E&P Investors: Time To Pore Over Annual Disclosures

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Includes: BNO, BOIL, DBO, DGAZ, DTO, DWT, GAZB, KOLD, OIL, OILD, OILK, OILU, OILX, OLEM, OLO, SCO, SZO, UCO, UGAZ, UNG, UNL, USAI, USL, USO, USOD, USOI, USOU, UWT, WTID, WTIU
by: Raw Energy
Summary

Annual disclosures of reserve information, production and financial results from 4Q '18 are pouring in for E&P companies.

Company guidance for capex, production, and other items is also coming in.

These disclosures and updated presentations will serve as the basis for company participation in 2019 E&P analyst and investor conferences beginning in late March.

This article prefaces what has been or will be disclosed conceptually, hopefully guiding readers toward things they can look for when analyzing their own investment opportunities.

Additional, more specific data on company disclosures will be provided once all such data has been released, captured, and summarized.

Every year when late February rolls around, I steel myself for the task I am about to undertake, which is to review public disclosures for E&P companies relating to their performance from the prior year. From year-end disclosures of reserves and production figures to guidance, from press releases on financial and operating results to 10-Ks, and from investor presentations to analyst conferences, I try to review it all for my own information, something I have done for more than 30 years. Oh crap, that just made me feel really old again!

Rather than take a bunch of naps to deal with what is a pretty tedious, many would say boring, endeavor, instead I stock up on Excedrin, No-Doz, antidepressants and assorted beverages—caffeinated for during the day and possibly alcoholic at night – being careful not to mix what should not be taken together (!). Then I just plow through it all until I am finished, which if I space out my workload to SEC filings and the like can take until mid-March, when NCAA basketball tournaments provide a needed distraction.

Source: en.oxforddictionaries.com

But I digress. The purpose of this article is to remind myself, and to point out to readers, things that I consider important to consider in building a fundamental case for any public E&P company. I started off with an overview, "Some Macro Trends to Watch For in 2019," to summarize certain thoughts I have about the E&P environment for 2019, and I would encourage all readers to read that article as a prelude to this one (if nothing else, it is free!).

As an introduction to this article, I should remind readers that this is something I prepare for my own information, but publish so that readers can consider any themes presented here in their own research and analysis, if they so wish. Your choice, and your decisions. To the extent that I rely on data, it is obtained from public sources that I attempt to verify, but all readers should conduct their own due diligence. I have bolded certain E&P industry terms in their first usage, terms that I think should be of particular interest. Finally, although I may refer to certain companies, I do not make specific stock recommendations and am not an investment advisor.

Reserves

There is a definite sequence to the publication of year-end disclosures. Reserve disclosures are often made first, after independent year-end engineering reports have been completed. Bigger companies (those with public market caps > $750 million) are required to file their 10-Ks by March 1, mid-sized companies by Mar. 18 and smaller companies by April 1. For this article, I will use Concho Energy’s 10-K and other public disclosures to show some things to look for in researching any company.

The easiest part, for me, is to actually find the reserve disclosure in the 10-K, because it is always near the end of the document. Personally, I think the reserve disclosures are often the most important disclosures a company makes, because not only do they show where the company has been, but they give an indication of how effective the company can be going forward; after all, E&P is an asset-based business, and proved reserves are what drive short term cash flows, earnings, capex availability and effectiveness, etc. I doubt that many readers take the time to go through 10-Ks, but for those who do, I suggest starting at the back and working forward.

Concho’s reserves are presented in the standard format required by the SEC, showing total proved reserves for the past 3 years, along with reasons for the changes during each year, presented as: (1) revisions to previous estimates; (2) extensions and discoveries; (3) purchases of reserves; (4) production and (5) sales of reserves. Although data for the last year is usually presented in a press release, I prefer to look at 3-year data to try to identify any trends and smooth out any anomalous results.

CXO Reserves

From Concho’s table, you can see that total reserves increased in 2018 from 840 mmboe to 1,187 mmboe (+41%). They produced 96 mmboe, or 11% of beginning total proved reserves (and 16% of proved developed reserves); that gives CXO a Reserve Life Index of 9X based on total proved reserves (or 6X PD reserves only). Back in 2016, CXO had a reserve life index of 10.5X on total proved reserves; I attribute the drop to having drilled more Permian horizontal wells, which have a higher-rate, higher-decline trajectory. During 2018, PUD reserves increased by 44%; increases in both proved developed and PUD reserves were in large part due to CXO’s merger with RSP Permian in an all-stock deal valued at $9.5 billion. Detailed descriptions of reserve changes are included in the text that follows the table.

Another disclosure of significance is the Standardized Measure, or SEC10, which again shows details for the prior 3 years. For the year, CXO’s SEC value increased from roughly $7.5 billion to $15.6 billion (+108%). Details regarding future cash inflows, production costs, development costs and income taxes are also shown, with all items held constant and prices calculated on the basis of the trailing 12-month average of NYMEX futures prices as of the first day of each month. In 2018, all companies start with oil prices of $65.56/bo and $3.11/mmbtu, each adjusted for transportation cost, quality differentials, etc.

The table that details changes in the Standardized Measure from year to year shows various categories of change, with predominant ones being changes due to production, prices, and extensions and discoveries, among other reasons. It is fairly stunning to see that, of the beginning value of $7.5 billion, almost $3.2 billion in net sales (revenues less operating expenses) was produced in 2018 (43%) … compared to something like 25% in 2016. Again, that illustrates the impact of the swift decline in horizontal drilling volumes, more than offset by a positive impact of increased pricing, purchases and extensions and discoveries (via capex) that allowed total value to increase.

With all this talk about development drilling, how did CXO invest its capex? There are 2 tables in the 10-K that illustrate that: one for Costs Incurred during the year, and one for aggregate Capitalized Costs that tie in to the company’s Properties, Plant and Equipment (“PP&E”) balance sheet item. CXO spent $4.1 billion to add 534 mmboe of reserves (for acquisitions and extensions), a Finding Cost of $7.68/boe, at least the way I would calculate it on an “all-in” basis. Some companies also disclose Drillbit Finding Costs based strictly on the results of exploration and development capital. The SEC value of those reserve additions turned out to be $4.6 billion, or 1.1X the capex investment. In the past 3 years, CXO added reserves at an all-in cost of $8.60/boe.

What good does all of this do, you may ask? Well, for one thing, knowing how efficiently a company invests its capital allows comparisons to be made, both on a year-to-year or company-to company basis. Also, knowing how much a company produced in prior years gives useful comparisons to how those volumes compare to what is projected in guidance for the current year. Further, knowing what a company’s past finding costs were allow a reader to estimate how much capital is required to simply replace reserves being produced in the current year, as well as how much prior capex would have needed to be to generate current year production (as opposed to reserves to be produced over many years). For example, we have already calculated that finding costs were $7.68/boe and replaced 253% of production (8,100 mmboe vs. 3,200 mmboe produced), so roughly 40% of CXO’s capex could be presumed to be, in effect, Maintenance Capex ($4 billion). However, if base production were scheduled to decline by 15% in the current year, and year-1 production were 25% of total production, then 4X that amount ($16 billion) might be necessary. Of course, the lower the reserve life, the lower the capex required as well, because year-1 production makes up a higher percentage.

Many other metrics incorporate these concepts as well, including Enterprise Value/boe (total proved or total proved developed), $/boe of flowing barrels, NPV/location, etc. None are determinative by themselves, but help get an understanding of what might be expected to occur in the future based on existing assets.

The chart below illustrates the compression that has occurred over the past four years in the average EV/BOE, broken down by market cap. As can be seen, it is the mid-cap and small-cap sectors that have suffered the most, going from premiums to large-cap valuations to discounts. While the cause of the contraction can certainly be debated, I think it is due to the market realizing that the price recovery has not been of as much help to the smaller companies as expected, as well as to previous over-estimated of the growth prospects of those companies. We will see if this trend continues in 2019.

E&P EV/BOE

Source: Enercom

What about Type Curves, depletion risk and EURs? Reserve estimates for every well are made and reviewed by the company’s independent engineers (in CXO’s case, by Cawley, Gillespie and Netherland, Sewell for different portions of CXO’s reserves), after having reviewed every comparable well they have in their database, including wells drilled by others, assuming comparable drilling and completion techniques according to current methods. If a company’s actual production begins to deviate from the established projection for a particular well, the projection is changed and shows up in the “revisions” section of the annual disclosure summaries. In CXO’s case, negative revisions of 74 mmboe were made (-9%). To date, as a general statement, production from new wells has exceeded the type curve in the most recent years.

However, that does not mean the trend will continue. Projecting windfalls or shortfalls at this point in newly-drilled wells’ life is likely premature at best. While recent media articles have mentioned negative “deviations” from type curves presented in investor presentations, those articles fall short upon further scrutiny. (1) One series of articles included only oil reserves, when natural gas and natural gas liquids comprised a significant part of EURs. (2) the articles assumed an artificial cutoff of 30 years, when properties may produce longer than that (or not), (3) the articles did not disclose or discuss their assumptions about the determination of economic limits employed, such as operating cost or pricing assumptions or terminal decline rates. Such data can more than make up for any “discrepancies” noted, and if nothing else, most of those conclusions will either be borne out or discredited at some point in the future, not now. Companies should continue to disclose how their actual results compare to projections in any event, and modify EURs as necessary.

Some people may see these kinds of data, and immediately claim they are somehow manipulated. Others may see initial decline curves that are "much steeper," or "bound to result in lower EURs over time," etc. What the data show are that decline curves are in fact steeper, but from higher initial rates, which translate into higher IRRs and return of capital within shorter periods. They also show continued out-performance, so far, of recent completions that are included in the data set. What they do not indicate is anything related to economics, so if the costs of achieving higher initial and intermediate term production levels still doesn't produce economic returns, the data can be correct but the results still sub-par overall.

This applies to PUD and all other locations as well. While there is (increasing?) data to suggest that original wells may outperform so-called “child” wells, readers should already be taking into account future risk in assessing reserves. In general, for valuation purposes, companies often assign PUD reserves a risk-weighting of 75-90%, probable a 25-50% risk-weighting and possible reserves a 10-25% risk-weighting, all based on geology and personal interpretations by the engineer(S) doing the evaluation.

Are we finished with reserves yet, you might ask? I suppose we could be, but there are still important points to make. The first is that obviously CXO acquired via merger RSP Permian, and in the tables the 308 mmboe under “purchases of minerals in place” has to be accounted for. Property acquisition costs of $4.1 billion show up in the costs incurred section, so we know that such costs were roughly $13/BOE (the rest of the acquisition would have been allocated to unproved acreage of $3.6 billion. From a valuation standpoint, however, a key factor is HOW the assets were acquired; in this case there were 51 mm shares of CXO issued (valued at $7.5 billion), plus debt of $1.8 billion and other items of $0.8 billion.

At year-end 2017, CXO’s proved reserves were 840 mmboe; with a share count of 149.3 mm, that equated to reserves/share of 5.63. At year-end 2018, CXO’s proved reserves were 1,187 mmboe; with a share count of 201.2 mm, that is a reserves/share figure of 5.90. So, despite reporting absolute reserve growth of +41%, reserve growth per share, something that should be on more importance to investors than absolute growth, was +5%.

We’re still not quite finished on reserve metrics though, because we haven’t factored in debt. At year-end 2017, long-term debt was $2.69 billion, and at year-end 2018 it was $4.19 billion. Enterprise Value is generally defined as the sum of debt plus the market cap of equity; based on CXO’s common stock price of $103, CXO’s EV was roughly $20.7 billion, or an EV/BOE of $17.44. Based on year-end 2017 debt levels, the 2018 stock price and 2017 reserves, CXO’s EV was $17.9 billion and EV/BOE was $21.91.

Because CXO’s EV/BOE declined by 20% from 2017 to 2018, does that mean it made a bad deal when it bought RSP Permian? Not necessarily, because CXO purchased quite a bit of undeveloped acreage from RSP as well, and it undoubtedly felt that RSP’s asset base had significant growth potential, with a lesser-developed base potentially more than CXO’s own assets. One other factor hints at the need for growth, the inclusion of a $2 billion “goodwill” item on CXO’s balance sheet in connection with RSP purchase. I usually refer to goodwill on an E&P company balance sheet as “deferred impairment,” because it reflects the amount by which the purchase price cannot be allocated to specific assets. Time will tell.

Production – Production is often reported in the release with reserve figures. CXO shows 96 mmboe in production for 2017 in its reserve table. Fortunately (!) that ties to what CXO also reported for its income statement purposes. For its guidance for 2019, CXO said it expected to generate production growth of 15% from fourth quarter 2018 to fourth quarter 2019. That is the comparison I prefer, compared to other companies that report year-over-year growth only, or growth based on the midpoint for the year. The latter two measures make growth appear stronger than it really is in companies that grew during 2018, while the q-o-q figures represent how the next year will compare to the most recent production volumes.

Of course, CXO doesn’t make it particularly easy to come up with specific numbers, which would also have been nice. The closest it comes is to say that 4Q production was 28 mmboe, so production for the 4Q ’19 should be 32 mmboe (roughly a 1.0 mmboe increase per quarter). That would give an annual total of 122 mmboe if spread out that way. To get an accurate comparison for 2018 would require an analyst to construct Pro Forma estimates based on the CXO/RSPP combo as if it had occurred at year-end 2017 … maybe later. Their guidance for 21-25% growth over 2018 is meaningless due to the RSP Permian deal, IMO.

Similarly, although not something that CXO has to deal with, are guidance for the current year that provides for growth “adjusted for sales” or some such nonsense. Companies are great at showing growth year to year that could just as easily be “adjusted for purchases” (i.e Pro Forma), but they love to talk about accretive deals and not dilutive deals, which is what sales usually are. Beware of these disclosures, at least those that don’t disclose the actual numbers as well.

Another point to make regards BOE; it is calculated on the basis of 6 mcf:1 bo even though the economic equivalent is more like 18:1 currently. Since natural gas has a lower valuation/BOE than does oil, it is something that has to be considered and kept track of. At year-end 2017 CXO’s oil/gas mix was 60% oil; at year-end 2018 it was 63%, slightly higher.

Pricing utilized in reserve disclosures is mandated by SEC rules, the 12-month average of the first day of the month prices on NYMEX for WTI and Henry Hub. Those are merely references prices, and reflect the price of the product at the delivery points (Cushing, OK and Henry Hub, LA, respectively). Each company will start with the same numbers but end up with different wellhead prices, based on location, quality, grade, etc. Those adjustments are usually fixed, as opposed to regional price differentials that may vary from period to period. CXO guides toward a ($2.00) – ($2.50) deduct, excluding differentials, for oil and 80-100% realizations for natural gas relative to Henry Hub.

Capital expenditures (CAPEX) - CXO did not directly disclose total capex for 2018 in its press release, although the tables and the 10-K show $10.4 billion. Many companies include only exploration and development costs in capex because they are recurring, where acquisitions are not. On that basis, CXO had $2.6 billion in capex in 2018. In its formal guidance for 2019, CXO set a capex budget of $2.8 -$3.0 billion, an increase from 2018 but a decrease of 17% from prior guidance.

What I will be looking for when analyzing company presentations and conference calls are comments addressing process improvements like reduction in drilling time, specifics about completion techniques regarding the # of fracs, interval between fracs, proppant loads, as well as any general comments about technological improvements in pad drilling or otherwise. While often the focus of capex is on the simple numbers, I also will be interested to see disclosures on costs/lineal foot and estimates of how much of the drilling time has been spent “in zone”, which geosteering has improved dramatically in recent years.

Operating expenses – When companies are actively drilling, LOE/BOE should be going down simply because the volume growth exceeds the cost growth in the early years. Such reductions may not last if or when production declines or plateaus. CXO is guiding toward $6.00 - $6.50/BOE for 2019, including base operating expenses plus workovers.

Midstream expenses are not treated consistently by companies. CXO guides towards $0.85 - $0.95/BOE for Gathering, Processing and Transportation (“GPT”) costs, and includes them in a separate line item on its income statement. When companies disclose their total costs, many companies exclude GPT costs even though they are an ongoing expense that can be significant. By itself, that is not necessarily an issue, but when companies exclude the costs and also do not note GPT as a deduction from revenue, they are easy to miss and make companies look more efficient than they truly are. Total GPT liabilities often appear as contingent liabilities in notes to the balance sheet, since the commitments, particularly for natural gas, may have specified volumes associated with them that cannot be undone. I usually combine LOE + GPT as closer to true operating expenses.

Water hauling costs are becoming more of an issue, particularly in the Permian. I look for disclosures regarding both costs and about water handling arrangements, especially since some companies have begun to outsource their water handling arrangements, where in prior periods they may not have.

General and Administrative Expenses (“G&A”) - In some respects, I have given up placing too much importance on G&A, because it is so tough to compare between companies. If you take a look at my article on G&A, you will see that G&A costs can end up in any one of up to 9 (?) different places, from the income statement to the capex/investment statement of cash flows. G&A/BOE is also highly influenced by the level of BOE being produced, rather than any sort of meaningful reference figure.

One thing I do track, though, is how much of the G&A reported in the income statement gets backed out as “non-cash” (i.e. stock) in the cash flow statements. CXO is guiding to $2.20 - $2.40/BOE of cash-based expense and $0.70 - $0.90 of non-cash stock-based compensation (i.e. roughly 25% of total compensation). Non-cash compensation is usually contingent on several factors, so may never be issued at all.

GAAP Projections- Even after all of the assumptions that have come out of the 10-K and guidance for 2019, supplemented by company presentations, readers are unlikely to come away with a firm handle on what GAAP net income will be. That is somewhat intentional, because even though companies will disclose DD&A is, there is still no net number to point to, because companies do not guide for expected prices.

Whatever net income ends up being flows into balance sheet shareholders’ equity. While many readers are used to hearing how losses, impairments and other items are “non-cash,” in truth they are not, just that they are not cash in the period under consideration. Eventually everything flows through the balance sheet into retained earnings, so one quick check on a company’s overall profitability level is to see what their retained earnings level is. After an impairment, future earnings should replenish the retained earnings account if the impairment is “temporary,” but impairments of producing assets have long since been made permanent because of depletion and/or property sales.

Debt – Like all companies, CXO includes a schedule of its debt maturities as notes to its balance sheet. At year-end 2018, none of its $4.2 billion in long-term debt, excluding bank debt that is typically rolled forward, has a maturity before 2025, a nice bit of runway for them in which to conduct their operations.

Those same notes have terms and other descriptions for the debt instruments. The credit facility is for $2.0 billion, of which $1.8 billion is unused, effectively liquidity for the company to employ however it sees fit, assuming it maintains the existing borrowing base. Certainly no borrowing base, credit or liquidity issues for CXO for the foreseeable future.

Equity- GAAP equity is a pretty free-flowing concept because it is not comparable from company to company. Companies that follow full cost accounting have likely taken impairments post-2014 that reduced equity, making many of their GAAP metrics better-looking than their successful efforts counterparts, who have taken lesser impairments, if any. Full cost companies have also not been able to write their assets up (if they still exist) if they have assets that were written down when oil was $42, so they have a double-whammy negative GAAP effect at this point. Conversely, if many of the successful efforts companies had to take full cost impairments, their equity would be severely if not totally depleted. No wonder they like successful efforts!

All of this translates into lower DD&A charges for full cost companies, which should make their net income look better than successful efforts companies, almost twice as good from my initial reviews. While many readers might say that “it’s only accounting,” I find that to be categorically untrue. Besides the fact that banks, creditors, investment bankers and M&A personnel do not use GAAP concepts like net income, I continue to see numerous media and analyst reports (some charging thousands of $$!) that do not account for the differences properly, in ways that impact valuation. If nothing else, any computer program that is designed to look only at GAAP concepts (because they are easy to find) will be picking up numbers that are just plain misleading, if not completely wrong, for valuation purposes.

EBITDA has become one of my pet peeves as a metric that is often misused. Many people use EBITDA as a substitute for cash, and it most definitely is not. In fact, for some of the reasons noted above as well as one other, it can be way off. That other reason is debt, which EBITDA does not account for (as in interest payments that are cash outlays). EV/EBITDA ratios, for example, will very often lead readers to companies with high debt (and high interest payments). Two companies, one with high debt and one with no debt, can come out looking equivalent using EV/EBITDA, and debt levels can kill in E&P. Many of the metrics in use in E&P were developed by investment banks seeking candidates for M&A or leveraged buyouts, where a new capital structure could be put in place. For investors in public companies, however, buying into existing debt levels and interest payments is part of the fundamental picture. The more appropriate measure is Debt-Adjusted Cash Flow or DACF, which is equal to Adjusted EBITDA (adjusted for non-recurring and non-cash items) less interest expense. That calculation is what separates out indebted vs. low debt or debt-free companies.

Another metric used less frequently is Debt-Adjusted Equity, in which all debt is assumed to be converted into equity at the current stock market price, thus taking leverage out of the picture. Many investors would probably throw up when they saw the results, particularly in what they see as a “low-priced” stock environment. The existence of Debt Swaps at certain prices may give an indication of how management views both its debt and its equity.

Free Cash Flow (“FCF”) has probably become my favorite pet peeve in recent years because of its misuse in interpretation. By definition, and in simple terms, positive FCF exists where cash flow coming in exceeds capex going out; negative FCF is the opposite.

Somewhere along the line, people started equating FCF with financial health. Because it has no bearing on debt, equity or any other measure other than cash in/cash out, that has the potential to penalize healthy companies that are growing and reward companies who are failing. FCF is either a conscious decision about a certain capex level by management or something enforced against management to keep them in line from a credit standpoint.

One key toward assessing the effectiveness of FCF is to also look at production growth and compare earnings or cash flow growth to that. Spending more to grow less is a “bad” FCF result, while spending to grow substantially more is not necessarily bad. Whatever FCF is, though, should really take into account debt outstanding in some fashion, because that “free” cash flow is really not free if it must be kept to show that companies can repay their outstanding debt if necessary.

FCF is often “mistiming,” as well, in that it compares current period cash flows to current period capex … which is often more likely to produce production and cash flow in future periods, especially if capex is “back-end loaded” during the year. Many investors evidently fail to see the distinction, or else just don’t care. They are focused strictly on whether a company is FCF positive or negative. [This obviously presents an opportunity for investors who look past that single number].

Overall environment – Beyond these specifics that apply to every company, there are also comments to watch for generally, that discuss market trends, such as:

Capital markets - I should just skip over this one right now, because the capital markets are essentially dead for new issuances of debt or equity. The year 2018 was the worst year for issuances since 2010, evidently, and nothing being discussed now shows that changing anytime soon. Still, it is a sign to watch that a turn in the market might be at hand.

What I will include, however, is a chart that shows recent breakeven estimates for 50 different acreage positions and the respective companies that own them.

Rystad 50 top acreages While these estimates may well be accurate based on wellhead returns only, the next chart shows how tremendous wellhead returns can translate into much smaller corporate-level returns ... and even that chart does not show the impact of debt. These illustrate to a large extent why the capital markets have developed a real cautionary view of E&P, because the wellhead figures that managements love to cite are not translating into the profits that the market expects, even if the market is being harsh on what is realistic to expect given the still-recent price crash. Sorry, Antero, but the market clearly does not view your corporate level returns as compelling, even though you have attempted to show the bridge between half-cycle and full-cycle returns; kudos for that.

Antero returns

M&A – Likewise. M&A was really beginning to pick up in the late 3Q, but the $Q and the 1Q so far have cut that off at the knees for now. Consolidation still seems to be necessary, especially in the Permian, but prices have to be stable and managements have to be convinced that the timing is right for deals to get done. The deals being closed now were all negotiated when prices were higher.

Bankruptcies – Oil prices declining from $75 to the mid- $50 range is much more of a hit to financial health of E&P companies than most people realize. Actual filings in 2018 were down, but the total $ amount was up. Companies that filed in 2018 and that are still financially distressed will be more impacted by long-term debt that was issued years ago and is now coming due, vs. the companies who had heavy bank debt and were forced to file quickly when borrowing bases were cut.

Sentiment- Sentiment is hard to assess, other than to watch prices and volume for signs of accumulation. It doesn’t appear that sentiment could get any worse than it is now, but there are so many uncertainties (as I addressed in my article,….) that it will just take constant vigilance to see the best entries.

“Activists” - There have been several accounts of investors who are seeking to influence management in some way, from detailing how capex should be spent, to setting capex to generate FCF, to recommending “shareholder-friendly” initiatives like stock buybacks and dividends, to company sales/mergers, etc. To be honest, I view most of these as being the product of misapplication of many of the ideas in this article.

Desired valuations from these investors often fall much higher than what existing fundamentals would achieve, and may be largely based on the market from several years ago, when valuations were often “crazy.” Citing multiples of book value ( a non-no as shown here) or EBITDA or reserves that are 2014-type numbers may sound good, but any buyers will be living in the present. Some recent attempts to sell entire companies have failed (Sandridge, QEP Bakken, Gastar, Sabalo, etc.) and other attempts have been withdrawn.

In my opinion, buybacks and dividend increases are misguided as well. Investors appear to be of the mind that the sector has recovered from the price crashes and has money to burn, when that is not the case. In fact, I think that some of the negative FCF signs you see are from companies who know that they still have not achieved escape velocity from their debt issues, and are trying to increase production in the hopes that higher prices will help elevate their finances.

In some ways, this strategy mirrors the failed upstream MLP strategy, where cash was returned to holders that should have been retained to provide for debt repayment. This, despite the fact that if you actually read MLP documents you will see that there is no term such as “Distributable Cash Flow,” something the MLP managements dreamed up as if to say, “We’re not going to consider that we will ever have to pay back debt.” That fiasco is nearly behind us, but that is effectively what activists are seeking. The more accurate term is Available Cash Flow or ACF, which is cash flow that is available after considering all needs of the company, including debt repayment.

With buybacks, I do not understand how paying money to buy back the shares of selling shareholders, to the detriment of existing shareholders who must take on a bigger share of debt, etc., helps. Studies have shown buybacks to be relatively ineffective in changing prices, and the E&P buybacks announced so far that have activity have purchased stock at prices well above their current levels. Companies who end up in bankruptcy usually have tried to buy back their stock or debt thinking it was undervalued, only to discover that is not the case. Sure, there are exceptions for the majors and larger independents whose balance sheets can support buybacks, dividends, capex, etc., but the list is currently beyond those companies. In fact, I expect some companies to face more distress as a consequence of these “shareholder-friendly” initiatives during 2019 and beyond, subject of course to a dramatic improvement in prices.

Technical environment - Maybe the best question to consider after you have read this is “Do I really care about the fundamentals anyway, or am I just as likely to be investing based on the technicals alone … or someone’s buy recommendation?” I like to develop my own understanding of each company’s position and strategy, but I also rely on my assessment of the technical environment to decide if or when to buy or sell. I abandoned buy and hold investing long ago after one of the previous E&P crashes, and my focus now is on trying to watch for swings in sentiment as buy points, with well-defined entry points, size of position, maximum loss, etc. We’ll see how effective that is in 2019, but in 2018 it meant that most of my activity was in the 1H, and I was largely in cash during the 2H. Of course, I missed lots of great short opportunities that way, but I am not usually very keen on shorts.

Conclusion

Annual disclosures by E&P companies offer a once-yearly look into recent results as well as guidance for the upcoming year. Reading through press releases, 10-Ks, company presentations, etc., while fairly boring at times, can also be very informative, especially over time when disclosures and activities can be compared to prior periods. While it may be unreasonable to expect that readers would review many of the E&P companies in the sector, developing techniques that will allow readers to review selected companies is still a useful exercise, in my opinion. Hopefully this article’s contents help identify some things to look for, but of course any ideas or methods that work for individual readers are fine as well.

Final question: In 2019, will the market see the glass above as half-empty or half-full?

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. 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.