Imagine you have just left on a vacation after a tough stretch, and you have washed your car, loaded it up for a nice trip and turned on some music. As you leave the city and clear a congested stretch of highway, the road ahead looks clear as far as you can see. You're drifting toward the middle of the road for safety, and all of a sudden you hear "thud," "thud thud." You stop the car, get out to see what happened, and then you see it ...
Yep. From out of nowhere, somehow a skunk appeared just as you were passing by, and you hit it head-on. Then, as you're wondering what to do about the roadkill, it hits you ... no, not an idea, but the smell. That really stinks!
That's pretty much the feeling that E&P companies and their investors have had after such a difficult year. Just when it looked like things were improving, the E&P market just stunk up the place ... badly! If you've ever hit or had "an experience" with a skunk, you know it is not easy to eliminate the stench, and it takes time. We'll see how the sector recovers, but as much as investors want to get back in their proverbial car immediately and just drive on as if nothing happened, the impact of 2018 may well linger on, just as the smell of a skunk does.
As I explained in my most recent article, E&P Bottom of the Barrel Club Q4 Review: You Picked A Fine Time To Beat Me, Lucille,’ because of the recent drastic changes in both oil and natural gas pricing since 3Q results and guidance were issued, I will focus this article more on activities and specific actions of consequence rather than financial results. With updated reserves, CAPEX, production and other financial info due beginning any day now, it will be much better to wait for 2019 projections, even though those projections usually come without specific revisions to oil and gas pricing.
I would still encourage readers of this article to read that article as well, because many of the points there might be applicable to companies covered in this article, even though they might not have the prominence or importance they do to companies in the previous article. The BOTB Club consists of companies that I considered the most likely restructuring candidates back in late 2015, while the MOTR Club companies covered in this article include companies that are neither distressed nor considered the top of their class by the market, at least as I see things. The MOTR Club is of a more recent vintage, as my initial articles in Oct. 2018, for “Non-Permian” and “Permian” attest. Both sets of companies are combined into one Club for this article.
The usual caveats apply to this article. I have obtained the info from public sources and checked them for reliability, but errors may still exist. No specific companies are recommended by me, and readers are cautioned to do their own research and analysis before making their own investment decision. Protecting capital, setting entry and exit points and allocating both investment $ and % of portfolio size are advised based on each reader's individual style.
Like the BOTB Club, the MOTR Club companies’ stock performance numbers are bathed in red. No companies have a positive return since the cycle high back in June, 2014, which is not unexpected given the fall in oil prices from over $100 to $50 today. Only one company, WPX Energy (WPX) has a positive return since Dec., 2015, which is near the cycle low (so far), despite an almost 80% increase in the price of oil since then. Since the end of 2016, only Matador Resources (MTDR) and Ring Energy (REI) have positive returns, and from that point forward the time periods shown all reflect ZERO companies with positive performance. Of course, within those time periods, even long traders might have found positive pockets of time when profits could have been realized, but long-term buy and hold investors are largely underwater from dates specified.
In the table above, I have also included performance of the group of companies I call the 'Tier One Producers' or 'TOP' Club for comparison. A full spreadsheet was contained in the most recent BOTB Club article for 70+ companies.
Borrowing Base Changes
For those who read the BOTB Club article, the changes below are notable, because they show how banks react to financially-worthy credits, extending maturities and increasing borrowing bases. Of note also, although not addressed here, such companies typically keep these balances available so that they have liquidity to pursue opportunities as they arise. Many have $0 bank debt outstanding.
Alta Mesa (AMR) increased its borrowing base from $350 million to $375 million.
Carrizo Oil & Gas' (CRZO) borrowing base was increased from $1.0 billion to $1.3 billion, with an elected base of $1.1 billion.
Centennial Resource Development (CDEV) increased its borrowing base from $800 million to $1 billion.
Jagged Peak Energy’s (JAG) borrowing base was increased from $825 million to $900 million.
Magnolia Oil & Gas’ (MGY) initial borrowing base was set at $550 million.
Oasis Petroleum (OAS) extended its bank maturity to five years from the closing date, with a springing maturity 90 days prior to the maturity of the existing 2022 and 2023 Senior Notes.
Rosehill Resources’ (ROSE) borrowing base increased from $150 million to $210 million.
SM Energy’s (SM) borrowing base increased from $1.5 billion, with a $1 billion elected amount. The maturity date was also extended.
SRC Energy’s (SRCI) borrowing base increased from $550 million to $650 million.
WildHorse Resource Development (WRD) saw its borrowing base increased from $1.05 billion to $1.3 billion.
WPX Energy’s (WPX) borrowing base increased from $1.8 billion to $2.0 billion, with elected commitments of $1.5 billion.
Carrizo Oil & Gas redeemed $130 million in notes due 2020 @ 100%.
Matador Resources issued $1.05 billion in 5.875% Senior Notes due 2026.
SM Energy (SM) redeemed $334.6 million of its 6.5% Senior Notes due 2021 @ 102.17.
SM Energy subsequently issued $500 million of its 6.625% Senior Notes due 2027 to fund the redemption above as well as $85 million of its 6.125% Senior Notes due 2022 and its 6.5% Senior Notes due 2023.
Southwestern Energy (SWN) completed a cash tender @ 100% for $787 million in notes due 2020 and 2022, with proceeds payable from the company’s Fayetteville sale (see below)
Callon issued 22 mm shares @ $11.82 for $260 mm in gross proceeds, earmarked to pay for a portion of the company’s Cimarex purchase.
Carrizo issued 9.5 mm shares @ $23.00 for $218.5 million, to be used to fund in part its purchase from Devon Energy (DVN).
Matador issued 7 mm shares @ $32.72 for $229 million, with proceeds earmarked for general corporate purposes.
Rosehill Resources (ROSE) issued 6.15 mm Class A shares @ $6.10 for $37.5 million in proceeds.
Alta Mesa announced a $50-million repurchase program, and announced that as of Nov. 13, they had repurchased 3.1 mm Class A shares at an average price of $4.76/share.
Encana (NYSE:ECA) announced a $1.25 billion repurchase program.
Extraction Oil & Gas (XOG) announced a $100-million repurchase program in Nov.
Laredo Petroleum (LPI) announced a $200-million stock repurchase program.
Callon acquired oil and natural gas assets in the southern Delaware Basin from Cimarex Energy Co. for total cash consideration of approximately $538.6 million. Production from the properties was estimated at 6,831 boe/d, of which 73% is oil, and is mostly from the Bone Spring formation. The undeveloped acreage includes 18,925 net Wolfcamp acres of which 11,500 net acres have rights to the base of the Wolfcamp. The purchase added 28,657 net surface acres to Callon’s Spur operating area in the Delaware basin, more than 90% held by production. The acreage contains an estimated delineated base inventory of 212 net identified horizontal drilling locations targeting the Third Bone Spring, Wolfcamp A and Wolfcamp B zones, with 86% to be operated by Callon. Over 60% of the inventory is comprised of well locations with laterals of 7,500 ft or more.
Carrizo acquired Delaware Basin properties from Devon Energy (DVN) for $215 million. The properties consisted of 9,600 net acres in Reeves and Ward County that directly offset existing Carrizo operations, with wells producing 2,500 boepd (60% oil) and 100 net Wolfcamp locations based on 7,000-foot laterals.
Encana sold its San Juan Basin assets for $480 million to DRJ Energy, a portfolio company backed by PE firms Trilantic Capital Management LP, Waveland Energy Partners and Global Energy Capital. The properties included approximately 182,000 net acres. With average production of approximately 5,400 barrels of oil equivalent per day including 3,900 barrels per day of liquids. At $35,000 per flowing boe, estimates implied an undeveloped value of roughly $1,600 per acre.
Matador purchased 8,400 gross (8,400 net) acres for approximately $387 million, or a weighted average cost of approximately $46,000 per net acre, in Lea and Eddy Counties, New Mexico. Notably, in describing the methodology used to evaluate the acreage, Matador CEO Joe Foran noted, “rock quality, the number of potential commercial zones, potential additional reserves bookings, the added value from the lower 1/8th royalty interest, available midstream opportunities and the tract’s strategic fit within our existing portfolio of properties.” i.e. nothing about a specific $/acre figure or a reference to other deals.
Oasis sold additional interests in certain midstream assets to Oasis Midstream Partners (NYSE:OMP) for $250 million, or roughly 6.75X estimated 2019 EBITDA.
Parsley Energy (PE) sold approximately 11,850 net acres in central Reagan County, southern Upton County, and northern Howard County for combined proceeds of approximately $170 million. Production on the divested and net traded assets was approximately 1,200 net boe per day during 3Q18.
QEP Resources (QEP) sold assets in the Haynesville/Cotton Valley area (LA) for $735 million to Aethon III, a portfolio company backed by the Ontario Teachers’ Pension Plan and Redbird Capital Partners. The assets cover about 49,700 net acres, including 137 gross operated producing wells. Production during the third quarter averaged about 49,500 barrels of oil equivalent per day of production, 100% of which was dry gas. QEP also owned and operated midstream infrastructure on a majority of its Haynesville assets.
QEP also sold natural gas and oil producing properties, undeveloped acreage and related assets located in the Uinta Basin to Middle Fork Energy Partners, LLC, a portfolio company backed by PE firm Quantum Energy, for $155 million. The properties included an estimated 605 Bcfe of proved reserves as of December 31, 2017, and net production in the first quarter of 2018 was 54 mmcfed, of which approximately 23% was liquids.
QEP has also agreed to sell its Williston Basin assets to Vantage Energy Acquisition Corp. (VEAC), a blank check company formed by PE firm Natural Gas Partners, for $1.725 billion in cash and stock. The acquired assets consist of more than 100,000 net acres in the core of the Bakken and are currently producing at the rate of 46,000 barrels of oil equivalent per day.
Range Resources (RRC) sold a 1% overriding royalty interest (proportionately reduced) in Washington County, PA acreage for $300 million to an undisclosed buyer. Cash flow associated with the overriding royalty is expected to be approximately $25 million in 2019. Range’s properties from which the overriding royalty is carved out encompass approximately 300,000 net surface acres that produced 1.7 bcfe net per day in the second quarter of 2018. The overriding royalty applies to existing and future Marcellus, Utica and Upper Devonian development on the subject leases, while excluding shallower and deeper formations.
Ring Energy (REI) acquired assets in its Central Basin Platform core area from Carlyle Group (CG), a PE firm for 2,623,948 shares of common stock of the company valued at $5.80 per share. The acquisition will add 5,313 net acres and 55 new gross horizontal drilling locations.
Southwestern Energy (SWN) sold natural gas properties and affiliated midstream business in the Fayetteville Shale in Arkansas for $1.865 billion to Flywheel Energy, a recently formed E&P company backed by Kayne Anderson. The assets include 716 mmcf/d of net production from 4,033 producing wells across over 900,000 net acres and an integrated midstream gathering system with over 2,000 miles of gathering pipelines and more than 50 compressor stations.
Whiting Petroleum (WLL) completed a $130-million acquisition of Williston basin properties. The properties, contiguous with the East Missouri Breaks and Hidden Bench areas, encompass 54,833 net acres and have current production of 1,290 boe/d and estimated proved reserves of 26 million boe. The seller was rumored to be Oasis Petroleum (OAS), which signed two separate purchase and sale agreements to sell an estimated 4,400 boe/d of net production and 65,000 net acres of noncore assets in the Williston basin for $283 million.
WildHorse closed two separate definitive purchase and sale agreements to acquire a combined 20,305 net acres in the Eagle Ford, Austin Chalk, and other intervals with approximately 39 Boe/d of net production across Burleson, Brazos, Lee, and Washington Counties, TX. In addition, WRD has also leased 10,700 net acres in the Eagle Ford and Austin Chalk year to date, net of lease expirations. After giving effect to the leasing activities and the two acquisitions discussed above, WRD has acquired approximately 31,005 net acres in 2018 for approximately $43.0 million.
Newfield Exploration (NFX) has agreed to merge with Encana in a transaction valued at $7.7 billion, including the assumption of $2.2 billion of debt. Under the terms of the merger agreement, Newfield shareholders will receive 2.6719 Encana common shares for each share of Newfield common stock, which at today’s closing price of $6.62 for ECA, would value the equity component of the deal at $3.6 billion, or almost $2 billion less than on the date of the announcement. Upon completion of the transaction, Encana shareholders will own approximately 63.5 percent of the combined company and Newfield shareholders will own approximately 36.5 percent. This transaction includes approximately 360,000 net acres in the core of the STACK/SCOOP area in the Anadarko Basin. This oil-weighted, stacked-pay asset contains multiple commercial and prospective zones which Encana believes are perfectly suited to its proven cube development model. This asset contains over 6,000 gross risked well locations and about 3 billion BOE of net unrisked resource. Further details can be found at the links for the [Merger Presentation] and the [S-4 Proxy/Prospectus]. The special meeting is set for Feb. 12.
WildHorse Resource Development and Chesapeake Energy (CHK) agreed to merge in a transaction originally valued at $3.98 billion, including the assumption of $900 million in WRD debt. The offer allows WildHorse shareholders to elect to receive either 5.989 shares of Chesapeake common stock or a combination of 5.336 shares of Chesapeake common stock and $3 in cash. Assuming that shareholders elect the latter option due its cash component, total consideration based on Chesapeake’s closing price, the total transaction value would be closer to $3.0 billion, roughly $1 billion less than at the announcement date. WildHorse shareholders would end up owning 45% of Chesapeake. WildHorse is an EagleFord E&P company backed by PE firms Natural Gas Partners, KKR and Carlyle, all of whom have agreed to vote for the transaction. Its assets consist of approximately 400,000 net acres, of which 86% are undeveloped, and producing oil wells. More details can be found at the links for the Merger Presentation and the S-4 Proxy/Prospectus. The special meeting is set for Jan. 31.
Earthstone Energy (ESTE), a closely-held company controlled by PE firm EnCap, had agreed to merge with Sabalo Oil & Gas, another EnCap portfolio company, for $950 million in cash and stock. Due to the rapid decline in oil prices, the transaction was terminated in 4Q.
Things to Watch In Early 2019
Some of the following discussion points below may sound at first like the points included in my BOTB Club article, but I have updated and expanded on many of the points. If the article follows history, there will be many new readers who do not choose to read the prior article because it didn’t directly apply to the stocks they own, but I hope that even those who did read the prior article find something new here. Many of these trends impact all E&P companies, which makes it difficult not to repeat some things when you are reviewing such a large number of companies in multiple articles.
SEC10 Reserves: Independent reserve estimates of volumes and SEC valuation are normally released in January. As a reminder, SEC guidelines mandate the use of prices for oil and gas that are the average 12-month trailing prices on the first day of each month. Because the last month in the year is December, December 1 prices will be in effect for all companies (as adjusted for location and other differentials).
Prices for oil are already set at $65.66 and prices for natural gas at $3.10, which means that 2018 reserve valuations will be higher than they would be at current prices. They will also likely be measurably higher than the 2017 SEC valuations.
One interesting exercise will be to compare the $/boe of reserves for each company in 2018 to the $/boe figure calculated at $51.34 and $2.98, respectively, the SEC price for 2017 calculations. That would give a pretty reasonable comparative estimate of the reserve value of a company within that price range (i.e., $50-65). At this point, having SEC prices ranging from almost $100 oil in recent years to $40 and several interim points as well gives a reasonably reliable way of assessing current reserves at various price levels, something I will likely tackle in a future article.
PV10: In this context, PV10 means the use of strip pricing to calculate reserve valuations. In recent years, when the PV10 was higher than the SEC10 valuation, companies have been quick to point out and reference the higher figures. This year that dynamic is reversed; strip pricing for oil for 48 months is $55 per barrel and natural gas is at $2.65 per mmbtu for the same period.
Companies have been quick to point out that strip pricing decks are most often used by their banks in determining their borrowing base. Of course, what they do NOT say is that strip pricing decks only create the starting point for the banks’ analysis. Including G&A and other items to establish a cash flow projection, that value shrinks to something more like 75-80% of PV10, and the advance rate against proved reserves is typically no more than 60-65% of NAV so calculated. The net result is something that many managements don’t like to acknowledge, which is that at both SEC and PV10 pricing in this environment, future net cash flows are unlikely to have the capability of paying off debt in their current structure; price or reserve increases are necessary to get adequate values for that.
Guidance: Some companies have already issued 2019 guidance; most will have to do revisions at current prices. In addition to CAPEX budgets, a primary focus for the investment community has been Free Cash Flow, or Operating Cash Flow less CAPEX. FCF, by itself, is not a symbol of financial health, nor is it a measure of anything more than sources and uses of cash flow. All a company has to do to create FCF is lower its CAPEX to less than its OCF, something it can do with the stroke of a pen. Of course, the impact of reducing CAPEX will impact production levels, and without price increases that means a company is depleting its assets over time, liquidating if you will.
Companies with negative FCF have been penalized severely, even when that result was an expected part of their strategy in the short term. Despite reduced CAPEX, I expect production levels to increase on the order of 5-10% overall, although many of the early announcements from companies are projecting production growth of 20% or so despite reduced CAPEX.
My theory remains that investors think they want FCF, until they see the results of reduced cash flow. If companies were penalized for generating negative FCF, just wait until they reduce their guidance for reserve and production growth, net income and cash flow. Many investors will simply sell and move on to companies that they feel offer better growth prospects. Debt becomes that much more of an issue in many cases as well, because part of the impact of today’s CAPEX is intended to recreate equity lost in the 2014-2018 time frame. Impairments may have been taken for accounting purposes, but unfortunately impairments do not reduce actual debt outstanding; new activities must offset the asset value reduction caused by lower prices and cash flow in recent years.
Hedges: I expect to see huge changes in the value of derivatives announced prior to formal earnings. Where companies may have had accumulated losses on their derivatives in 3Q '18 (and in many cases, large non-cash losses in their income statements), at year-end much of that will be reversed … and then some. While these figures do not impact cash flows, they will present some interesting challenges for analysts to track. After all, swaps, puts, calls, collars, 3-way collars, etc. all have very different treatments by their structure, as well as by the price points put in place by companies as they largely try to hedge their next 12-24 months for cash flow stability purposes.
Differentials: The situation in the Permian Basin with respect to transportation bottlenecks has not improved much. Limitations on what can be transported have caused Midland to Cushing (NYMEX) WTI differentials to expand to double-digits during parts of the 4Q, and quotes are currently (-$6.00) or so, declining back to near parity by the end of 2019. Natural gas prices, which reached as low as $0 in certain spot sale areas, are quoted at (-$1.60) through June, declining to -$0.70-$0.80 thereafter. With Henry Hub (NYMEX) prices of $2.90 for June and $3.00 at year-end 2019, that means that Permian natural gas prices may be in the range of $1.30 into June and slightly over $2 into year-end, at which time additional pipelines will be operational. In the 4Q '18, differentials in the Bakken Trend "blew out" to as much as $20 due to similar transportation constraints, so management discussion is important there as well.
Debt/Covenants: As I have mentioned previously, despite all the talk about financial covenants like debt/EBITDA, etc., the most important factor and control the banks have is in setting the discretionary borrowing base. Companies that relied heavily on bank debt because interest costs were cheaper than non-bank debt have been paying for that decision when borrowing bases are re-evaluated, with the next redetermination scheduled for April. Also, the creeping maturities of long-term debt issues to within the period of the bank facility requires some evaluation by banks of the security of their own position.
Frankly, members of the MOTR Club have done an admirable job in restructuring the debt side of their balance sheets, as shown by the number of debt tenders or redemptions, as well as equity issuances and increased borrowing bases. Most members do not utilize much of their borrowing base, choosing to leave it as intended as a short-term issuance to bridge the gap until long-term debt and/or equity can be issued. Several companies have retired debt with approaching maturities in the 2020-2022 range, substituting instead longer-dated debt to 2025 and beyond.
Another point that is obvious in examining the MOTR Club disclosures is that they are trying to minimize the lack of available capital in the market by rationalizing their asset base. When a company cannot raise new capital, the best thing it can do (actually one of the things it should do as a matter of course) is sell “non-core” assets to reinvest in their top focus areas. Non-core assets might be those that make up the bottom 10%+ of its asset base, or enough in proceeds to plug a hole in development funding, etc. I always look at CAPEX as being net of asset sales, because that is the net effect they have on income and cash flow.
Locations: Operationally, companies will routinely disclose rig counts and completion data; in most cases, the data disclosed is not particularly informative to retail investors. What is also important, though, is any discussion about spacing of locations, density, etc.; when terms like "interference" or "parent-child reductions" are discussed, these can be critical to assessing the number of "real" locations, rather than the theoretical maximum number that is often thrown out.
While it is not often disclosed, the total number of lateral feet drilled is often more instructive than rig counts. A “rig” counts as such whether it is drilling 5,000-foot or 10,000-foot laterals, and the trend in recent years has been to drill longer laterals if at all possible. Also, the NPV of a 5,000-foot lateral “location” may differ greatly from that of a 10,000-foot lateral. Costs per lateral foot is another potentially useful disclosure of cost efficiency.
It may seem odd, but reducing the number of locations may not have much of an impact on a company’s NPV if the company has several years of inventory left. By shifting capital to remaining locations and maintaining a relatively constant level of activity, the future cash flows may be less affected during the time period when the influence on NPV is greatest. With shale plays, that is in the first 2 years; by the time one takes into account the possible impact of less cash flow 10 years out, NPVs are largely set. At 10 years, the factor for NPV using a WACC of 15% is 25%, meaning that $100 10 years out contributes $25 to NPV. At 20 years it is $6, and at 30 years $1.50.
The greatest impact of the above is that the ability to grow or replace reserves on an overall basis from a particular project area is diminished. Over time, reserve replacement would have to be increasingly inorganic (or not from within existing assets) rather than organic. Given the lack of barriers to entry in establishing new project areas, that is not the end of the world for any company, but new project areas would have to be found and/or purchased to provide for growth beyond those time frames.
Accounting: Full Cost (“FC”) companies and Successful Efforts (“SE”) companies have different methods for calculating impairments, as I have noted numerous times. Prior impairments can distort DD&A comparisons as a result, along with every other metric tied to book value (i.e., net income, shareholders’ equity, etc.). SE companies tend to carry higher Property Plant and Equipment (“PP&E”) balances than FC companies, and many would have virtually no equity if done on a FC basis; alternatively, to compare a FC company on a SE basis would require a reader to add back prior impairments in some manner.
From an income statement standpoint, because FC companies have taken prior impairments, their DD&A rate should be lower, perhaps far lower, than a SE company; hence, their net income should be higher, and by this point should generate positive net income since impairments were taken with oil at $43 or so. While a common complaint from many readers is that FC companies are never allowed to “write up” their property values, the reality is that after an impairment is taken, future net income should increase shareholders’ equity over time to offset the negative impairment. If a FC company did not generate net income in 2018, that is a definite yellow flag. Of course, analysts routinely ignore PP&E balances in calculating values anyway; they use current reserves and valuation estimates in place of PP&E, adjusting shareholders’ equity with the difference.
M&A outlook: The disclosures above, both for property level and corporate deals, indicates a good deal of activity in 2018. Some of the corporate deals are on hold at the SEC for now, but I assume they will be completed. I am not so sure about 2019 activity, because 6-12 months or relative price stability is often required before two parties can come to a common understanding on terms. Just when things started to heat up, prices crashed, and there will undoubtedly be some investors who are upset with managements’ timing on recent deals. Time will tell.
Private Equity: PE firms are still having a major impact on deal flow, both from the buy and the sell side, as evidenced by the discussions above. Some PE firms have funds for which they need to develop exit strategies (usually over a 5-7-year life), while other funds represent new money investments as other institutions seek to take advantage of what they hope to see as competitive returns. With the decline in the public debt and equity markets, they have increasingly resorted to transactions where at least part of the consideration they receive is in the form of stock.
Many companies have significant holdings by PE or other large holders. At one time, that would have been considered a positive, in that it indicated support for that company. However, the downside of significant ownership positions is that once the firm decides to exit, if they enter the market to sell there is often not enough buying support to prevent a nasty decline. Recent examples come to mind of two companies in which Warburg Pincus funds own shares, Antero Resources (AR) and Laredo Petroleum (LPI). In the process of liquidating a prior fund, Warburg sold shares in block trades initially, which were then picked up on by other funds liquidating as well, causing (at least in part) major stock price declines in those companies. WildHorse Resources recently allowed Natural Gas Partners to distribute WRD shares to its fund investors to increase liquidity; it is not clear what impact that had on its market prior to the Chesapeake merger. There are now many other PE firms with sizable positions in E&P, so the caution is to watch their Schedule 13 or other Form filings for changes in ownership frequently.
The Majors: (1) Exxon Mobil (XOM) buys the Bass Family Trust Permian assets for $6.6 billion; (2) [[BP]] acquires [[BHP]]’s US onshore assets, including Permian acreage, for $10.5 billion, and establishes BPX Energy; (3) Shell (NYSE:RDS.A) (NYSE:RDS.B) is rumored to be engaged in talks with Endeavor Energy to purchase it for $8 billion; (4) Chevron sets its 2019 CAPEX budget for the Permian and other shale plays at $5.2 billion… etc. As a Chevron spokesperson said, “Our investments are anchored in high-return, short-cycle projects, with more than two-thirds of spend projected to realize cash flow within two years.”
If you are planning to invest in an independent E&P company, why watch what the majors are doing? In short, because they're back! Actually, they never really left, but the impact of their recent moves and what it means for the industry over the next several years or decades may be profound, especially in the Permian Basin. You see, back in the 1980s and 1990s, many of the majors decided to de-emphasize the U.S. due to their perception that international exploration presented them with the best opportunity to achieve the scale needed for them to grow. They need to invest huge sums on development drilling both to justify their deals and to grow production, and their projects are less dependent on what the price of oil is on any given day. Besides, they often own refineries, pipeline systems and chemical operations where they may make money even when oil prices are low. Their CAPEX plans may well dwarf those of the independents ... combined, and their presence is one reason why oil production may grow faster than many expect going forward ... or not.
Longevity: Many readers see why other companies will fail, but neglect to consider that the companies they have invested in may as well. Thinking that banks and other creditors will step in to provide what would be considered "equity" is a non-starter, and failure is an option even for MOTR companies.
By fail, I do not necessarily mean go bankrupt, but rather have to undergo an out-of-court restructuring of some sort, or maybe sell out in M&A activity. Many of the companies trading today were recent formations, in this case meaning recent since the mid-2000's, when the "drunken sailor" mentality took hold in both debt and equity markets, and anyone who could spell "oil" or "gas" could raise money. To illustrate how few companies are long-term survivors, check the list below to see how many companies from 25 years ago you recognize. The 1998-1999 and 2008-2009 price collapses took care of many of them...
Machines and Algorithms: I read a lot of comments bemoaning selling pressure when stocks are declining, but far less concern about purchasing pressure (imagine that!). With automated trading and sophisticated algorithms in place for 70-80% of all trades, by some estimates, my advice to investors is to accept that this is the case (and that "shorts" are no more likely to move pricing on the downside than "pumpers" are to move to the upside). I fall back on my own trading/investing strategy to minimize disruption, including treating preservation of capital as my #1 objective. If a stock moves against me beyond a pre-determined % or $ amount, I do not hesitate to sell even stocks I like, because it means that my entry point was not optimal (I am also not afraid to re-enter stocks I have sold). Based on learning valuable lessons from past market downdrafts, I keep losses to a minimum (usually) and let winners run, always with stops that will not let me or the market turn a good trade into a bad investment. FOMO often reigns in investors' minds, but E&P stocks are very volatile, so "missing out" is sometimes a good thing. Of course, everyone has their own philosophy; that is mine (and there is nothing at all wrong with using ETFs like XOP instead of individual stocks if that suits your style better).
I would have much preferred to see the MOTR Club get off to a good start, but that was not meant to be. It is heartening, though, to see the level and type of activity illustrated above that companies are taking to prepare them for an even longer "lower-for-longer" period. Those who haven't, like many in the BOTB Club, may continue to flounder absent significant price increases, while many of the MOTR Club companies may be there to pick up the pieces or get swallowed up by bigger fish a la the '98-'99 and '08-'09. Ten years appears to be an ongoing cyclical move, hopefully a trough; 2019 is shaping up to be volatile despite an early bounce from a massive decline in 2018. It is going to take a lot of tomato juice to eliminate the stench of that dead skunk year.
Disclosure: I am/we are long AMR ESTE. 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.