Oh, my gourd! In October, the E&P sector’s carriage turned into a pumpkin, leaving investors exclaiming “Good grief!” Trying to mask the increasingly scary gloom that is driving them batty and seeing monsters at every turn, investors now begin to focus on …. Halloween? No, earnings season, of course! Will investors boo earnings, find delightful treats or merely wade through a bunch of hocus pocus to try to find meaningful information? If only I hadn’t broken my crystal ball. But enough Halloween gallows humor...
...or maybe not.
While a few companies have already reported, the E&P 3Q earnings season kicks off in earnest on Halloween, Oct. 31. The purpose of this article is to provide a generic preview of things to look for in upcoming reports, accompanied by specific release dates and data of importance to investors. Although it may prove to be too daunting and time-consuming to read through my recent articles for various E&P sector groups, the links below and the notes I included there for each company provide access to what companies disclosed in 2Q, which can serve as a guide for comparison to what companies disclose in 3Q reports.
Oil prices- A full discussion of the oil price environment is the stuff books and most media reports are made of. While the macro environment is certainly important, it remains largely unaddressed in E&P reports. Instead, what investors should be focusing on are things like differentials and capacities.
NYMEX oil prices, the ones quoted in the media, are financial futures that are usually settled with cash, and have no absolute correlation to wellhead prices, which are key to producers. Wellhead prices are determined primarily by quality of the oil and by location. Differentials based on quality rarely change if a company operates in a particular area, while transportation constraints may the differentials from one region to another, in some cases significantly.
Permian (Midland and Delaware) Basin producers will need to address both volume constraints and pricing impact in the 3Q and looking ahead to 2019. Posted prices in the Permian are often up to $5 less than NYMEX prices, but because of takeaway constraints, an additional discount of $10+ may have been taken to get their oil to markets in 3Q, particularly if a company did not/does not have firm transportation agreements in place. These constraints are expected to be resolved sometime in 2019 as new pipelines come into service, but it will be important to get each company’s specific positioning and viewpoint towards where their local prices are headed and what impact that will have on cash flow, earnings, etc.
Natural gas prices- In some respects, management discussions regarding natural gas pricing may mirror those for oil prices. Differentials in the Marcellus/Utica have been negative for several years now, but in recent months new pipelines have relieved capacity constraints and allowed companies to receive higher prices for their local production. While low storage levels might impact winter pricing if it is frigid, reserves in the ground, DUCs and future CAPEX plans are likely to resolve the situation, but management perspectives will be interesting to hear.
Northeast natural gas prices are not the only story, however. Perhaps even a bigger issue will be takeaways from the Permian of associated gas, which has made up a bigger portion of production growth in recent months/years than even the Northeast. While Northeast prices may have risen as takeaway increased, Permian natural gas prices remain at a significant discount … and end up displacing volumes from other parts of the country. My understanding is that Waha natural gas prices were $1 less than their Henry Hub/NYMEX counterparts in 3Q.
What the US may have going forward is a massive bottleneck in the Midwest of Marcellus/Utica volumes heading west, Rockies volume heading east and Canadian volumes heading south. More than the Midwest itself can consume, that may well pressure Henry Hub prices when the Permian volumes, which are almost un-responsive to price, are considered. In the meantime, natural gas prices on NYMEX for Jan. ’19 are up only slightly year-over-year.
Derivatives- Derivatives are among of the most misunderstood concepts in E&P, and management does little to help investors understand how they affect their financial results. There are many different kinds of financial derivatives (and hedges, which are technically different), but the most common are (1) swaps, or commitments to sell a certain volume of production for a certain period of time at a fixed price; (2) puts, which allow the company to sell specified volumes at or below the strike price, (3) calls, which allow the company to sell specified volumes above a certain price; and (4) so-called “costless collars”, which typically combine the purchase of a put with the sale of a call, costless because at the time they are entered into the cost of the put and the proceeds from the sale of the call offset each other, resulting in no net cash outlay.
The problem with derivative disclosures is that they often indicate that a company is hedged without indicating HOW the company is hedged and AT WHICH PRICES the hedge is effective. An easy example is Company A, who says their volumes are “100% hedged” for the next quarter. Upon further examination, it appears that A has purchased puts on 100% of its projected production at a price that is less than the current price. So, for example, if the puts offer protection to A below $50 and the current price is $70, A still bears the risk of price declines from $70 to $50 despite being 100% “hedged.”
Company B is also “100% hedged” via the sale of calls at $70. It is entitled to the net proceeds > $70 but remains at risk for all prices below $70, adjusted for the proceeds from the sale of the calls.
Company C is “100% hedged” via a swap at $60. This may be what most people think of when they think of being fully hedged, as in insulated against both price increases and decreases. As prices increase above $60, their net realized price stays at $60.
Company D is “100% hedged” via a costless collar that involved the purchase of a put at $40 and the sale of a call at $60, roughly equidistant from the $50 price at the time the collar was put on. A price decline below $40 will entitle D to reimbursement of the difference between the put price and the actual price, bringing its net realized price to $40. Likewise, a price increase above $60 will require D to give back the difference in price above $60, resulting in a net realized price of $60. At any price in between $40 to $60 D remains at risk, despite being “100% hedged.”
When managements say what % of production is hedged, it is therefore very important to know HOW the hedging was accomplished, as well as WHAT PRICE RANGES ARE PROTECTED. Simply knowing a % hedged is not enough. I have even seen major advisory firms publish misleading charts of company hedging activities that imply protections that are simply not there, if that is what investors are hoping to glean from such disclosures.
Margins- I could walk through what managements are likely to disclose with respect to LOE and each item of expense, but frankly if a company is drilling new wells, such items should go down on a $/BOE basis, because “flush” production generates incremental net cash flow. A corresponding increase in margins should be expected, particularly if CAPEX is being financed by debt, which only is burdened by ("low") interest rates for income statement purposes. You will likely never see management disclose what comparable numbers would look like in the future with no future drilling, as the lack of new drilling would simply reverse that result. It is awfully hard to gauge what is a true operational improvement vs. just a lower $/BOE result based on higher revenues. Another thing you will likely never see is any discussion of how much cash flow should be retained to satisfy the needs of creditors.
Net margins, and recycle ratio (i.e. how much cash per $ of CAPEX is returned via cash flow) are the two primary tools for gauging effectiveness of current period activity. Comparing quarterly changes is often the best that investors can expect or hope for, and often it is only after research and analysis that those figures become visible.
Wells drilled- Frankly, most of the operational discussion is directed more at analysts and engineers rather than investors. The number of wells drilled and the initial results of those wells enable analysts to project future financial results and compare actual production vs. projections. Unfortunately, there is little follow-up on wells drilled quarter to quarter, except as may be disclosed in type curves.
The development of type curves is very important for companies and their engineers to determine reserve estimates. “Beating the type curve”, which is a phrase readers may hear or see in almost every management report, is certainly better than its opposite, but constant monitoring is needed to see whether early results translate into better overall results over a longer period of time. Type curves based on outdated well results are much less comparable than newer wells from a sufficient number of new wells to be statistically relevant.
Completion techniques are very important but often difficult to compare. Companies will describe “Version 1” or “Gen 3.14” techniques, but unless you are an engineer these may be foreign terms. What is important is to know whether and why companies change their techniques, and a general explanation of the differences (i.e. more/less proppant and fluids, wider/tighter spacing, etc.). One recent change that is expanding in usage is the move to develop local sources of sand for use in fracing.
Other operational efficiencies, such as the time required to drill and/or complete wells, are important to note, but will also already be reflected in a company’s drilling plans, CAPEX, operating costs, etc. One important, recent improvement I have seen noted is the increased use of 3D seismic and geosteering techniques in drilling. To be honest, I would have thought that companies would have already had access to up-to-date seismic, and taking time to do the technical analysis and planning with geosteering might have improved prior results well before now if companies had not been rushing to drill.
Development- A major shift in development plans by E&P companies may have gone unnoticed, and that is the shift from drilling to hold acreage to drilling to develop a specific area. In the early days of an emerging play, companies focus on drilling on as many prospective leases as possible to hold acreage, which gives them time to assess results even if there is a continuous drilling clause in the lease. In most areas, that phase initial phase is now complete.
Now, especially in areas like the Permian, but elsewhere as well, investors should expect to hear more about terms like “co-development,” “cube drilling,” “production corridors” and the like. These terms indicate the intent of the driller to stay in one location, which requires fewer rigs, to drill more wells and in some cases enough wells to fully develop a particular property or set of properties, rather than bounce around from property to property. Other companies may reference moving to a “manufacturing or “factory” mode that emphasizes repetitive, repeatable processes and results.
A potentially major risk for all new shale plays is the risk of “premature” depletion, which can occur because of offset well interference in the spacing pattern, inefficient frac or completion techniques or simply reservoir performance. Companies often emphasize new techniques and the improvement that results from those, but the time period may not be long enough to observe how decline rates/depletion beyond an initial flush production period will impact results.
These “parent/child” discussions may occur in any play, whether it be the Permian, the EagleFord, the STACK/SCOOP, the Bakken, etc. There is some preliminary evidence that production declines in certain areas are not levelling off the way they were originally projected, so companies are going to need to be prepared to address those issues or analysts will (or should).
The term “locations” is one of the more misused and/or misunderstood terms in E&P. It is often simply a land-based, mathematical calculation that takes the number of acres and divides by a spacing estimate provided by management, sometimes independent of geology and often-times subject to great subjective differences company to company (with no standardized definition).
So, for example, a 640-acre section and an assumption of 80-acre spacing yields 8 locations. Extrapolating that over 64,000 acres leads to a disclosure of 800 locations. If subsequent drilling (i.e. the parent/child issue above) determines that 160 acre spacing is better, the company now has 50% fewer locations. A risk analysis by any competent company management will take into account geologic risk, pricing risk, cost of capital, scheduling issues, etc., in considering valuation, and conditional probability outcomes would typically warrant further risked assessment by potential purchasers. If the outcome of a small number of wells can affect a multitude of subsequent wells, companies should be proceeding with care rather than simply assuming a statistical approach to decision-making.
Knowing the number of locations are also not particularly useful without knowing the length of laterals assumed. Some “locations” may be based on 5,000’ laterals while others have projected 15,000’ laterals. Reserves, production and/or CAPEX per lateral foot may be much more informative than simply a location count. Lateral length should also be considered when reviewing rig counts, because drilling 15,000’ laterals takes fewer rigs than shorter lengths; maybe Baker Hughes should revise their rig count figures to calculate figures per lateral foot.
From a land perspective, you may hear two different terms: “bolt-on acquisitions,” which are lease purchases that are in close proximity to existing acreage, and “acreage trades,” where a company trades acreage it owns in one area for another company’s acreage in another area. Both types of deals are designed to add future reserves/locations, but the bolt-on acquisitions give more bang for the buck than trades, which often merely shift reserves from one well to another.
Financial strength- Investors may well find that every company in the E&P business is in “strong financial strength” according to management. Low leverage, adequate liquidity, Free Cash Flows (cash flow – CAPEX), etc. are the typical buzzwords management likes to focus on, and right now investors are mesmerized by FCF and very negative towards companies who cannot generate same … even though it is not an indicator of financial health.
I have purposely left off projections of IRR from the earlier discussions. Managements are still likely to include only half-cycle returns in their calculations of drilling results, and those exclude lease acquisition costs, facilities costs, G&A, etc. A recent example I saw for Cimarex showed an 80% IRR at the well level translated down to a 40% full cycle return, and considering G&A of 25% of cash flow and interest would get them …something even less. I see returns projected for half-cycle costs of less than 40-50% and I move right on, because those will not generate any real long-term value to a company. NPVs are a better measure, but few disclose them in any meaningful way.
Investors are not likely to hear much about financial measures that companies would prefer not to disclose. Obviously, corporate level IRRs above is one such measure. Another measure is “maintenance CAPEX,’ or the amount required to maintain production at a constant level. FCF is meaningless for that purpose, since it only measures the level of CAPEX and not the level of any production change. Outspending cash flow to produce significant production growth may be perfectly acceptable (to me, anyway), while a lack of production growth in the same scenario is a big red flag. An apples to apples comparison would take what CAPEX would maintain production for all companies.
Companies are very fond of stressing growth, either from year-to-year or quarter-to-quarter. There is nothing inherently wrong with that, except that context is important. Investors should not care about absolute growth, but growth per share is critical. Production disclosures are often the primary culprit in such disclosures; what good is 10% growth if the number of shares outstanding increases by 20%?
EBITDA is another favorite disclosure, and another unsatisfactory measure as it is often used. EBITDA is largely a measure invented by investment bankers for investment bankers looking to value companies as LBO or takeover prospects, but its use has expanded to mean all sorts of things. One thing it does NOT mean is cash flow, and cash flow is more important to investors investing in an ongoing business. By excluding interest expense from its calculation, EBITDA can easily lead investors strictly to the most leveraged companies; for example, when Enterprise Value is used, as in EV/EBITDA calculations.
A more appropriate usage, in my opinion, is “Debt-Adjusted Cash Flow,” which in its simplest form would be Adjusted EBITDA (i.e. EBITDA excluding adjusted for non-cash and non-recurring items) minus interest. Adjusted EBITDA figures are now almost universally included in press releases, and excluding interest (which is shown as an addition to net income for Adjusted EBITDA calculations) gets as close as possible to a valid comparative figure.
Net income illustrates an interesting disclosure for companies. For companies that use Successful Efforts accounting, their prior lack of impairments means that higher DD&A rates should translate into lower earnings than would otherwise be the case, and investors are clamoring for more earnings without realizing what goes into them. Earnings for SE companies won’t’ show what I would consider major improvement until they have added enough lower cost reserves to replace the higher cost reserves they are depleting.
Full Cost companies, on the other hand, should be generating significant earnings at this point, primarily because they have taken such large impairments, for the most part. Ceiling test impairments a couple of years ago should have lowered DD&A rates to correspond roughly to $40 oil, so if FC companies are not generating income then something is wrong. Any statistical analysis that compares the two types of companies as if they are the same is badly flawed, in my opinion, and the accounting method should be one of the first things investors look at in analyzing a company and its balance sheet (which impacts net income and book values as well as any result utilizing same in the calculation … something that computer algorithms apparently do not understand).
Reserve Valuation- Investors are not likely to see or hear much about reserves and valuation measures in the press releases and conference calls that accompany earnings. However, since companies often update their presentations at the same time, that kind of information, updated for current prices, can often be found there.
Traditionally, constant price (i.e. current prices held constant) PV10 values have represented a good approximation of reserve values. When prices are moving around, such prices sometimes offer a better view than SEC prices, which use 12 month trailing average prices, held constant and discounted at 10%; at 12/31/2017, those prices would have approximated $51 for oil, for example.
What managements have taken to disclosing in recent years is something they refer to as PV10, based on futures strip prices. Why? That one is easy to answer; because it has produced a higher number than an SEC or constant price PV10 would have. Those disclosures may be about to change, in my opinion. Why? Again, an easy answer; because with price backwardation and current prices that are beginning to approach their 12-month trailing average, the strip price may actually produce a lower number.
The problem I have with both numbers are that they are merely metrics, sometimes helpful in determining NAV or liquidation values, but less so when assessing financial health of a company, and particularly when legacy debt is involved. If you look carefully at strip PV10 figures, and at escalated PV10 numbers if those are supplied, you will realize that G&A and other items are not included. In a continuing business, these costs are not optional, so the “real value” of the reserves to the corporation must be further discounted by such items; if G&A and other items are 25% of net cash property cash flows, then PV10 figures must be discounted by 25% … with that figure representing what is available to retire debt and fund CAPEX. Such comparative figures remain depressing even at recent prices, although few companies are at risk of default yet. Debt maturities in 2020-2022 may present a difficult challenge for several companies, as the risk parameters for debt incurred in 2014 with prices at $100 oil are far different than they are for new issuances today.
The Table that follows shows information regarding upcoming earnings release dates, accounting methods and various 2Q financial results or metrics. Taken in conjunction with the recent articles detailing 2Q disclosures, they may offer some help in assessing 3Q performance, and the links to company presentations presented in those articles will offer the opportunity to compare before and after changes that might be made with those upcoming results.
The previous articles can be viewed at the links below:
By my count, that is 76 companies for which readers can find data, my notes and company presentations. Obviously, trying to repeat those articles would make this more like a book than an article.
I have highlighted “top 10” and “bottom 10” performers in green and red in the Table below. As a reminder, the Table is best viewed by right-clicking on it, then clicking on “Open image in new tab” and viewing it there. I have not tried to do my checking of these numbers since the upcoming releases will present new ones; these were taken from a third-party website while the figures contained in my previous articles were obtained by me directly from public filings. For screening purposes, such overview numbers can be useful in any event.
As I said earlier, this article is intended as a preview of upcoming earnings results, an overview of the sector rather than an individual preview of each company (although by reading my prior articles and company presentations much company information is available). Some “themes” to watch for, though, might include:
Tax loss sale candidates- Oct. 31 marks the end of many funds’ tax years, so they often sell their losers in Oct. to offset gains they have elsewhere in their portfolio. Although this can offer a good trade opportunity for companies whose prices begin to rebound after selling abates, care must be exercised because calendar year taxpayers may also look to sell between now and year-end for similar reasons. The biggest YTD stock price declines are highlighted in red in the Table.
Colorado producers- A ballot initiative in Colorado to essentially end all drilling in the state will be voted on November 6, with recent polls indicating it has 52% support. Companies like High Point Resources (HPR), SRC Energy (SRCI), Bonanza Creek (BCEI), Extraction (XOG), PDC Energy (PDCE), Noble Energy (NBL) and Anadarko (APC) are the largest producers in the DJ Basin, and their stock prices have been hit hard since Aug. 1, when the fact that the initiative would be on the ballot was announced. These companies will likely be impacted substantially in one direction or another based on that vote.
Obviously, though, those companies could continue to produce from existing wells and drill new wells with existing permits in Colorado, then re-invest elsewhere. The latter 3 companies have less undeveloped acreage at risk, but the valuation discounts of the first 4 companies might also move to extremes. Another, less discussed ballot initiative, if passed would allow claims to be filed against the State as a result of any “taking,” so companies might still be able to recover damages if both measures pass. Of course, even any initiative passed must be put into law and kept on the books by the state legislature, not by this vote. It will be an interesting situation to watch.
Natural gas producers- A contrarian play, potentially, would be to watch natural gas producers at least for a winter trade, which would be largely dependent on frigid weather amid a low storage environment. If such a play developed, companies like Antero (AR), Cabot (COG), Eclipse (ECR), Equitable (EQT) (until their E&P operation spinoff is completed), and Southwestern Energy (SWN) are likely beneficiaries.
Permian producers- My Middle of the Road- Permian Edition group contains companies that are more likely sale candidates in the market due to their (lower) size, but those companies are also the most likely to be sold or merged at some point as well.
"Out-spenders"- Companies who have CAPEX > Cash flow may also be emerging companies who must spend more to grow production in their early years and may, in fact, have cash and/or liquidity to see them through without resorting to issuance of long term debt. These companies have been a target of focused selling, which may be misplaced as far as long term results are concerned. Included in this group from the table are relatively new companies like Alta Mesa (AMR), Centennial (CDEV), Extraction (XOG), Jagged Peak (JAG) and WildHorse (WRD).
"BOB" and "WOW"- These two watchlists might be what you might consider the 'Best Of the Best" and/or "Worst Of the Worst" companies after hearing what they have to say and observing the market reaction to that. Some investors like to buy the best companies after a selloff, in hopes of a bounce, while others may either short the companies that they view as the worst, or perhaps buy them after a capitulation. My 'Tier One Producer Club' companies were one attempt to identify companies that the markets often think of as the best, while the 'Bottom of the Barrel Club' were companies on the opposite end of the spectrum back in late 2015 when the club was created. Readers can create their own watchlists on SA to follow any group of companies they wish to follow.
Whether it is Halloween or not, I avoid falling knives, so this is not a call to immediately invest in these companies, but rather to have lists ready to go if/when prices have bottomed out (or capitulated) and are beginning to move upwards on good volume.
One last Halloween observation: the original ‘Halloween’ movie came out 40 years ago. In 1978, oil prices were $14/bbl, which translates into an inflation-adjusted price of $52.50; a recent price of $66 shows that oil prices have beaten inflation since that time (obviously with much volatility), and it represents a 4% annual rate of return over that period.
This article is essentially a continuation of the articles I have written recently that provided information about companies’ 2Q results from public filings such as press releases, conference calls, 10-Qs and investor presentations. Hopefully this provides some basis for further research and analysis on the part of readers, and hopefully it also allows readers to analyze upcoming earnings releases with a better understanding of companies that may be of interest.
If nothing else, construct a checklist of the items noted, or your own, to create a “buzzword bingo” card … and see which companies provide the most useful and comprehensive information!
Disclosure: I am/we are long AMR GSTPA.
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.