Energy Prospectus

Natural Resource Market Overview 1Q2021 by Goehring & Rozencwajg
Natural Resource Market Commentary 5-20-2021

Global commodity markets in 1Q21 continued to show significant strength. Despite
surging COVID-19 cases and bleak press coverage, commodity prices continue to suggest
strong economic growth lies ahead. Successful vaccine rollouts — more successfully in
the US, Britain, and Israel, less successfully in Europe and Canada — point to a strong
rebound in global travel and economic activity as the global economy reopens. Commodity
prices as measured by the Goldman Sachs Commodity index, which has a very high
energy weighting, rose 14% in 1Q21. Since bottoming at the end of April last year, the
index has advanced over 100%. The Rogers International Commodity Index, which has
a large agricultural exposure, rose 11% during the quarter. Since April 2020, the Roger’s
commodity index has advanced almost 75%.

Natural resource equities also showed considerable strength in 1Q21. The S&P North
American Natural Resource Sector index, which has significant exposure to energy, rose
over 19% during the quarter. Since bottoming March 2020, the index has advanced 110%.
The S&P Global Natural Resource index, which has more international mining and
agricultural exposure, rose 12% during the quarter. Since it bottomed in March 2020, it
too has advanced over 100%. For comparison purposes, the S&P 500 Index rose 5.8%
during 1Q21.

Commodities with the greatest perceived economic sensitivity (oil and copper) continue
to lead the market. Oil rose a significant 20% during the quarter and has now recovered
all its COVID-19 losses. The oil market has slipped into a severe structural deficit. Oil
prices are headed much higher and investors should maintain significant exposure to oil
related investments. Please see the oil section of this letter for an in-depth discussion
regarding supply and demand.

Copper rose 17% and now sits 50% over its pre-COVID 19 highs. Copper continues to
lead the bull market in base metals and is the first and thus far only commodity to have
made a new cycle high. Copper is also the only base metal to approach its all-time high
reached in 1Q2011. Copper reached $4.35 back in February 2021, within 6% of its
all-time peak of $4.65 set in 2011.

Grain prices were again strong in 1Q21. Corn prices, driven by continued large buying
of both feed corn and ethanol by the Chinese, rose 17%. Soybeans rose 9% and wheat,
in response to better global weather conditions, declined 3%. As we wrote last quarter,
we believe 2021 could potentially see the beginnings of a global agricultural crisis. Global
grain markets will continue to see continued tightening as the northern hemisphere
planting, growing, and harvest season progresses. The United States Department of
Agriculture (USDA) just released its 2021 US farmers’ planting intention report. It was
a shocker: US farmers now plan to plant almost 5 mm fewer corn and soybean acres
versus the most recent surveys. We remain very bullish on global agricultural markets
and recommend investors have significant exposure.

Natural gas prices rose only slightly (2.8%) in 1Q21. The natural gas withdrawal season
started off with extremely warm weather in both November and December. Weather
turned much colder in January and February and, except for the record cold outbreak
that gripped Texas and the South, the rest of the US never experienced a severe cold
outbreak. March also saw the return of warmer than normal weather. Overall, the US
winter was approximately 5% warmer than normal. As the 2021 withdrawal season
started, US natural gas inventories stood almost 7% above normal; however, strong LNG
and Mexican pipeline demand, coupled with weak supply, brought inventories back to
normal levels even in the face of warmer than normal winter temperatures.

Precious metals were mixed during the quarter. Gold prices declined 10% and silver
prices fell 7%. Platinum prices, pushed by the continued high level of interest in hydrogen
fuel cells, rose 10% while palladium continued its 5-year bull market run, rising 7%.

What a Difference a Year Makes (in Oil)
Exactly one year after West Texas Intermediate crude reached its historic -$37 per barrel
low, the damage inflicted on global oil markets from the COVID-19 economic lockdowns
has been largely repaired. Inventories have drawn down at the fastest rate on record and
in a mere 12 months nearly all excess crude inventories have been eliminated. Prices are
once again in excess of $60 and Brent nearly topped $70 per barrel in mid-March.

Exploration and production equities (as measured by the XOP) have led the broad market
higher, advancing 145% since the beginning of April 2020.

In the midst of last year’s turmoil we released a podcast on March 10th 2020 discussing
the severe volatility and weakness in global crude markets. We explained how falling
productivity in the shales would cause the market to recover much faster than anyone
expected. We advocated investors maintain or add to their energy exposure, an extremely
bold call at the time. As with any prediction, we got some elements right and others
wrong, but on balance we were correct. Not only has the oil market rebounded sharply
over the past 12 months, but the drivers of the recovery have been consistent with our
analysis. We bring this up because those same models which predicted the big oil price
rebound last year continue to point to extreme tightness as we progress throughout 2021.

Global oil markets are firmly in deficit, as evidenced by rising prices, falling inventories,
and growing backwardation. After having peaked in June 2020 at nearly 400 mm bbl
above average, OECD inventories have drawn by 250 mm bbl relative to seasonal averages,
suggesting the market has been 1.2 m b/d in deficit — the highest reading on record. We
expect this deficit will grow as we progress through the year. Inventory data in the US
shows continued draws relative to seasonal averages in March and April, albeit at a slower
rate. We should point out however, that extreme weather in Texas impacted production,
demand, and net imports leaving the data difficult to analyze properly. With the Texas
weather disruptions behind us, we expect US inventories will again resume their sharp
moves lower, and the most recent data confirms our analysis. Last summer we predicted
record high inventory levels would be fully drawn-down as soon as 2Q21and that prediction
now looks to have been accurate. We currently expect both excess OECD and US
inventories to be completely worked off by late May — far sooner than anyone thought
possible. < As I have been telling you in my weekly podcasts, falling OECD inventories are the primary driver of oil prices.

Reflecting the improved inventory situation, both the WTI and Brent market has gone
from an extremely high $15–20 per barrel 12-month contango last April to a $4 backwardation
today. Remember, a backwardated market (where future prices are below spot
prices) is indicative of tight physical supplies where traders are willing to pay a premium
for prompt delivery.

Throughout the past year, we explained why US shale production would be much slower
to recover this cycle because of widespread depletion problems. US shale represented
nearly all non-OPEC+ production growth last decade so any disappointments in US
shale production would have immediate and far reaching impacts on global oil balances.
Shale production collapsed last year as companies actively shut-in producing wells (an
industry first) and largely stopped drilling new wells. Shut-in production returned to
the market last fall causing supply to temporarily rebound; however, we argued this would
be short-lived — and it was. By the end of the year, all the shut-in production had been
returned, yet shale supply was still down 1.4 m b/d year-on-year — the biggest decline
in shale history.

In past cycles, shale production rebounded quickly because the industry had ample “core”
locations left to drill. As prices fell, companies would focus all their activity on these best
areas causing productivity to surge, largely offsetting the slowdown in overall activity. In
multiple letters last year, we explained in great detail how the industry had nearly exhausted
its inventory of core acreage, and we predicted how difficult it would be for E&P companies
to boost productivity and production through additional high-grading. Our neural
network told us that the E&P industry would not be able to offset lower activity with
higher productivity. This important and fundamental shift — the first time in shale
history — was missed by most analysts. Our neural network told us that shale productivity
was largely flat in all three major basins (Permian, Eagle Ford, and Bakken), despite
an incredible 80% reduction in 2020 drilling activity. In previous drilling downturns —
2008–2009 and 2014–2015 — drilling productivity soared as companies had ample
inventories of top-tier prospects left to drill. In this drilling downturn, an 80% drilling
drop with no corresponding increase in productivity is proof that you are near exhaustion
in your inventory of top-tier drilling locations — a fact confirmed by our neural
network.

We have entered a new era in global oil markets. The only source of non-OPEC+ growth
over the past decade is now suffering signs of sustained depletion. Most analysts believe
the shales will exhibit strong growth again when oil prices recover; however, our research
tells us that growth from the shales will fall far below expectations in the first half of
this decade.

Non-OPEC+ production outside of the US is equally challenged. In their most recent
report, the IEA reports that non-OPEC+ production outside of the US was down
500,000 b/d in March compared with a year earlier. The IEA projects production from
this group will grow throughout the year and that by 4Q21 supply will be 700,000 b/d
higher than a year earlier. We disagree with this assessment and expect production will
fall short by as much as 400,000 b/d, if not more. Exploration outside of the shales has
been extremely disappointing over the past decade and new project sanctions have barely
been able to replace base declines. Given the capital budget curtailments around the
world, we expect non-OPEC+ production outside of the US will continue to disappoint
going forward.

Meanwhile, demand is normalizing following the COVID-19 disruptions last year.
Although global demand remained 5 mm b/d below its pre-COVID level in 1Q21, it
continues to trend in the right direction. Notably, demand has remained intact despite
a second wave of infections and global lockdowns following the Christmas season — a
lockdown that still continues in many parts of the world. Jet fuel continues to be the
weakest source of demand as international travel remains subdued, although increased
freight volumes have helped to offset some of the decline.

Several countries have now either regained or surpassed pre-COVID demand levels. In
1Q21, Chinese demand was likely 1.4 m b/d higher than the same period in 2019. Indian
demand was likely within 10,000 b/d of its pre-COVID record as well. Therefore, the
two largest sources of demand growth in recent years are now back to their pre-COVID
levels. Surging Indian case data suggests demand may be impacted in 2Q21, but never-
theless the latent demand in the underlying economy appears very strong. This is exactly
what we predicted would occur as a direct result of the S-curve. As we have explained in
the past, when a country reaches a certain level of per-capita real GDP, their commodity
intensity begins to move up dramatically. China and India are both firmly in their S-curve
sweet spots and so it is no surprise they are the two countries that are most quickly
regaining their pre-COVID demand peaks.

As the COVID-19 vaccination distribution continues to accelerate globally, we believe
demand will rebound very sharply from here. Indications point to substantial pent-up
demand for both leisure and business travel once restrictions are lifted. Government
policies meanwhile have left savings rates at all-time highs.

Looking forward through the rest of this year, we believe oil market deficits will accelerate,
causing inventories to plummet. The IEA currently estimates demand will average
97.6 mm b/d for the remainder of the year. To the extent global vaccine distribution
accelerates, we believe this figure could be too low by as much as 1.5 mm b/d. Non-OPEC+
production is expected to grow by 1.8 mm b/d, driven by nearly 1 mm b/d of growth
from the US shales. We simply do not believe this is likely given our modeling of core
exhaustion and productivity trends. Instead of growing by nearly 1 mm b/d from here,
we believe total US production will continue to fall by as much as 400,000 b/d. Based
on their figures, the IEA expects the call on OPEC+ to average 44.6 mm b/d for the rest
of the year compared with actual production of 41.3 m b/d in April.

Assuming OPEC+ returns production according to their recently announced schedule,
the IEA expects the market to remain in deficit by 1 m b/d for the remainder the year.
Making the adjustments we described (increasing demand and decreasing US shale
output), we believe the deficit will exceed 3.5 m b/d, causing inventories to approach
record low levels. If our models continue to be correct, global oil markets should remain
in deficit even if OPEC+ returns to producing at its all-time high levels. < If G&R prove to be correct, WTI may go to $100/bbl within a year.

As our readers know, we favor those companies with high-quality assets and sensible
balance sheets that trade at favorable valuations. These companies should continue to
generate material value as the cycle progresses. One metric we like to use is proved reserves
per net debt adjusted share. If a company has high quality assets, it should be able to
grow its proved reserves per share; adjusting for net debt helps account for capital discipline.
Looking at the universe of US E&P companies, we estimate the market-cap weighted
group saw proved reserves per net debt adjusted share fall by 6% for the second consecutive
year. Proved developed reserves (leaving aside future undrilled locations) fell by
4%. Our position-weighted average group of companies on the other hand were able to
grow proved reserves by 3% and proved developed reserves by 8%. We believe this is a
quick way of confirming that we continue to identify the best remaining assets in the US
shale basins.

We are entering into a new era in global oil markets. While most analysts are concerned
about demand, the most important driver will likely be supply. After a decade of robust
growth, the US shales are now exhausted and incremental growth will be very difficult
to achieve. Two decades ago, investors worried we were running out of oil while today’s
investor worries that we have passed peak demand. Although we cannot say for certain
what the coming decade will bring, it will almost certainly defy conventional expectation.

The US shales have been an extremely prolific source of supply but we firmly believe
their best days are behind them. As this realization sinks in, we believe investors will
focus on those companies with the remaining high-quality assets. We recommend investors
maintain sizable investments in high quality E&P and oil service companies with a
sizable earnings leverage to higher oil prices.

G&R's take on U.S. Natural Gas Market

Gas Getting More and More Bullish

Natural gas prices were flat during 1Q21. Weather was a near-constant negative headwind
in North American natural gas markets this winter. November and December were
much warmer than normal while January was near normal and March was 10% milder
than normal. Only February was colder than normal by 15%, but this was not enough
to offset the other months. Overall the 2020–2021 withdrawal season was 5% warmer
than 10-year averages.

Despite the mild winter, storage withdrawals were higher than average. US inventories
started the withdrawal season 200 bcf (or 5%) above 10-year averages before working
off nearly all of this excess by the beginning of the injection season. Inventories finished
the winter season only slightly above average.

US natural gas supply continues to show limited growth. Production over the last four
quarters averaging 91.2 bcf/d, down 5.6% year-on-year. Although January production
was up 1.3 bcf/d compared with Q4, it remained 2.6 bcf (or 3%) below the same period
last year.

Production estimates from the Energy Information Agency’s (EIA) April Drilling
Productivity Report suggests no growth through at least May.

The US natural gas rig count remains far below the level needed to keep production flat,
let alone grow. After having peaked at 200 rigs in February 2020, the US natural gas rig
count fell to 68 rigs in July before rebounding to 94 rigs today. Our models suggest today’s
activity levels are still too low to offset base declines, resulting in continued declines.
Notably, activity remains subdued in the Marcellus. Over the last 10 years, the Marcellus
has been the driving force behind surging US natural gas supply. From almost zero production
in 2010, the Marcellus produces almost 30% of US gas supply today.

In previous letters, we discussed how the Marcellus and Haynesville were rapidly reaching
a point where production would plateau and begin to decline. According to our neural
network, both plays were reaching the same geological challenges faced previously by
the Barnett and the Fayetteville, immediately before they plateaued and started declining.
Barnett production grew rapidly in the early 2000s. Production unexpectedly plateaued
in 2013 and peaked at almost 5.5 bcf/d in 2015 before entering into a persistent decline.
Production from the Barnett is now only 2.3 bcf per day, almost 60% below its peak. In
the case of the Fayetteville, production ramped up sharply in 2007, began plateauing in
2012, peaked at almost 3 bcf per day in 2013, and then began its steep decline. Presently,
Fayetteville production averages 1 bcf/d — 65% below its peak.

What caused the plateau and then steady declines in both plays? According to our neural
network, drilling productivity plateaus once 40% of tier 1 locations in a play have been
dilled. Productivity begins to fall once 60% of tier 1 locations have been drilled. In the
case of the Barnett, 40% and 60% of tier 1 prospects were drilled in 2013 and 2015,
respectively. By 2015, production in the Barnett peaked and began a persistent decline.
In the case of the Fayetteville, 40% and 60% of tier 1 prospects were drilled by 2012 and
2014, respectively. Production in the Fayetteville began to peak in 2011 and by the end
of 2014 production began its steep decline.

Our neural network tells us that 60% of tier 1 Haynesville wells have now been developed
and 40% of tier 1 Marcellus locations have been drilled. If our analysis is correct,
the Haynesville will begin to experience chronic declines soon while Marcellus production
will begin to plateau. By 2023, we estimate 60% of the tier 1 Marcellus locations
will have been developed and production will fall.

The Haynesville plateaued in the beginning of 2019 and production has since been flat.
Likewise, Marcellus production stopped growing in mid-2019 and has also been flat since.
The Marcellus rig count peaked in 1Q19at 68 rigs, just as production began to plateau.
Even before the COVID-19 lockdown took hold, the rig count in the Marcellus had
declined by 40% to 40 rigs. Marcellus rigs collapsed to 24 last September during the
worst of the COVID-19-related economic dislocations. Today it has only rebounded
modestly to 29 rigs.

Production in the Marcellus stopped growing with close to 70 rigs drilling for natural gas.
With only 29 rigs operating, production will soon begin to decline. Our neural network
puts forth strong evidence why the Marcellus has seen such rig count weakness. At the beginning
of 2019, 40% of tier 1 drilling locations had been drilled. Today that figure stands close
to 50%. We believe the weakness in Marcellus drilling activity strongly reflects the dwindling
number of Tier 1 locations left to drill.

A similar pattern has emerged in the Haynesville. The rig count in the Haynesville peaked
in Q1 of 2019 at 58 rigs just as production began to plateau. The rig count then fell 27% to
42 rigs before COVID hit. During the worst of the pandemic, 31 rigs were drilling in
the Haynesville.
Since then the Haynesville rig count has rebounded to only 45 — still almost 35% below
its 2019 peak.

Our neural network tells us that nearly 60% of tier 1 wells have now been drilled in the
Haynesville and, just as in the Marcellus, we believe the weakness in the Haynesville rig
count reflects the dwindling number of tier 1 well locations left to drill.

The importance of the Marcellus and Haynesville gas play cannot be overstated. Since 2006,
US natural gas production has grown 90% and the Marcellus and Haynesville represent
over 75% of this growth.

The severe production declines in both the Barnett and Fayetteville shale gas fields clearly
show what happens when top-tier drilling locations become exhausted: field production
begins to decline. The process is about to grip both the Marcellus and Haynesville shale gas
fields, with huge bullish implications for US natural gas prices.

Overall demand for US natural gas remains strong. Gas demand for US LNG exports
continues to rise. Aided by the commissioning of Cheniere’s Corpus Christi Train 3, natural
gas feedstock demand has now reached 11.5 bcf /day, up nearly 25% year-over-year. With
that, US export capacity has now reached 10.8 mm bcf /day. Given the strength of global
LNG demand, we expect to see close to 10 bcf per day of LNG exports in 2021, up 50%
from last year’s COVID-19 impacted levels. < So far, LNG exports have been over 11 bcfpd in 2021.

Natural gas pipeline exports to Mexico continue to rise sharply. The recent completion of
two new pipelines and the expansion of an important compression station has caused US
gas exports to Mexico to reach a new record of 7.7 bcf per day, up nearly 50% from a year
ago. Also, the completion of the Tula-Villa de Reyes pipeline, scheduled for later this year,
will add almost an additional 1 bcf /day of export capacity to Mexico.

The great bear market in gas over the past 13 years was caused by surging supply. Our research
tells us that natural gas supply growth in the US will slow dramatically, if not turn negative,
in the next several years. At the same time, domestic and export demand for US natural gas
continues to grow. The bull market in natural gas has begun with little attention from the
press. We recommend investors own a diversified portfolio of natural gas-related equities.
Valuations are very low and natural gas prices are going much higher.