The article below is an excerpt from our Q3 2025 commentary.
At Goehring & Rozencwajg, we’ve built our approach around a simple but often uncomfortable conviction: the best value in natural resource equities is usually found where everyone else has already given up looking. We focus on the sectors that have fallen out of favor, where prices are depressed, and sentiment has coalesced into certainty. In these moments, a tidy narrative always emerges to explain the gloom—one that encourages investors to extend today’s troubles far into tomorrow. Instead of accepting that storyline, we look for the quieter evidence that supply and demand are shifting beneath the surface. Those early signs usually mark the end of the bear market and the start of the next bull phase, long before the consensus notices.
When this approach works, it tends to work suddenly. The consensus, having grown comfortable with its own pessimism, is forced to reverse course, often violently. Over the years, we’ve noticed a recurring error behind these episodes: investors regularly confuse long cycles with true structural change. Cycles happen all the time; structural shifts, by contrast, are rare enough to practically count on one hand. Mixing them up can be costly—the difference, in many cases, between being swept out in the undertow or catching the turn early enough to earn exceptional returns.
Few markets today illustrate our strategy better than crude oil. Investor sentiment is almost uniformly bleak. The standard storyline claims the world is drowning in supply—shale output that never seems to ebb, now joined by rising OPEC+ volumes. Demand, we’re told, is on the verge of rolling over as electric vehicles crowd out traditional consumption. The attitude feels familiar. In 1999, gold was dismissed as a “barbarous relic,” a quaint artifact of monetary history with no place in a modern, credit-driven economy. Today, oil carries that same stigma: an outdated fuel from a world supposedly moving on. Gold’s obituary, of course, proved premature—it went on to become the best-performing asset of the next twenty-five years. One has to wonder whether oil, now playing the role of the relic, is set up for a similar reversal.
The bearish case today finds its clearest expression in two places—one bearing the weight of officialdom, the other commanding a large online following. The first is the International Energy Agency, which has maintained a gloomy view of oil markets for years. In its latest Oil Market Report, the IEA describes crude markets as suffering through the worst glut on record. Next year, they argue, will be even worse, with oversupply surpassing the levels reached during the COVID-19 collapse. We take a very different view. The current market looks nothing like that extraordinary period, when inventories ballooned to the point of overwhelming global storage. Today, stockpiles sit at relatively lean levels, signaling balance rather than excess.
During COVID, the IEA’s dire pronouncements helped drive sentiment to extremes—and that despair created one of the best investment opportunities we’ve ever had. Our energy positions purchased during that panic delivered exceptional results. If investors are now reaching for the same pessimism they embraced then, we are more than willing to see how that story plays out a second time.
In the private sector, the role of chief pessimist has largely been taken up by Doomberg, now among the most widely read financial writers on Substack. He has been unwavering in his negative stance on crude, and in recent months, he has redoubled it. His reasoning is captured neatly in a passage from his latest essay, “The Cup Runeth Over,” where he lays out the mental model he believes investors should adopt:
“Few erroneous concepts [Peak Cheap Oil] have cost investors more capital than this one, primarily because it feels like it should be true. The consensus view is that there is a finite amount of hydrocarbons under the surface, and surely the easiest stuff has already been picked off. As we have consistently argued, a superior mental model is to assume that there is an infinite supply of hydrocarbon resources [ed. emphasis ours], that oil and gas companies are technology superpowers that just happen to produce energy, and that the long-term real price of all commodities is therefore lower.”
We debated Doomberg in early 2024 and have not changed our views. The long-term real price of oil has not drifted steadily downward; history shows the opposite. In the 1970s, real oil prices rose more than fivefold, peaking at $106 per barrel (2024 USD) in 1981. As new discoveries came online in the 1980s and 1990s, prices retreated nearly 80%, bottoming at $20.64 by 1999. The industry’s underinvestment during that period, coupled with declining output from Mexico and the North Sea, set the stage for the next surge: an all-time real high of $175 per barrel in 2008. The subsequent wave of spending unleashed the U.S. shales, which in turn produced a double-bottom in prices around $35 per barrel in 2016 and again during the COVID lockdowns. Taken together, the pattern is unmistakable. Oil prices do not follow a gentle, inevitable glide path lower. They trace a recurring cycle driven by exploration, development, and the unavoidable reality of depletion.
Second, while hydrocarbon resources are finite—an uncontroversial point—we do not interpret that to mean the world is running out of oil, or that production is about to collapse. But neither does any of this argue for a bearish stance. History again provides the check. In 1970, global output was 48 mm b/d. By 1980, it had climbed to 63 million—a nearly 3% annual growth rate. That increase did nothing to prevent prices from rising fivefold in real dollar terms. When oil bottomed in 1999, production was 71.5 mm b/d; by 2008 it reached 83.1 million, a 2% annual gain. Prices still surged. Indeed, since 1999 the world has produced nearly as much oil as it had in all prior decades combined—an extraordinary accomplishment that nevertheless coincided with real prices trading above $100 per barrel for more than half of the last quarter-century.
In short, oil prices do not rise when the world runs out of oil. Rather, they rise when investors become so bearish that capital is unavailable, and new production ceases to offset base declines. In 1970, it was the decline of conventional U.S. production. By 2003, the pressure points were the North Sea and Mexico. Today, it is the U.S. shales. These cycles repeat with remarkable regularity, and by our reading, we are simply nearing the end of a long, grinding bear phase.
The steady drumbeat of negative headlines has taken its toll on investors. Energy now makes up a mere 2.5% of the S&P 500—down from 15% over the last century and 10% over the last twenty-five years, even accounting for prior downturns. Redemption pressure tells the same story. Shares outstanding in XLE and XOP, the two dominant energy ETFs, have collapsed by 42% and 74% respectively since 2022, as investors have rushed to abandon the sector.
And yet, in the middle of all this gloom, several genuinely bullish developments have appeared. The consensus, true to form, filters out anything that doesn’t fit its storyline and projects the negative data far into the future. We approach turning points differently. When we make a bold call that a bear market is ending, we look for specific “mile markers”—indicators that confirm we’re on the right track. In the past few months, three pieces of fundamental data have surfaced that strongly suggest we are moving in the direction we anticipated.
First, U.S. shale oil production turned negative year-on-year in October. We first forecast this outcome back in 2019, arguing that shale output would begin to roll over around 2026. We later pulled that estimate forward to 2025—and events now suggest that call was on target.
Several years ago, well before today’s AI enthusiasm, we built a deep-neural-network model to parse the drivers of shale productivity. That work proved invaluable. The model made clear that most of the productivity gains the industry celebrated were not the result of breakthrough drilling techniques, but rather of something far more prosaic: high-grading. Companies were drilling their best remaining locations first.
Our conclusion ran counter to the industry’s preferred narrative, which held that rising productivity reflected better technology. The distinction may sound technical, but it carries major implications. If productivity gains stemmed from true drilling innovation, then the industry had unlocked additional resources and could expect years of continued growth. If, as our work suggested, the gains came from high-grading, then nothing fundamental had changed—the best rock was simply being drilled first, and the remaining inventory was inherently weaker.
Combining this insight with detailed inventory modeling, we projected in 2019 that the Bakken and Eagle Ford were nearing their peaks and that the Permian would top out around 2025. By early 2024, when we debated Doomberg, the Bakken and Eagle Ford had indeed rolled over, while the Permian was still expanding—exactly in line with our timeline. Still, the idea that the Permian might soon peak was treated as heresy, and the debate attracted considerable attention. Doomberg voiced the prevailing view: that technology and engineering prowess would carry the basin forward for decades.
The evidence now speaks plainly: the Permian has rolled. After reaching a peak of 5.73 mm b/d in October 2025, crude output has slipped by roughly 100,000 b/d and has turned negative on a year-over-year basis. This decline in the Permian has, in turn, pulled total U.S. shale oil production down nearly 200,000 b/d compared with last year. None of this resembles a temporary pause. Our models indicate the slowdown is fundamentally geological— rooted in the maturation of the resource—and therefore unlikely to be reversed by incremental engineering alone.
Doomberg points to rising NGL volumes as evidence that total Permian liquids will keep expanding, even while acknowledging crude has peaked. That is a risky conclusion to draw. Our modeling shows that this post-peak gas uplift is brief. If we are correct, year-on-year NGL growth should slow sharply over the next six months, with total Permian liquids— including NGLs—peaking on a sequential basis over roughly the same timeframe. Far from signaling endless growth, the divergence between gassy wells and falling crude production is typically the last chapter in a mixed-reservoir play—a kind of swan song before the broader decline sets in.
The significance of the U.S. shale rollover cannot be overstated. Over the past fifteen years, nearly 90% of all non-OPEC+ production growth has come from the shales—a larger contribution than U.S. conventional output provided in 1970 or the North Sea and Mexico did in 2003. With such an outsized share of global growth now faltering, the consequences this time are likely to be even more far-reaching.
In its latest World Energy Outlook, released on November 12th, 2025, the IEA appears to have made a notable shift in its long-term view of oil demand. Only a year ago, the agency declared with great confidence that the world was nearing peak consumption. Under its “Stated Policies Scenario” (SPS), beginning in 2023, the IEA projected that global demand would rise by less than 2 mm b/d through 2030, then retreat back to 2023 levels by 2035, and finish 2050 some 6.1 mm b/d below where it began.
In the new report, the IEA still presents its SPS figures, though even those have been revised upward—by 1.5 mm b/d for 2035 and 3.8 million for 2050. More importantly, the agency has introduced a new “base case,” the Current Policies Scenario (CPS). Under the CPS, oil demand grows meaningfully—up 6 mm b/d from 2023—and, crucially, does not peak at any point in the forecast window. By 2050, the IEA now sees total liquids demand approaching 120 mm b/d, compared with roughly 103 million in 2024.
Two factors drove this shift, both of which we’ve discussed at length in past letters. The first is the IEA’s revised view of total global energy consumption through 2050. In our 2023 Q3 letter—particularly in our essay on Jevon’s Paradox—we argued that the agency’s earlier projections of declining global energy use rested on a deeply flawed methodology. The new report suggests that the message may have finally landed. Under the updated scenarios, total energy consumption is now expected to grow by 100–150 terajoules between today and 2040—a dramatic reversal from their previous outlook. Instead of contracting, global demand is now projected to rise at roughly the same compound rate it has maintained since 2010. It’s a welcome course correction, though we suspect the eventual figures may still prove higher.
The second driver is the disappointing trajectory of global EV adoption. We have long argued that once you account for the full energy burden of battery manufacturing and renewable power generation, EVs are less efficient at moving people and cargo than widely assumed. That inefficiency, we noted, would limit broad adoption unless governments stepped in with substantial subsidies. Even with those subsidies, uptake has missed expectations. Just this month, Ford announced it would discontinue its highly promoted electric F-150. And much of the recent “EV growth” has come from plug-in hybrids—which still burn gasoline— rather than from true battery-electric vehicles. We expect consumers to remain hesitant for the same underlying reasons, and for future EV projections to continue falling short.
At first glance, the IEA’s methodological shift may seem like a footnote, but it carries major implications. Much of the bearish narrative around oil has hinged on the idea of imminent peak demand. Only a few years ago, the IEA’s Director General, Dr. Fatih Birol, warned that any company investing in a new oil project risked owning a stranded asset in a world of permanently declining consumption. He went so far as to advise firms not to approve a single additional project, lest they face future impairments. Under a falling-demand scenario, that position might have had some merit. But if oil demand is now expected to grow for decades, the calculus changes entirely. Companies must reinvest aggressively simply to offset natural declines—and even more so with U.S. shale production beginning to fall.
Just before publishing the World Energy Outlook, the IEA released what we consider the most consequential report in years. On September 16th, 2025, they issued a study titled Implications of Oil and Gas Field Decline Rates. The name alone helps explain why it drew almost no attention; it sounds like homework. But beneath that dry heading is a set of conclusions that point unmistakably toward a much tighter global oil market in the years ahead.
The main takeaway is that without any new investment, global crude fields would decline by 8% -- nearly 50% higher than the rate observed only a few years ago. To put this figure into perspective, every year the oil industry must bring on 8 m b/d of new supply simply to offset declines, up from 3.5 m b/d previously.
For the past fifteen years, nearly all of the world’s production growth has come from the U.S. shales. In hindsight, the shale boom stands as one of the most remarkable developments in oil industry history. Today, shale output—counting associated NGLs—approaches 15 mm b/d, roughly 50% more than Saudi Arabia’s production. Yet for all their scale, the shales are an unusual story. Shale oil wasn’t “discovered” in the traditional sense; it was released. The industry always knew where these resources sat, but the rock was too tight to produce economically. That changed only when George Mitchell of Mitchell Energy paired horizontal drilling with hydraulic fracturing, unlocking reservoirs once considered hopeless.
Once Mitchell proved the concept in the Barnett, the industry moved with astonishing speed. Rigs and frac crews multiplied, and the shales were developed with an intensity that conventional fields never experience. In that respect, shale is truly short-cycle. New production can be brought online in months, while conventional oil and gas projects require years simply to discover, delineate, and engineer. The IEA now estimates that a single conventional project can take nearly twenty years from exploration to first oil. By contrast, the shales grew from effectively zero to 15 mm b/d in less time than that.
It’s no surprise that the shale boom came at the expense of conventional exploration. Between 2020 and today, the industry has discovered only about 7 billion barrels of oil equivalent per year—down sharply from the roughly 30 billion discovered annually from 2000 to 2010. To put this figure in its proper context, the world consumes 35 billion barrels of oil every year. Development activity has slowed as well. By our estimates, real spending on conventional projects has fallen 35% since 2015. The result is clear: the world has been significantly underinvesting in conventional oil and gas, relying instead on the shales to shoulder almost the entire load.
All of this naturally raises the key question: what happens now that the shales have begun to roll over? The IEA set out to answer exactly that in its latest report, and the implications point to a much tighter market ahead.
The study is remarkably comprehensive, spanning some 17,000 hydrocarbon basins and organizing global output into three buckets: existing conventional fields, new projects, and shale oil. We spent considerable time reverse-engineering their methodology to reconstruct the full production profile over the next quarter century. The results, once laid out clearly, are startling.
At first glance, the report offers a seemingly balanced outlook. If today’s annual capital spending of roughly $570 billion holds, the IEA believes global crude production—about 97 mm b/d, excluding biofuels and refining gains—can be maintained through 2050. In a world where oil demand were truly peaking, that might be enough.
But as we’ve just discussed, the IEA now concedes that demand is likely to keep rising well into mid-century. Under their Current Policies Scenario, consumption climbs toward 120 mm b/d by 2050. To meet that higher level, the industry would need to add roughly 20 mm b/d of new supply—or face a structural deficit. That would require a dramatic increase in investment from today’s levels.
The report also leans far too heavily on future shale contributions. By 2035, the IEA assumes that continued investment will lift shale output from today’s 15 mm b/d to 18 million. Although they do not spell out their assumptions beyond 2035, our reconstruction suggests they are effectively assuming enough ongoing development to hold shale production roughly flat thereafter. Given what we now know about the geology, that is an optimistic reading— one that risks misrepresenting the true durability of shale supply.
We simply do not believe this outlook is achievable. The U.S. Energy Information Administration projects shale output declining by roughly 500,000 b/d by 2035, and by 2 mm b/d between now and 2050. Our own models point to even steeper declines. If so, the IEA may be overstating shale’s contribution by more than 4 mm b/d in 2035 and nearly 6 million by 2050.
The report then turns to the critical issue of post-peak decline rates. Once a field peaks, production drops quickly. Without continued infill drilling, the IEA estimates that a conventional field experiences a “natural decline rate” of 8.1% per year. With additional spending on maintenance, infill work, and secondary recovery, that decline can be moderated to 5.9%—the so-called “observed decline rate.” But both rates have been rising steadily. Since 2015, nearly 70% of newly sanctioned conventional projects have been offshore, and those fields decline at roughly twice the current global average. Shale declines faster still: absent new drilling, shale output falls 35% in the first year, 18% in the second, and then settles into a roughly 12% annual decline.
This shift toward higher-decline sources has already left its mark. The IEA estimates that annual base declines have risen by 1.5 mm b/d between 2010 and 2025. Less than half of that increase comes from the larger production base. The rest reflects the growing share of shale and offshore output—both of which decline sharply once past their peak. And even if shale slows, the continued dominance of offshore in new project approvals suggests overall base declines will keep drifting higher.
The report then tallies how much new supply would be required simply to offset base declines and keep global production flat. The figures are sobering. Under natural decline rates, output would fall nearly 60%—to about 42 mm b/d—over the next decade. Infill drilling on post-peak fields helps, adding roughly 10 mm b/d by 2035. Fields that are still ramping up contribute another 5 million, while already-approved but not-yet-developed projects add around 7 million. Unconventional oil—mostly shale—adds 18 mm b/d relative to a world with no new investment, as previously discussed.
Even after accounting for all of these identifiable sources, the report arrives at only 82 mm b/d of production in 2035. That leaves a 17-million-barrel-per-day gap that must be filled by new, yet-to-be-discovered fields. By 2050, the shortfall widens dramatically: the known cohort declines to 51 mm b/d, requiring 47 mm b/d from entirely undiscovered sources just to hold global production flat.
Herein lies the problem. Because a new conventional project can take close to twenty years from exploration to first oil, the industry would need to be exceptionally active now simply to balance supply by 2050. The IEA points to roughly 230 billion barrels of discovered but not-yet-approved resources. In theory, these could move more quickly than brand-new finds. In practice, they are expected to contribute only about 13 mm b/d by 2035 and 28 million by 2050. Even after drawing on this entire pool, the shortfall remains large: a gap of 4 mm b/d in 2035 and 19 million by 2050—just to keep production flat.
This leads to three major problems. First, even if substantial new projects were discovered today, they would almost certainly not deliver first oil by 2035, implying at least a decade of structural deficits. Second, the IEA’s own math underscores the challenge: adding 19 mm b/d of new supply by 2050 would require discovering roughly 10 billion barrels of new resource each year—about 25% more than the average annual discovery rate since 2020. Third, if demand truly rises to 120 mm b/d by 2050, the world will need an additional 20 mm b/d beyond merely holding production flat. Meeting that requirement would call for roughly 8 billion barrels of fresh discoveries per year, beginning immediately. All of this would demand a massive increase in exploration spending at a moment when most oil companies are still cutting back.
The likely outcome is a prolonged period of tight supply, with a growing share of the market shifting back toward OPEC+. History offers a clear pattern: whenever OPEC’s market share rises, so does its pricing power. Taken together, these dynamics point toward a future in which oil prices are not just higher, but structurally higher.
Taken together, the two IEA reports—along with the clear rollover in the Permian—reinforce our conviction that we are on the right path. More intriguingly, they may hint at a broader shift in the IEA’s long-term perspective. For the better part of twenty-five years, the agency has maintained a consistently bearish view of oil. Any softening of that stance would come as a surprise to a market that has grown accustomed to hearing the same refrain.
If the long-term picture now looks so constructive, why do investors remain so pessimistic? The answer lies in the IEA’s short-term Oil Market Report, which models balances through 2026. In its latest edition, the agency argues that today’s market is in a deep surplus—one that will supposedly worsen next year. According to the report, the current glut rivals the excess seen during COVID, and the coming year’s surplus may be even larger.
We see it differently. The issue comes down to the so-called “missing barrels.” As we’ve noted before, every barrel of oil produced must either be consumed or placed into storage. Yet in the first three quarters of the year, the IEA estimates that global production exceeded consumption by 2 mm b/d—while inventories rose by only about 400,000 b/d. The remaining 1.6 mm b/d simply disappear in their accounting. We refer to these, only half in jest, as the “missing barrels”—oil that was produced, but neither consumed nor stored according to the data.
There are only three possibilities: inventories are being measured incorrectly, supply is overstated, or demand is understated. Historically, it has almost always been the third. Inventory levels are directly observable, and supply numbers are tied to tax and royalty reporting, leaving demand as the usual culprit. We believe that is the case again—global demand is being significantly undercounted.
To be fair, this year’s data is somewhat skewed by an increase in oil aboard tankers. Some analysts have suggested that even more crude is “on the water” than reported, implying a quiet return of floating storage. We think the explanation is far simpler. As OPEC+ raised production, the volume of oil in transit naturally rose as well—much like the oil required to fill a new pipeline when it first comes online. We track every tanker loading and discharge globally and see no evidence that vessels are being used as floating storage. The market has been in mild backwardation besides, eliminating any economic incentive for traders to store oil at sea.
Even after adjusting for the additional oil in transit, the “missing barrel” discrepancy still exceeds 1 mm b/d so far in 2026. And there is no sign the gap is closing. The IEA maintains that the surplus will widen further in the fourth quarter. Yet real-time data tells a different story. U.S. inventories—which represent nearly half of all global commercial storage—have risen by only about 200,000 b/d above seasonal norms over the past two months, down sharply from the roughly 800,000 b/d of excess builds seen earlier in the year. The supposed glut is shrinking, not expanding.
According to the IEA’s headline numbers, global demand rose by 800,000 b/d year-on-year in the third quarter to reach 105 mm b/d. But if the “missing barrels” are, as history suggests, really uncounted consumption, then adjusted demand did not rise by 800,000 b/d—it rose by roughly 2.2 mm b/d to reach 106.4 m. b/d. The gap between the reported figure and the implied one is striking.
This has major implications for 2026. Based on the IEA’s headline figures, demand is expected to grow another 800,000 b/d between the third quarter of 2025 and the third quarter of 2026, reaching 105.7 mm b/d. However, if you believe that demand is actually currently 106.4 mm b/d (as we do), and that it continues to grow by its present 2 mm b/d year-on-year, then it could actually reach 108.4 m b/d by the third quarter of next year – some 2.7 mm b/d higher than the IEA’s expectations. Even with these adjustments, the market may still show a surplus next year—but a far smaller one than the IEA portrays.
There are also meaningful risks on the supply side, particularly in the U.S., Russia, and Saudi Arabia. The IEA assumes U.S. production will hold flat through the third quarter of 2026; we think it could just as easily decline by 200,000 b/d. Russia is similarly projected to remain steady at 9.3 mm b/d, though ongoing depletion issues and restricted oil-service support make that number far from assured.
Saudi Arabia remains the real wildcard. The IEA expects the Kingdom to average 10.1 mm b/d next year, a figure we consider optimistic. We have written extensively about the growing strain on Saudi Arabia’s supergiant fields, and our analysis suggests the Kingdom struggles to sustain 10 mm b/d without risking long-term reservoir damage. Historically, whenever production has pushed above that level, it has been accompanied by draws on inventories and then followed by pronounced cutbacks to rest the fields. It is too early to make firm predictions, but we would not be surprised if Saudi Arabia announces an unanticipated reduction in output sometime within the next twelve months.
Thus, while the prevailing view—shaped largely by the IEA and echoed by Doomberg— insists that oil markets are drowning in the worst surplus in history, soon to worsen and then slide into terminal decline, our reading of the data points in a very different direction. We see a market that has weathered an unexpected 2-million-barrel-per-day surge from OPEC+ remarkably well, that sits in only a slight surplus today, and that could tip back into a modest deficit by this time next year. Furthermore, the past two years have seen the majority of easily mobilized production vanish – first it was the drilled-but-uncompleted wells in the shales and now it is OPEC+ spare capacity. This leaves very little buffer in near-term oil production.
Beyond that, the fundamentals become even more compelling, driven by rising base-decline rates and steady demand growth—precisely as the only major source of non-OPEC+ supply this decade rolls over.
The great irony of markets is that turning points always look least convincing just before they happen. The data are debated, the narratives feel entrenched, and the consensus leans all to one side—until the floor shifts beneath it. Every great oil cycle ends the same way: with certainty giving way to surprise. The last time investors were this confident in a glut, the market doubled before they understood what had happened. Today’s setup is even tighter. We have acted on that reality. Others will move later—when the price has already rewritten the narrative.
Curious to learn more now? Read more in our Q3 2025 research newsletter, available for download below.
Registration with the SEC should not be construed as an endorsement or an indicator of investment skill, acumen or experience. Investments in securities are not insured, protected or guaranteed and may result in loss of income and/or principal. Historical performance is not indicative of any specific investment or future results. Investment process, strategies, philosophies, portfolio composition and allocations, security selection criteria and other parameters are current as of the date indicated and are subject to change without prior notice. This communication is distributed for informational purposes, and it is not to be construed as an offer, solicitation, recommendation, or endorsement of any particular security, products, or services. Nothing in this communication is intended to be or should be construed as individualized investment advice. All content is of a general nature and solely for educational, informational and illustrative purposes. This communication may include opinions and forward-looking statements. All statements other than statements of historical fact are opinions and/or forward-looking statements (including words such as “believe,” “estimate,” “anticipate,” “may,” “will,” “should,” and “expect”). Although we believe that the beliefs and expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such beliefs and expectations will prove to be correct. Various factors could cause actual results or performance to differ materially from those discussed in such forward-looking statements. All expressions of opinion are subject to change. You are cautioned not to place undue reliance on these forward-looking statements. Any dated information is published as of its date only. Dated and forward-looking statements speak only as of the date on which they are made. We undertake no obligation to update publicly or revise any dated or forward-looking statements. Any references to outside data, opinions or content are listed for informational purposes only and have not been independently verified for accuracy by the Adviser. Third-party views, opinions or forecasts do not necessarily reflect those of the Adviser or its employees. Unless stated otherwise, any mention of specific securities or investments is for illustrative purposes only. Adviser’s clients may or may not hold the securities discussed in their portfolios. Adviser makes no representations that any of the securities discussed have been or will be profitable. Indices are not available for direct investment. Their performance does not reflect the expenses associated with the management of an actual portfolio.