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Oil and natural gas (NG) have been in the headlines continually since Russia invaded Ukraine six months ago but much of the virtual ink has been contradictory, with some experts predicting $200 oil and others calling for a crash to $50 or less. I wrote an article in April in which I provided my projections for WTI crude pricing for this year ($100 Oil Is Here To Stay – ‘Drill, Baby, Drill’) and made recommendations regarding 5 oil-and-gas-related equities. If you are really interested in the topic and have some time on your hands, you may want to read my previous article because I discussed there many topics which still apply and which I will not repeat here..
Five months have passed since I wrote that article, and I thought I would revisit my predictions and extend them into 2023, as well as comment on two of the equities I recommended in my previous article (I am only discussing two equities in this article because the last article took me nearly 50 hrs to prepare and I simply do not have the time to do THAT again!).
How Did I Do On My WTI Price Projections?
To condense 5,000 words of crude-oil-pricing discussion from my previous article into a single paragraph here, I posited previously that oil was likely to stay in triple digits in 2022, unless we encountered a recession and/or Iranian barrels were likely to come back on the market, in which case I thought WTI might go into the $80’s (look in the section of my previous article entitled “Counterarguments to the Foregoing Thesis”). It turns out I was pretty much on target. After my article came out, WTI did basically remain in triple digits for the following two months, until June when the recession drumbeat became a roar and WTI dropped into the $90’s, a number that recently dropped into the $80’s as it became more likely that a deal would be done with Iran.
My Predictions For WTI In 2022 and 2023
Although I think the analysis of where WTI is likely to trade is important to making money in the energy space, I realize this is a long article, so if time is short, you can skip the WTI price analysis and jump to the discussion of Energy Transfer and TETRA Technologies below. On the other hand, if you want to understand the nuts-and-bolts, let’s dive in.
The key conclusion in my previous article was “that crude oil prices will stay higher for longer than perhaps many people expect.” To give you the punchline at the beginning of this article, my opinion continues to be pretty much the same, with a few caveats and wrinkles.
To be more specific, I think we have triple-digit oil prices coming back to us in the next 12 months (since I bought my crystal ball at the dollar store, I rarely make predictions more than 8-12 months out), although a serious recession/bear market (i.e., if the S & P drops another 15-25%, as Jeremy Grantham and others believe) may drop WTI back to the $70’s.
I realize that in making the above prediction, I am going contrary to the forward curve which shows $80’s prices in 2023, and I am going contrary to projections of many E & P’s (exploration and production companies-the companies that produce crude), who are often using $65 to $70 WTI as a basis for their EBITDA/FCF projections.
Let me provide the reasons why I believe the forward curve is wrong and why I believe we have more $90’s and $100’s in our future than $60’s and $70’s (unless the S & P resumes its downdraft).
1. Even Though Many E & P’s Quote Their “Breakeven” Prices To Be in the $30’s, That Is NOT Correct.
Traditionally-and even today-the concept of “breakeven” price has only taken direct production costs into account, and under this rubric, yes, many companies can tout “breakeven” numbers in the $30’s per barrel.
But that rubric no longer exists in today’s world.
Let’s take a company that is producing 1000 bpd in 2022, and has a traditionally-calculated breakeven price of $30/barrel. If the company did nothing but produce those barrels, natural production decline in its unconventional wells might result in 2023 production dropping to 700 bpd, and even less in subsequent years. Therefore, just to maintain production, the company has to drill a well or two every year. Although well drilling and fracking have traditionally been thought of as “capex” and therefore not included in breakeven costs, I think today every E & P either implicitly or explicitly includes in their “conceptual breakeven” costs the capex needed to at least maintain production (and maybe even the capex costs to increase production a few percent a year).
But that’s not all that most E & P’s are now including in their “conceptual breakeven” costs. If the company has more debt than management thinks it should, then debt reduction costs will also be included in “breakeven” costs. Furthermore, some sort of “capital return to shareholders” (in addition to debt paydown, which is a return of capital to shareholders, whether they recognize it or not) must now also now be covered by the company’s revenues. Finally, it could be argued that the costs of obtaining new acreage to replace already-drilled acreage should also be included in the broader breakeven cost discussed above. And once all of the above have been covered by revenues, having some real free cash flow (i.e., cash left over after all of the above have been paid out of revenues) is the new financial target for most E & P’s.
To put it a different way, in the old days, companies would borrow money to drill wells, thinking of it as “capex,” rather than what it actually was, which was the cost of simply maintaining production. Not very many E & P’s think that way anymore.
Why is that relevant to the discussion about crude pricing? Because the above updated rubric for determining the real breakeven point means that unlike before, excess production will not occur at $60 or $70 oil-a number that some years ago would have incentivized lots of debt for lots of extra drilling and capex. Indeed, the opposite is likely to occur-i.e., if WTI hits the $80’s (as it did a couple of weeks ago), companies may stop deploying rigs or even pull rigs, lowering production (as natural decline takes over) and leading to a different, higher floor ($80’s) than what was considered adequate just a few years ago ($60’s). In essence, rolling all of the above costs into a more realistic “unified cost of production” forces the breakeven point far higher than before, and precludes excess production that would lower WTI to the $60’s or $70’s (barring a resumption of the bear market).
In late July-early August, we had a bit of a test of this theory. During that time frame, WTI dropped from upper $90’s to mid-$80’s, and I told a friend of mine at that time (about a month ago) that I would not be surprised if rig counts stopped increasing or even went negative. (rig counts had been climbing steadily throughout 2022, so I was predicting a change in that trend) As it turns out, rig counts went negative the following three weeks and just went up by 3 rigs this past week-meaning that rig counts basically remained unchanged for the whole month of August. Obviously, this is hardly a scientific test and a month does not prove a point, but it certainly supports the foregoing argument.
2. Russia’s Attack On Ukraine Will Revamp Oil and Gas Flows Around the Globe and Keep Oil and Gas Prices Higher for Longer
I borrowed the above subtitle verbatim from my previous article because what I said five months ago still applies-and maybe even applies with greater force. Whereas some geopolitical experts believed early on that the war would be over in a matter of weeks, I believed otherwise, and unfortunately, I continue to believe otherwise. I explained the reasons why in my previous article and won’t repeat them in full here, but I will quote the following paragraphs from my previous article:
I don’t see the above circumstances reversing over the next year. In fact, even if the war is resolved soon–which does not seem likely–I doubt that Russia’s isolation (discussed above) will change anytime soon. I do not see the West’s “self-sanctions” ending in 2022 (nor probably in 2023) and I certainly do not see Shell, Halliburton, Schlumberger and the rest of them rushing back to Russia anytime soon.
In fact, I think the world’s disgust with Putin may actually INCREASE once the missiles stop flying and the war crime investigations begin and more atrocities are revealed.
But even if I am wrong about everything I have said above, there is one more reason that convinces me that global oil prices (i.e., Brent and Arabian light and related crudes) are likely to remain in triple digits this year, and that reason is a sea change in European attitudes toward continuing to depend on Russian hydrocarbons.
Although Europe has not sanctioned its current purchase of Russian hydrocarbons (NOTE ADDED IN CURRENT ARTICLE: Europe has agreed to sanction Russian oil effective 12/5/22. Although this sanction will have its holes, it certainly will lower the amount of Russian oil that hits the market-although “by how much?” is an open question), there is no question that Europe has finally recognized the self-inflicted vulnerability it has created in terms of its critical dependence on Russian hydrocarbons. The Europeans banned fracking, shut down hydrocarbon production in Europe, shuttered nuclear power plants and sourced huge amounts of their hydrocarbons from Russia. This might have been forgivable if Putin’s Ukraine attack had been a surprise, but after his forays into Chechnya, Georgia and Crimea (the latter just 8 years ago)-not to mention his repeated statements that all of Ukraine (not just Crimea) belonged to Russia, his support of the separatists in eastern Ukraine, and his repeated use of Russia’s hydrocarbon production to blackmail Europe, it is hard to argue that Putin’s attack on Ukraine was a surprise.
Be that as it may, Europe now recognizes that relying on Russia for over one-third of its hydrocarbon needs (a percentage that is almost 50% in Germany) is unwise policy, and therefore, there is little doubt that Europe is going to wean itself off Russian hydrocarbons over the next 2-3 years.
The 180-million-barrel Release from the SPR (Strategic Petroleum Reserve) Is A Huge Factor That Nobody Is Talking About
Demonstrating the administration’s panic over the impact that high gasoline (and even higher diesel) prices would have on the Democrats’ prospects in the November midterm elections, Biden announced in early April an unprecedented release of 180 mb of crude from the nation’s SPR over the following 6 months-i.e., 1 million barrels per day, every day, from May to October.
Over the past few months, I have read dozens of articles arguing that “demand destruction” has been leading to “builds” of crude in storage, and not a single article has noted that the builds have occurred SOLELY due to the release of 7 million barrels per week from the SPR. Despite that release, we have not had a single weekly crude build of 7 million barrels which means that if no oil had been released from the SPR, we would not have had a single crude build in the US in the past few months.
To put this yet another way, in the absence of the SPR release, we would have had a crude draw every week and the amount in non-SPR storage would have been about 120 million barrels (May thru August releases-120 days-at 1 mbd) LESS than the EIA has been reporting in its weekly reports (which EXCLUDE the SPR draw).
To put this a third way, there has been NO “demand destruction” relative to production-in other words, demand has actually exceeded production over the past few months but it doesn’t look that way because 120 million barrels have been released from the SPR.
What is even more interesting is that despite the release of 7 mb of crude from the SPR per week, there was a crude draw of 7 million barrels two weeks ago and a crude draw of 3.3 mb for the week ending 8/19 (reported by the EIA on 8/23/22). In other words, crude supply in the US was unable to keep up with crude demand-despite the addition of 14 million SPR barrels to the supply over those 2 weeks.
Finally, it should be noted that the 120 million barrels that have been released from the SPR so far have driven the SPR to its lowest level since 1985-and there are still another 60 million barrels to be released in September and October. But keep in mind that according to longstanding procedure, these barrels must be replaced. Therefore, if that policy is followed, 180 mb of crude must be returned to the SPR in the future, increasing future demand.
OPEC+ Has Undergone a Huge Change In The Past Eighteen Months-But American E & P’s And Oil Experts Haven’t Noticed
As I explained in my previous article, huge changes in the recent geopolitics of the Middle East have led OPEC to respond to the SPR release (and to Biden’s recent trip to Saudi Arabia) in a way that has to a large extent negated the impact of the SPR release. I explained in my previous article that since his inauguration 20 months ago, Biden had been hostile to Saudi Arabia and the United Arab Emirates (UAE). Since I provided substantial details on this in my previous article, I will only briefly summarize and update that discussion here.
As I previously explained, while the US has been abandoning the Middle East, both China and Russia have been doing the opposite. As the Saudis and the UAE–the only countries in the world with spare capacity to impact global supplies-are concerned about the US’s apparent interest in enriching Iran and allowing Iran to obtain a nuclear weapon (due to their assumption that a very poor “deal” with Iran is likely) and as these Gulf countries see that America has abandoned other former US allies (such as Afghanistan), Saudi Arabia and the UAE have logically decided to do what’s best for Russia, not America. Saudi Arabia and the UAE’s refusal to pump more oil-even after Biden made a personal trip to Saudi Arabia a few weeks ago-helps Russia by keeping global oil prices high.
Indeed, for various and complicated reasons, OPEC+ has underproduced its published targets by almost 3 mbd over the past few months. Saudi Arabia and UAE could have pumped more (how much more is not clear) but have clearly chosen not to do so, keeping world markets tight and maintaining an average Brent price this year of >$100. Based on OPEC’s actions in the past 18 months (including Saudi Arabia’s oil minister saying last week that OPEC might actually cut production at its next meeting!), it is clear to me that today’s OPEC is different from OPEC at Biden’s inauguration. Whereas OPEC previously stated it was happy with $75 oil (and Russia traditionally stated it was happy with $45 oil), OPEC has continually refused to add more production despite triple-digit Brent (and Arabian light) prices almost all of this year.
In essence, when faced with a choice, Saudi Arabia and UAE chose to do what benefits Russia (higher oil prices generating billions of extra dollars to Russia, especially important to Russia now given the expenses associated with Russia’s attack on Ukraine and hits to the Russian economy due to sanctions) than what benefits the US (lower oil prices). OPEC feels that the US has abandoned the Middle East, while Russia has done the opposite. Given the foregoing-and since OPEC (ie, Saudi Arabia and the UAE) can absolutely determine global crude prices by changing their production-I believe OPEC’s new price “setpoint” for crude on a long-term basis will be at least $90-$100 and as high as $110 to $120. OPEC would probably want to avoid sustained prices over $120 to prevent meaningful “demand destruction”) which I do believe would occur at $130 WTI (pushing gasoline prices over $5 again and diesel prices solidly above $6).
Could WTI Hit $130? $140? $150?
As I noted in the above paragraph, I believe OPEC will try to prevent Brent/WTI from exceeding $120 for any meaningful period of time. But over the past few months, some experts have argued that if demand increases, OPEC does not have the spare capacity to address much additional demand, and that therefore, prices could rise to $150 or even $200.
I don’t think that is very likely because at $150 WTI, gasoline in the US will exceed $6 per gallon, diesel will likely exceed $7, and demand destruction will lower demand and bring supply and demand back into balance in the low $100’s. In addition, I think both domestic and international supply will be incentivized with Brent and WTI in the $120 range and above. Domestically, WTI of $120 would enable E & P’s to add rigs, pay all the other expenses discussed above, and still make boatloads of FCF. International producers would be similarly incentivized, plus we might find that Western sanctions against Iranian (assuming those remain in place) and Venezuelan production are much less enforced at WTI of $120 than they might be at WTI of $90 (we are already seeing waivers being given to Western oil companies that operate in Venezuela).
In summary, basic economics (and increased likelihood of recession should oil go to the $120-130 range) would work to increase supply, lower demand, and bring oil prices back to where both producers and consumers can live with it, which I believe is between $90 and $110.
I will close by saying that the lower end of that range is more likely in September and October-as the SPR release continues-and the upper end of that range is more likely in Q4, as the SPR release ends. If Europe actually implements its sanctions against Russian oil effective 12/5/22, that might push oil past $110, although as discussed above, demand destruction may then take hold and prevent oil from going much beyond $120-$130.
Counterarguments To The Foregoing Thesis
The following might sustainably lower oil prices below $90:
1. Iranian oil comes back after a new nuclear deal is signed.
Although I think handing Iran tens of billions of dollars so it can further develop its nukes and long-range missiles (hello, North Korea) is a worse decision than Europe’s decision to rely on Russian hydrocarbons, recent events suggest that this may happen. I think such an event-especially given that Iran has somewhere between 60 and 80 million barrels in floating storage-is likely to lower oil prices meaningfully, possibly below $90 and maybe even below $80. But there are a couple of factors that may minimize the impact of Iranian barrels. First, it appears that Iran can only add about 1 mbd to global supplies (after the initial release of floating storage), and if Europe sanctions Russian oil, those sanctions may well remove that amount of oil (or more) from the global market.
Second, if sanctions are lifted, Iran’s production may come under OPEC control so that Iran’s extra production/exports may end up being nullified completely by OPEC policy, as suggested by Saudi Arabia’s oil minister last week.
Third, the SPR release will likely end at about the same time (or before) Iranian barrels hit the market, further muting the impact of the Iranian barrels.
Therefore, although crude prices would initially drop if (and when) a nuclear deal is signed, the long-term impact of such a deal on the oil markets may end up being mooted by other events.
2. Global recession.
Obviously, a global recession will lower demand for hydrocarbons, which may well decrease oil prices back to $80 or even less. There are valid arguments to be made supporting-and rebutting-the likelihood of a recession, and in my book, it’s way too close to call. But even if a recession is on the horizon, my guess is that OPEC and domestic E & P’s will show enough restraint (as they have already) that WTI will not drop much below $80, for reasons explained above.
If My Thesis of “Higher-For-Longer” Is Correct, What’s The Best Way to Play it?
In early March 2022, I submitted an article on TETRA Technologies, Inc., (Tetra Technologies, Inc. – 100% Return In One Year. (NYSE:TTI)) in which I argued that Russia’s attack on Ukraine would lead to major realignments in global hydrocarbon supply. Because I wrote that article just a few days after Russia attacked Ukraine, my thesis constituted a projection of what I thought would happen, but there was not much evidence (at that time) to actually support my thesis. Part of my thesis was based on an understanding of Putin-my belief that he would pursue his attack with vengeance, as he had in Chechnya and Georgia, as well as his use of chemical weapons in Syria and his support of the separatists in eastern Ukraine since annexing Crimea in 2014. Unlike many talking heads who spouted the common (and sometimes wrong) “wisdom” that geopolitical events are usually short-lived and have minor impact on global markets, I believed the war would be prolonged, and that Putin might well resort to attacks on civilians, especially if the war wasn’t going as well as he had hoped. I further posited that the longer the war lasted, and the more draconian the attacks on civilians, the more determined the West would be to terminate its dependence on Russian hydrocarbons.
Unfortunately, since I submitted my TTI article in early March, my fears of civilian targeting have been realized to an even greater degree than I had envisioned. In essence, subsequent developments in the Ukraine war-and the West’s response to it-have provided strong support for the belief I expressed that the West would be moving away from Russian hydrocarbons. Russia’s attack on Ukraine and the resulting motivation to increase hydrocarbon production in the US (and elsewhere, of course) has further enhanced the value proposition of virtually all companies involved in the production of hydrocarbons, and although many oil and gas equities have risen as WTI and NG prices have gone up, those increases do not adequately reflect what I believe to be a sea change in global hydrocarbon supply channels.
Based on the above beliefs, I loaded my portfolio with various oil-and-gas companies, and in my previous article, I discussed five companies in my portfolio that I believe offered compelling value. Due to the length of this article, I am limiting my discussion to just 2 of those companies, but I continue to believe that the companies I do not discuss here– Callon Petroleum (CPE), Ring Energy (REI) and CSI Compressco (CCLP)-offer at least 50% upside over the next year.
The two companies I discuss below are Energy Transfer (NYSE:ET) a huge midstream, and TETRA Technologies (TTI), which is probably my favorite equity in the oil and gas space because it offers not only a growing and unique oil/gas services business but also because TTI has three renewable initiatives that could help the stock price to double in 2023.
1. Energy Transfer (ET) Has 50% Upside Over the Next Year.
I have written 5 articles on ET. In my very first article on ET published in Jan. 2021, I recommended it when it was trading at $6.65. I wrote a second article in Feb. 21, and then a series of 3 articles in May, 2021 (third article, fourth article (Energy Transfer (ET): Q1 Operational Performance Augurs Well For Stock) and fifth article (Energy Transfer (ET) Stock: Setting A 12-Month Price Target Of $14 Per Share).
Although ET has done well since I first recommended it (total return, including distributions, of almost 100% since January 2021), I hereby reiterate my most recent price target for ET of $17, which I set in my April, 2022, article cited above. This price target amounts to an additional 50% return over the next year (ET is $12.12 as I write this). I posited in my very first article that ET would have a very good 2021 and an even better 2022, and that is in fact what has happened. A good part of ET’s success is due to the fact that ET uses its 120,000 miles of pipelines to move about 30% of the natural gas that is shipped around the United States every day and Europe’s goal of replacing Russian NG has increased domestic NG flows (as well as NG liquids-another big profit center for ET) in 2022, filling ET’s pipelines and increasing ET’s revenues.
Given that NG is trading at $9.32 as I write this, it is very likely that NG flows will continue to increase into 2023 and beyond, further adding to ET’s EBITDA and FCF. Because so many other SA authors have written about ET (probably over 20 articles in the past month), I will focus my ET discussion on a couple of issues that have not been addressed by the other authors.
The most common negative comment I read in these pages argues that ET is a bad investment because it may not stick to its previous low capex projections and instead, will go back to spending too much on capex. There are two problems with this criticism. First, since when did spending money to increase revenues become a problem? Isn’t that what happens with most tech companies? It seems capex in the oil-and-gas field is a bad word, but in other spaces, it’s a good expenditure. That makes absolutely no sense. The correct question to ask is: What kind of return can ET earn on the capex it is about to spend?
In the past two years, ET’s EBITDA has gone from about $10.5 billion to upper end of guidance of $12.8 billion projected this year (personally, I think ET will hit $13 billion). Didn’t that EBITDA climb because ET bought Enable (a kind of capex, or investment of your capital, -buying a company in anticipation of a return on that investment) and because ET has brought online multiple other projects on which capex was previously spent but was now generating revenues and EBITDA? And if that is true-which of course it is-why are we denigrating ET’s current capex spending plans?
Again, that makes no sense. So I now hear the naysayers arguing-“But look how many billions of capex ET spent in the past, generating poor returns,” to which I respond, “That’s ancient history.” Every investor is, of course, welcome to judge a company by its previous track record, but if you miss an inflection point-a change in either the market and/or the company-you miss the outsized returns that someone who sees that inflection point will make. Frankly, it was clear to me in January of last year, that an inflection point was upon us, both in how ET was being run and in the hydrocarbon market. Based on identifying that inflection point, I recommended ET at $6.65, bought a boatload of it, and have more than doubled my money.
Others disagreed with my view in Jan. 2021, but continuing to disagree with what has now become obvious (i.e., that ET is generating excellent returns on its capex) just because ET didn’t spend its capex as productively as it could have years ago means leaving money (and outsized returns) on the table.
The other problem with the complaint about ET increasing its capex spend is the apparent lack of recognition that global hydrocarbon supply chains changed in 2021 and even more so since Russia attacked Ukraine in February this year. Given the marginalization of Russian hydrocarbon production-and the consequent focus on US hydrocarbons-is it really THAT unreasonable for ET, a hydrocarbon midstream, to increase its capex so it can take advantage of the markedly changed macro environment?
Finally, a few words about my $17 price target. In my earlier articles, I felt there was a good chance that ET would return to its historical distribution of $1.22/unit in 2022, or perhaps in early 2023, and indeed, ET has increased its previously-lowered distribution in each of the last three quarters. I think there is a decent chance that ET raises its quarterly distribution from 23 cents in Q2 ’22 to 27 cents in Q3 and 30.5 cents (its original distribution) in Q4, although the trip from 23 cents to 30.5 cents might take 3 quarters rather than 2. Reaching a distribution of $1.22 would constitute a 10% yield on today’s price. Also, a $1.22 distribution would support my price target of $17 (a 7.2% yield, which is very close to ET’s historical yield).
In addition, with debt at about $50 billion, and assuming (as I do) EBITDA hits $13 billion this year, the debt ratio will be comfortably under 4 to 1, and in my book that will render debt a non-issue, especially in the current hydrocarbon macro environment. Some people are concerned that an FID (final investment decision) on the Lake Charles LNG facility-which is likely to be announced this year-will ramp debt back up, but although that is possible, I rather doubt it. First, I believe ET will share the equity cost of Lake Charles with one or two partners, lowering ET’s share to perhaps $1.5 to $2 billion. Second, even with an increased distribution, I expect ET to generate several hundred million of FCF per quarter in 2023 and beyond, and since ET’s likely equity contribution will be spread over several years, there should be enough FCF to cover Lake Charles capex out of cash flow while paying the full $1.22 distribution.
Therefore, with an implied distribution yield of 7.2% ($1.22/$17), and strong hydrocarbon fundamentals in 2023, a $17 price target in a year is reasonable. Therefore, I think ET is a very good buy under $13, which would give you a tax-advantaged 10% distribution yield on purchase price once the distribution hits $1.22. This is not to say ET couldn’t be bought in the $11’s, or maybe even $10’s if the S & P heads backs to 3000, but as they say, timing the bottom is impossible, and buying an equity that yields 7.6% today and is likely to yield 10% in six to nine months is still a pretty attractive proposition.
2. TTI Has Low Downside Risk And 100% Upside-And Potentially Even More If Its Zinc Bromide Battery Storage and Lithium Initiatives Succeed
I have written two articles on TTI this year (Tetra Technologies Stock: A Potential Double In One Year and Tetra Technologies, Inc. – 100% Return In One Year. TTI was at $2.74 when I first recommended it on 2/22/22, six months ago. TTI is at $3.96 as I write this, sporting a return of 45% in the past six months (which months haven’t been so good in the overall markets). If my discussion of TTI here interests you, you may find it worthwhile to go back and read my earlier articles.
As discussed above, the West is concertedly moving away from Russian hydrocarbons, and that is enhancing TTI’s value proposition in two ways-by strengthening both TTI’s legacy oil services business as well as amplifying the potential of TTI’s renewable initiatives which are themselves enhanced as hydrocarbons become more expensive.
First, the profitability of TTI’s oil-services business has been improving as hydrocarbon production has increased and with WTI likely to stay in the $90’s and above and NG reasonably likely to stay over $7.00 this year and next year ($9.32 as I write this)-not to mention some new opportunities for TTI in the hydrocarbon space–TTI’s legacy business has been doing well in 2022 and likely to do even better in 2023. Therefore-and as explained in more detail below–I maintain my 1-year price target for TTI’s legacy business at $5.50 (the math on that target can be found in my previous articles).
Second, the high cost of hydrocarbons-which, as discussed above is likely to stay high-as well as the recently-enacted Inflation Reduction Act (“IRA”) will both serve as tailwinds to TTI’s renewable initiatives, two of which are likely to add $2-$3 in stock value over the next year, yielding an overall price target of $7.50 to $8.50 (midpoint of $8.00) in one year, and representing 100% upside from TTI’s price today ($3.96). I should add that the consensus target among analysts following the stock is about $7.00 but our targets differ because I believe they have not given enough value to TTI’s lithium potential.
TTI’s Q2 legacy-business results were good. Revenues grew 8% from Q1 22 and 38% from Q2 21. Adjusted EBITDA was about flat with Q1 22 after deleting one-time items. Q2 22 cash from operating activities was $18 million, far exceeding pre-pandemic Q1 20 cash flow.
As I mentioned above, TTI appears to be getting involved in new markets/products not only in its renewable businesses but also in its legacy offshore services space. For example, TTI is beginning to serve oil and gas operators in Argentina’s shale basin, providing its flowback and best-in-class sand management services, soon to be followed by its leading water recycling services. In fact, because of the lack of midstream and pipeline infrastructure in the Argentine Vaca Muerta basin being served, TTI’s suite of services in Argentina are broader (and thus likely to generate more revenues) than the same type of services that TTI provides to domestic E & P’s.
Another growing oil field service being provided by TTI, both domestically and internationally, is water recycling. Disposing of produced water (water that comes up out of wells after the well is fracked, and also as part of the process of producing oil and gas) has become a major issue, both for practical and environmental reasons. The practical reason is that it appears that disposing of produced water by forcing it into disposal wells has been causing earthquakes. The environmental reason is that there has been growing pushback to the use of fresh water to frack oil/gas wells-especially in arid areas like the Permian basin. If produced water can be recycled and then used to frack additional wells, both of the above problems are solved. The costs of disposing produced water are very high. Add to this the cost of buying more fresh water to frac wells makes the total cost of water at well sites to be very high-not to mention the environmental issues around water.
Yet another growth opportunity was described by Mr. Brady as follows:
I’m excited to announce that during the second quarter, we also had a successful trial for our new auto drill-out technology for a large independent producer in Appalachia. This new technology is expected to reduce wellsite personnel by more than 30%, reduce rig up and downtime by approximately 40% and reduce HS&E exposure [NOTE ADDED: the safety exposure of having so many personnel around the well site], a meaningful impact to our customers’ well operations and their economics.
Although it is impossible to quantify the revenue impact of the above technology, it seems that any technology that can lower wellsite payroll costs and downtime by 30-40% would represent a huge savings to the operator and would therefore achieve substantial market penetration and provide a high margin to TTI. This is especially true now given that oil-field service workers are not easy to find. TTI achieved such savings and grew revenue with their sand filtration technology (which they call “Sandstorm,”) and is now looking to expand their wellsite expertise with technology that facilitates completing a well.
As mentioned above, this is a rapidly growing business for TTI, who is a leader in the water-recycling field. In Q2 22, TTI recycled 571 million gallons-up 62% since Q2 21 and up 17% sequentially. Given the seismicity and environmental problems discussed above, there is every reason to believe that this business will continue to grow rapidly.
Finally, I think the most exciting new oil-field-services opportunity for TTI is the ability to go a step beyond TTI’s current water-recycling and instead be able to clean up produced water to the level that the water can be used to irrigate a field (surface discharge). Today TTI is already cleaning produced water enough to be used to frack wells. Because disposing of produced water (as discussed above) is costly and creates environmental and seismic issues, and because of drought conditions across the US and around the globe, if produced water can actually be productively reused-maybe even more than once-that will be a billion-dollar win for the company that proves that tech on a commercial scale. Produced water is very complex, containing not only very high concentrations of dissolved minerals, including some pretty toxic ones (iron, arsenic, lead, mercury, cyanide) but also substantial concentrations of various minerals that have commercial value (bromine, calcium, manganese, barium, etc) as well as various life forms (e.g., algae, bacteria). Figuring out how to cost-effectively treat that water to a level where it can be beneficially reused is a complex technological challenge but TTI’s CEO stated that TTI is working on exactly that challenge (“that’s been a focus of ours as part of the next evolution of our recycling capabilities.”
Switching now to TTI’s lithium progress, during the Q2 22 earnings call, TTI announced lithium and bromine results of samples obtained from an exploratory well on its 100%-owned acreage that was drilled in Q1. Because previous results in the same brine aquifer (the Smackover formation) have been positive- (around 250 to 300mg/liter), I expected similarly positive results from TTI’s own testing. The results far surpassed my expectations, with lithium levels far higher than I expected. This is how Brady Murphy, the CEO, stated the results during the earnings call:
The fluid sample test results were conducted by 2 independent labs, and all valid results yielded very consistent lithium results across all 3 zones with an average concentration of 473 milligrams per liter, which is 67% above the concentrations used for the exploratory target.
Importantly, the CEO also stated that the well was
…perforated in selected zones of good porosity across a total depth of 196 feet, with fluid samples collected in 3 primary groupings of perforations.
Since I have extensive investments in the lithium space, I follow that mineral very closely, and I can tell you that these results far exceeded my expectations. To understand why, let me present a short primer on lithium. As almost everyone knows, sales of electric cars are increasing rapidly, and will continue to do so. Although battery cell chemistries differ among different cars, they all use lithium. Lithium is also used in laptops, cell phones, fighter jets, and in many other products essential for national security.
At the present time, the majority of global lithium is mined in Australia, South America and China, and the vast majority of the mined lithium is processed in China. A trivial amount of global lithium (1-2%) is mined in the US.
For the foregoing reasons, there has been great impetus to develop a domestic lithium resource and many different companies are working on exactly that across the US, a goal that has been markedly accelerated by the recent passage of the IRA. Lithium is sourced via either “hard-rock” mining or the extraction of lithium from large underground salty-water pools (“brine aquifers”). TTI has brine mineral rights to 40,000 gross acres in Arkansas that sits on top of one of these brine aquifers, called the Smackover formation. TETRA has sold an option to the lithium for 35,000 of those 40,000 acres to another company (Standard Lithium, SLI) but has maintained complete ownership of all the bromine in the entire 40,000 acres and to the lithium in approximately 5,000 of those gross acres. Although lithium has never been produced from the Smackover, Albermarle and Lanxess (both large chemical producers) have been producing bromine from the Smackover for decades, so extracting a mineral from the Smackover is a well-established process. It is interesting to note that in addition to producing other chemicals from the Smackover brine, Albermarle also happens to be the biggest lithium producer in the world.
Previous testing of lithium concentrations in the Smackover have yielded results in the 250-300 mg/l range, and frankly, that is what I expected TTI’s results to show. A level of 473 mg/liter is the highest level I have heard of anywhere in the US and would rival some of the best brines in the so-called Lithium Triangle in South America (which contains 60% of the world’s known lithium reserves), where those excellent brine resources generally run between 300-400 mg/l, and only rare brines (especially in the Hombre Muerto salar) exceed 500 mg/l.
A question one must always ask when reviewing brine lithium concentrations is “How representative are those readings of the overall lithium content in the brine aquifer?” and the evidence here is comforting, for a few reasons. First, TTI hired two outside independent labs, and most labs worth their salt would insist on pulling multiple samples from as many different levels of the borehole as possible-in this case, samples were pulled from three zones, representing different well depths. Second, most quality laboratories would require that multiple samples be pulled from each zone and individually analyzed, adding to the reliability of the lithium readings. Third, the fact that the various readings “yielded very consistent lithium results across all three zones” suggests that the high lithium concentrations extends throughout that part of the Smackover. And fourth, the fact that the readings were made by two independent and unrelated labs enhances reliability.
Another very positive result from TTI’s testing were bromine readings of 5350 mg/l, which was slightly higher than expected. The bromine content is important for two key reasons. First, TTI’s businesses utilize bromine and TTI expects to soon need more bromine than the amount currently being provided through an existing supply contract. TTI’s ability to produce its own bromine should enable TTI to lower its cost of bromine, thereby boosting margins in the TTI businesses that use bromine. Second, being able to pull TWO valuable minerals (lithium and bromine) from a brine stream should enable TTI to capture two revenue streams from the same well, pipeline and related capex. One can imagine a flowsheet where the brine is pumped to the surface, and then bromine and lithium are sequentially extracted from the brine and the leftover brine, known as the tail brine, is then reinjected back into the formation to maintain the formation pressure so it can continue to produce.
Although lithium levels of 473 mg/l represent a very substantial advance in proving the commercial viability of TTI’s lithium resource, some important facts remain unknown at this early stage. First, flow rates from a lithium-brine-producing well will influence the amount of brine that can be pumped from the well per day. Since the amount of lithium produced depends on how much brine can be pumped, if the brine-production wells you drill have high flow rates, you need fewer wells (and thus, less cost) to pump X number of gallons of brine per day. TTI’s statement that the exploration well had “good porosity” would suggest that flow rates will be good, but knowing actual flow rates would be important.
Another unknown factor is what the brine looks like across TTI’s 5000 wholly-owned acres. Although 473 mg/l is awesome, that number came from a single well. To define a 5000 acre resource well, one would need quite a few more wells, and I expect that TTI will announce a schedule for drilling those additional wells in the near future.
During the earnings call, TTI indicated that the lithium inferred resource study will be out in “early-to-mid-September type time frame”-which basically means in the next week or two. That study should answer some of the above questions and provide the number of tons of lithium and bromine that are recoverable from TTI’s brine acreage. If the results are positive, as I expect they will be, publication of the inferred resource study is likely to be a catalyst to TTI’s stock price. Given today’s lithium prices, even a modest 10,000 tpa (tons per annum) production rate could easily add $100 to $150 million in annual EBITDA to TTI’s bottom line, which is a pretty significant addition to a company likely to report $80 to $90 million in EBITDA this year. This is not to suggest that lithium-related EBITDA is imminent-the most realistic time-frame for beginning production being 2025 or 2026-but it does give one an idea of the scale of EBITDA that lithium could yield once production occurs.
The recent passage of the IRA represents another significant incentive to domestic lithium activities. The IRA provides for billions of dollars of rebates to consumers buying electric cars, but only if those cars have a high domestic content of battery minerals. In addition, the IRA provides for billions of dollars to incentivize companies to produce battery minerals, and the DOE (Department of Energy) is ramping up its procedures to get those dollars out to companies like TTI. Although TTI hasn’t announced any such awards, it would seem to be the poster child as a likely recipient of such federal subsidies, which in TTI’s case could be used to help fund the a portion of the capex that TTI would need (probably in 2024/25) to build the facilities needed to actually produce its lithium.
Auto manufacturers keen on sourcing domestic lithium might be another source to supply a portion of TTI’s capex (I expect TTI to have well over $100 million in liquidity by end of 2023-which should be enough to fund its contribution to lithium production facilities without a need to issue more shares and thereby avoiding stock dilution). Attempting to insure receiving enough lithium to produce their upcoming electric cars, Ford and other auto manufacturers have recently been making “prepayments” to lithium producers and potential lithium producers, which dollars are meant to help these lithium producers to bring their lithium to market faster and in larger quantities. It would seem that once TTI proves up its lithium resource (which I estimate would be mid-2023), it would be a good candidate to receive comparable prepayments from domestic EV manufacturers to help fund the capex to develop its lithium assets.
The other renewable initiative that I believe is likely to add to TTI’s stock price over the next year has to do with a new market for TTI-its sale of zinc bromide for batteries that are used to store renewably-generated solar- and wind power. As I explained in my previous articles, TTI announced in December, 2021, that it had entered into an agreement with Eos Energy Enterprises (NASDAQ:EOSE) whereby TTI would supply its high-purity zinc bromide for EOSE’s storage batteries. During the earnings call, an analyst asked a question about the sales prospects for TTI’s zinc bromide product (which they call PureFlow) and TTI’s CFO, Elijio Serrano, answered as follows:
Some have speculated that the revenue is somewhere between $8 million and $10 million. We have not pushed back on that number, and that’s strictly PureFlow.
Even if the EBITDA margin on 2022 PureFlow sales is only 30% (and it may be higher than that), an additional $3 million of EBITDA is meaningful for a company with quarterly EBITDA run rate of around $20 million, and especially so since TTI expects its zinc bromide sales to jump substantially in 2023.
Finally, EOSE is not the only company that makes zinc bromide batteries (Australia-based Gelion Technologies and Redflow Limited are also commercializing zinc bromide-containing batteries), and given the high purity of TTI’s zinc bromide-and the fact that TTI is a domestic producer of that compound-it is certainly possible (if not likely) that TTI will announce zinc bromide sales to other companies (in addition to EOSE) sometime this year, with additional zinc bromide sales adding to 2023’s EBITDA.
During the earnings call TTI announced another new business in the renewable space which TTI had not previously discussed, as follows:
Also in the third quarter, we will be delivering our first supply of calcium chloride to an international lithium producer for use in their lithium processing operation. This shipment is the first of 6-month order that we have received, and we believe represents a new market application for our calcium chloride product that will add incremental revenue and opportunities in the future.
Although I am quite familiar with the lithium space, I do not know how calcium chloride is used in lithium processing and therefore cannot offer an opinion on how significant this new market application could be for TTI’s revenues and EBITDA going forward. However, this sale was mentioned several times during the earnings call and may in fact become another meaningful monetization of TTI’s calcium chloride production capability.
For the reasons discussed above, I reiterate my previous assessment that TTI’s legacy business is worth $5.50 within one year, and the renewable initiatives should add $2 to $3 (midpoint: $2.50) in additional stock price, for a total one-year price target of $8.00. Indeed, if the lithium progress discussed above pans out, the lithium prospects alone could add $2 to $3 to the stock price over the next year.
Therefore, I believe TTI is a bargain today in the low-to-mid $4’s and a good deal today anywhere in the $4’s. If the lithium inferred resource study that is due out in the next week or two is positive (and assuming the markets haven’t dropped substantially between now and then), TTI could well hit the $5’s by the end of September.
Finally, if both the lithium and zinc bromide renewable initiatives achieve key milestones, TTI may, over the next year or so, start being thought of as a leading innovator in the renewable space (rather than being thought of just as an oil-and-gas services company), leading its EV-multiple valuation to expand, adding even more value to the stock price on top of a significantly-expanding EBITDA in 2023.
Risks
Although I have a high level of confidence that WTI is unlikely to drop into the mid-$80’s or below, and that NG is unlikely to hit $7 or less, I could be wrong, and if so, ET’s and TTI’s stock prices are likely to fall, even if they execute their business plans well.
Second, an additional market correction of 10-20-30% will very likely hit ET’s and TTI’s prices, even they continue executing well. Since I bought my crystal ball at the dollar store, I have no idea as to the likelihood of a meaningful correction in the stock market, but if it happens, it is likely to impact TTI’s stock price.
In my view, even a recession is unlikely to drop WTI below $70 (OPEC can easily prevent oil from going back to $70, and I believe they will do exactly that), but obviously that sort of environment would not be conducive to increasing stock prices. That concern is further minimized for TTI because its renewable initiatives-if successful-may allow TTI to buck the trend of falling stock markets because even a recession isn’t going to stop (or even slow down) continually-increasing lithium sales and storage battery penetration.
A third risk is that the whole energy field is unloved by investors. There is a reasonable “risk” that the market’s dislike of oil and gas equities may not change much, and thus, even though ET and TTI generate increasing EBITDA, the market may continue to undervalue them, as occurred just a couple of months ago, when ET fell below $10 and TTI dropped down to about $3.75-despite improving financials for both of them.
Conclusion
I believe Russia’s attack on Ukraine-regardless of how it turns out for the Russians and Ukrainians-has caused and will continue to cause a sea change in global hydrocarbon production and flows. Although there remain many uncertainties-how successfully will Russia avoid sanctions? Will India and China continue buying Russian crude? Will Iran start adding barrels to the global supply? Etc.-I strongly believe that hundreds of millions of Russian crude and products barrels and many BCF’s of Russian NG will fail to come to market over the next couple of years. Although this involves looking out several years and is more uncertain, I personally think this will be a permanent change once supply channels have been redirected, meaning that I believe Russian hydrocarbon production will drop from this point forward and never return to its previous levels. As an aside, I also think that due to high prices and geopolitical considerations (especially for Europe), as well as the recently-passed Inflation Reduction Act, the transition to electric cars and renewably generated electricity will be faster than it would have been otherwise, to the benefit of our planet and our children-and to TTI’s renewable initiatives.
Regardless of how things actually play out, I believe domestic E & P’s (and probably international ones, as well) will not throw capital discipline out the window, but rather, increase production when demand and prices justify it and moderate that increase in drilling (which, due to shale decline rates, may actually reduce production) if demand and prices support that approach. Finally, I believe the days of E & P’s borrowing money to increase production are over-if E & P’s increase production, they will almost always do it within cash flows while still paying down debt as needed and returning cash to shareholders, just as ET and TTI, discussed above, have been doing.
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