about 8% of total Eagle Ford production, where Eagle Ford nat gas production is about 60% of total Eagle Ford production. SM's Midland Basin oil production is about 77% of total Midland Basin production. SM's future drilling site oil resource base is 93% from the Midland Basin. Given SM is rapidly transitioning to a Midland Basin oriented operator, both in terms of production volumes and revenues, SM will be included in the Permian Basin-Midland Basin grouping in future reports.
EPE operates in the Eagle Ford, Permian Basin-Midland Basin and the Uinta Basin. The Permian Basin assets are in the Southern Midland Basin, which has a high nat gas and NGL weighting. Thus, EPE's Midland Basin assets are not of the same quality as Midland Basin E&Ps such as CPE, FANG, PXD, RSPP and PE. Oil production is derived about 45% from the Eagle Ford, 28% from the Midland Basin and 28% from the Uinta Basin. Total production is derived about 38% from the Eagle Ford, 40% from the Midland Basin and 22% from the Uinta Basin. EPE's future drilling site resource base is 64% from the Midland Basin, 16% from the Eagle Ford and 20% from the Uinta Basin. Given EPE is quite evenly spread across these three geographies, EPE will be included in the Diversified Oil-Weighted grouping in future reports.
PVAC and SN almost exclusively operate in the Eagle Ford shale. SN is the western Eagle Ford and its production and reserves are split evenly between oil, NGLs and nat gas. PVAC is in the Eagle Ford's oily window and 78% of proved reserves and 76% of production are oil.
From a size standpoint, with the exception of EPE, CRZO, SM, PVAC and SN have relatively small resource 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.
D&C Costs per Adjusted BOE for the group are relatively high given the high nat gas weighting. SM's D&C costs look low, but actually are high compared to the Marcellus shale oriented nat gas E&Ps (pure play nat gas E&Ps). SM's Permian Basin-Midland Basin D&C Cost per Adjusted BOE is $12.04, quite a bit higher than the Permian Basin-Midland Basin group of E&Ps at $10.61. CRZO's Permian Basin-Delaware Basin D&C costs are $11.31, which are superior to the Permian Basin-Delaware Basin group. For the Eagle Ford group, excluding SM, Eagle FordD&C costs range from about $13.25 to $15.50 per BOE, putting the Eagle Ford at the high end of all the oil-oriented basins I cover. EPE's Permian Basin D&C costs are $16.05 per BOE versus AREX, which operates exclusively in the Southern Midland Basin, at $15.05 per BOE.
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 companies focused on 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.
The group's profitability varies greatly; the higher the oil weighting the higher the EBITDA per BOE. PVAC has the highest production weighting to oil, resulting in the highest EBITDA per BOE. PVAC is one of the most profitable E&Ps I follow. CRZO is also solidly profitable given its high oil production weighting. SM has the highest nat gas weighting and the lowest profitability. SM is one of the least profitable oil-oriented E&Ps I follow.
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 the companies focused on various geographies.
CRZO and SM are Small-Caps while EPE, PVAC and SN are a Micro-Caps. CRZO, SM, EPE, PVAC and SN all closed on some combination of asset sales, asset purchases, new financings or security repurchases after December 31, 2017. The above tables reflect these transactions. SM's NPV of Net Operating Loss Carryforwards is material at $852 million.
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.
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 the companies focused on various geographies.
CRZO and SM trade at discounts in comparison to the E&Ps in other basins. EPE and SN trade roughly in line with other basins and PVAC trades at a bit of a premium to other basins.
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 the companies focused on 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.
PVAC emerged from bankruptcy in September 2016 with no debt. In additional PVAC made sizable acquisitions in 2017 Q3 and 2018 Q1. These facts are what contribute to PVAC's 127% production growth in 2018. EPE struggles from too much debt, thus restricting its ability to spend on capital expenditures and grow production. SN also has too much debt which weighs on production growth.
Chart 7 provides the levered and unlevered DCF analysis equity results.
EPE and SN are perfect examples of the impact of leverage in performing DCF analysis. Given EPE's and SN's high debt levels, the stock prices are expensive or fair, respectively, when valuing unlevered cash flows and subtracting net debt. But, if you assume they can roll their debt in perpetuity at current rates, then their equity prices are extremely under-valued when valuing levered cash flows. SM is one the most over-valued E&Ps I follow on a DCF basis. SM's heavy nat gas weighting results in SM having one of the lowest EBITDA per BOE levels of all the oil-weighted E&Ps I follow. Looking forward, while this weighting improves as more production comes from the Permian Basin, it's still not sufficient given only 8% of Eagle Ford production is oil. CRZO is a bit undervalued and PVAC is highly undervalued 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 companies focused on various geographies.
Net Debt is calculated as debt and preferred plus hedging liabilities less cash and hedging assets.
EPE has a weak balance sheet with very high debt levels. SN also has too much debt. CRZO's and SM's balance sheets are not as bad as SN's, but they too have too much debt. PVAC has a strong balance sheet.
The Eagle Ford shale group is living outside of cash flow, producing operating cash flow 16% below capital expenditures exclusive of the impact of hedging. The group is mixed, though. SN is forecast to produce operating cash flow 21% above capital expenditures. EPE is forecast to produce operating cash flow in line with capital expenditures. CRZO and PVAC are forecast to produce operating cash flow 13% and 7%, respectively, below capital expenditures. SM is forecast to produce operating cash flow 40% below capital expenditures. SM is funding this shortfall via proceed of $784 million from the sale of assets (transactions have closed or are scheduled to close in Q2 2018).
Overall, the Eagle Ford group is a mixed bag. CRZO, SM and EPE are materially exposed to geographies outside of the Eagle Ford (and in future reports SM will be moved to the Permian Basin-Midland Basin group and EPE to the Diversified Oil-Weighted group). D&C costs within the Eagle Ford are quite high for all the companies in this report. Profitability is strong for PVAC and CRZO since they are oil weighted, but profitability is quite weak for SM and SN given they are nat gas and NGL weighted. Other than EPE, all the companies have relatively small asset bases. And, while EPE has a larger asset base, the quality of the assets is quite low. PVAC has the best assets, the highest profitability and the lowest leverage of the group. CRZO has good assets and profitability also, although it still needs to work on its leverage. PVAC and CRZO are the two investable E&Ps of the group.
Disclosure: I am/we are long PVAC. 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.