DEP Update:  Happy New Year!  An early release today as we will soon depart North Carolina to return to Houston.  Kicking off this weekend’s note is our first Ruminations piece by our newest team member, Bill Herbert.  This, in our humble opinion, is a good macro thought piece as it helps frame some of the most salient issues confronting the upstream energy complex.  Yes, today’s Sunday note is unusually long as there is so much to digest on the macro front, but don’t worry, our DEP macro deep dives will be twice a year with normal notes having more abbreviated, but equally important, macro thoughts.  In terms of travel, we are in Houston this week for local meetings as well as for Thrive Energy Conference planning.  We are now shamefully in full blown solicitation mode for conference sponsors – please don’t be offended if we contact you at some point this week.  Lastly, we’ll be heading to Midland on January 9-12th for meetings and site tours.  Building out the schedule now, but if you are open to letting DEP stop by, let us know.


Energy Ruminations (author Bill Herbert – Summary:  The complexity factor for energy has never been higher. Contrary to the free-market mythology of domestic energy, governments increasingly have the upper hand in determining energy outcomes. Geopolitical threats have become acute and seemingly durable, energy security has become the indispensable virtue, globalization is dead, energy supply chains are being radically reordered, the need for sustained, strategic reinvestment has never been higher, and markets continue to be astonishingly febrile and volatile. Given these crosscurrents, energy prognosticating continues to yield both hubris and humility, seemingly for bull and bear alike, depending on the point in time.


The “energy transition” is in its incipient stages and, in substance, goes well beyond the hand-off from fossil fuels to renewables.  Yes, the aspiration is for a considerably greater contribution from low-carbon sources of energy, but today’s geopolitical realities also require refortified energy security and reliability emanating from fossil fuels (as well as nuclear).  This more holistic definition of “energy transition” will be all-encompassing, require long lead-times and sustained reinvestment, and will be expensive and inflationary.


US oil inventories (including SPR) are ~30% below pre-pandemic average levels. YTD, US SPR emergency inventories have compressed by ~35% and are down 45-50% from the peak of 2010 and hovering at the lowest levels since the mid-1980s. Total OECD oil and product inventories (including government stocks) are down ~10% vs. pre-pandemic levels. This is the jarring reality confronting the Western Democratic alliance in an increasingly perilous geopolitical world and capacity constrained energy ecosystem. And this is the fulcrum of the duration narrative for energy reinvestment.


While the conventional energy industry is transitioning from marginalized to critical, the energy weighting of the S&P 500 is too low.  Although the current S&P weighting of 5.1% has more than doubled from its recent nadir of less than 2%, it is at the low-end of the normalized range (and the relatively recent peak of ~16%) that prevailed for most of this century prior to the recent pre-pandemic marginalization of conventional energy.


Near-term, the environment is fluid, volatile and muddled. Market balances over the course of this year, will be shaped by a myriad of inputs and outcomes but the most prominent demand swing factor, by far, is China and its attempted “normalization” from Covid dystopia. And, on this front, the range of outcomes is perhaps wider than the Wall Street consensus appreciates. Although the Chinese leadership has recently displayed considerably increased resolve in emerging from Covid purgatory, and has announced the dismantling of quarantine requirements and downgraded the management of Covid from a Class A to Class B infectious disease (downshifting from draconian controls and oversight to basic treatment/prevention), the government is “battling a severe winter outbreak with estimated cases spiraling into the hundreds of millions and health services under pressure.” (FT). When and how this contagion abates, and an ensuing “normalization” unfolds remain prominent unknowns. The hope is that China’s policy shift will propel the country to a more robust economic recovery, notwithstanding current dislocations.


In addition to China, key unknowns include the depth and duration of OECD (and beyond) recessionary outcomes, should they come to pass, and the forward path for Russian oil supply. Currently the IEA and OPEC are assuming aspirational OECD oil demand growth (~330-390 KBD) for 2023 – possible but certainly debatable. Moreover, they are also assuming non-trivial dislocations and declines in Russian oil production (~850 KBD-1.4 MBD), – again, possible but debatable.


Given the prevalence of abundant prominent unknowns, volatility will remain acute and constant.


The following is a compilation of a dozen considerations and issues (preceded by brief thoughts on energy stocks) which encompass near-term as well as longer-term opportunities, threats and complexities confronting the energy industry.


Stocks, Positioning, Briefly Considered (sources: Bloomberg).  While the conventional energy industry is transitioning from marginalized to critical, the energy weighting of the S&P 500 is too low given the imperative of energy security.  Although the current S&P weighting of 5.1% has more than doubled from its recent nadir of less than 2%, it is at the low-end of the normalized range (and the relatively recent peak of ~16%) that prevailed for most of this century prior to the recent pre-pandemic marginalization of conventional energy. The challenge for investors who avoided energy is establishing an energy position following two years of incandescent returns. At this stage, energy isn’t undiscovered. The risk, if one continues to avoid energy, is enduring yet another year of meaningful energy outperformance. The long-term set-up is favorable due to the acute need for sustained reinvestment and the SPX energy weighting, over time, should continue to bend higher. The near-term, however, has several prominent wildcards that can materially influence near-term outcomes and sentiment. Can conventional energy outperform without help from oil prices? Last year, oil prices were flat-to-up, with incessant and frenzied volatility, while the XLE vaulted 50-55% (down ~5-10% from the recent November peak, up ~20-25% from the September low and down ~5-10% from the June apex – not for the faint of heart). Thus, the answer appears to be “yes,” but stocks won’t do well (yield compelling absolute returns) in the event global oil demand continues to stagnate (Q4 demand flat-to-down y/y) and oil prices are continually under pressure and the key wildcard is China (more below).  Valuations, on consensus estimates look reasonable to attractive with large cap refiners trading at low-teens FCF yields, US majors and best-of-breed E&Ps trading at low-double digit and large cap OFS trading at mid-to-high. A challenge for domestic E&Ps, and an opportunity for domestic OFS, is, perhaps, greater-than-modeled well-cost inflation. Finally, there is some oil price support in the form of a US SPR replenishment tripwire and continued rational guardianship on the part of Saudi/UAE.


While energy stocks are recapturing relevance, the commodity markets are suffering from “broken liquidity” given incessant volatility. Close to $130B has exited the global commodities trading market over the past year, according to JPM (recently reported by Bloomberg). Following the first two months of inflows, capital exited the market over the past year due to paranormal volatility arising from Russia’s invasion of Ukraine and increasing concerns about the macroeconomic outlook. Clearing houses have been raising collateral requirements while interest rates have markedly increased borrowing costs. While most expect positions to enlarge this year, capital will likely continue to stay on the sidelines as long as volatility remains acute.


A recurring question is “what happens should the Russian assault on Ukraine abate and negotiations begin in earnest?” Media outlets reported on Xmas that Putin expressed a willingness to negotiate over the invasion of Ukraine, which was greeted with well-justified derision. In a predictable follow-up, Russian Foreign Minister fulminated that Ukraine must demilitarize, while Ukraine rejoined that Russia needs to face reality. Russian scholar, Stephen Kotkin, prophetically expressed, in the early days of the conflict, that “the problem…is how to deescalate, how to get out of the spiral of mutual maximalism.” Notwithstanding the seemingly long odds of a desirable outcome, were a durable cease-fire to be declared, our guess is that the geopolitical risk premium would dissipate, oil would gap lower (but for how long?), risk assets would rally, the global economic outlook would improve and, soon enough, the need for continued and sustained reinvestment and refortification of security and reliability of supply would reassert itself.  


Brief Observations on Market Balances (sources: IEA, OPEC, IMF, Bloomberg, WaPo).  According to the IEA, global inventories, hovering at 5-yr lows, have remained roughly flat for several months as the market heads into a period of acute uncertainty with the commencement of the EU Maritime Services Ban and the G7/Australia price cap. Global observed inventories contracted by 23 million barrels (mb) in October, with crude stocks rising by ~6 mb (three consecutive months of builds) and products contracting by ~29 mb (first decline since March).


Leading-edge domestic weekly inventory data has been mixed with the latest batch having a high noise-to-signal ratio given weather disruptions, which is likely to be the case for the next few weeks of data releases given the aftermath of the recent storms. Accordingly, our commentary relates to trends preceding this week’s EIA data. Recent product builds have been prodigious, with gasoline stocks rising for a 6th consecutive week and diesel five of the last six weeks. Gasoline inventories have progressed (or devolved) from extreme deficit to now being only ~1.5% below the pre-pandemic 5-yr average (early-Oct the deficit was ~9%), and demand remains anemic, with the four-week trailing average ~8% below the pre-pandemic average. While diesel inventories are ~12% below the pre-pandemic 5-yr average (early-Oct the deficit was ~22%), demand is stagnating as the most recent trailing 4-week avg was ~5% below the pre-pandemic baseline. On the other hand, Crude inventories have drawn five out of the last six weeks (most recent week supported by substantially lower imports) and are now ~30% below the pre-pandemic 5-yr average. Refining utilization of less than 91% is running more than 200 bps below the pre-pandemic 5-yr average.


According to the IEA, OECD September oil demand increased 450 KBD y/y (largely due to jet fuel) but fell 540 KBD m/m.  Q4 OECD demand is projected to contract by 380 KBD y/y due to weak gasoline and petrochemical demand. On the other hand, non-OECD demand continues to be relatively resilient and expected to increase by ~270 KBD y/y in Q4 (Q3 +1 MBD y/y). All-in, however, global demand momentum slowed materially last year, decelerating from almost 5 MBD of y/y growth (followed by 2.3 MBD and 1.9 MBD y/y expansions in Q2 and Q3, respectively) to a flat-to-down contraction in Q4 (OPEC MOMR flat-to-up). Thus, the demand outlook is fluid, muddled and bifurcated as we exit 2022.


For 2023, the IEA is projecting global demand growth of 1.7 MBD (vs. 2.3 in 2022) driven by 390 KBD of OECD demand growth (mostly S Korea and Canada – we’ll see – S Korea Nov exports fell 14% y/y) and 1.3 MBD of non-OECD expansion, of which 820 KBD is expected to be generated from China. OPEC is projecting ~2.2 MBD of demand growth this year (2022 ~2.6 MBD).


We question the assumptions driving OECD growth given the uncertain economic outlook and the crisis in Europe (IEA assumes ~100 KBD of European demand growth for 2023). Leading-edge demand in the US is worsening and the prospect of recession, while an unknown, looms as a growing probability. And, on this front, the Wall Street consensus leans shallow and benign – inflation has peaked, the undercurrent of disinflation is gaining pace, job market is resilient as is the consumer, “reshoring” is gaining impetus – all plausible. The challenge is that the opposite view is equally persuasive – perhaps inflation has peaked, but the slope of the normalization will be flatter than optimists contend, the Fed’s dual mandate will continue to disproportionately focus on inflation, deglobalization is inflationary, benchmark policy rates will be higher for longer, and the labor market, which is currently out of balance (job openings/unemployed ~1.7x), will need to loosen materially through a weakening economy and rising unemployment. Larry Summers recently observed that “all major reductions in inflation in the past 70 years have been associated with recessions. Historical experience demonstrates that whenever unemployment (current ~3.7%) rises by more than half a percent within a year, it goes onto rise by 2%. So, if recession comes it is very likely to lift unemployment to the 6% range.” And even with an exceptionally tight labor market, US gasoline demand has hardly been inspired. To use our repeated locution, there are a wide range of outcomes.


On the other hand, non-OECD, ex-China assumptions look reasonable given the ongoing energy prosperity in the Middle East and vitality/growth in India. China, however, is the pivotal swing factor and the demand outcome is largely contingent on the Covid drama (see more below under “China is the demand fulcrum”). As an FYI, Bloomberg recently reported that Taiwan’s November export orders “plummeted” by the most since 2009, falling by ~23% y/y (2x consensus estimates), and actual exports contracted by 13%. Orders for all major categories fell. That said, China Covid restrictions partly weighed on the result and a sustained reopening could have a positive effect on the supply chain. Thus, the multiplier effect of China on Asian economies and broader oil demand.


With respect to supply, the IEA is projecting ~2 MBD of non-OPEC ex-Russia production growth with 970 KBD generated from the US (and ~300 KBD from Brazil, ~270 KBD from Norway), which strikes us as optimistic based on cost-inflation and supply chain realities and continued steadfast capital discipline. It is also assuming ~1.4 MBD of Russian production contraction (OPEC MOMR projecting an 850 KBD contraction) – our guess, based on the production resilience and realities of the market last year (heavily discounted crude will eventually find a home), is that this could be too severe (see more below under “Embargoed Russian oil”). We’re all currently navigating through the fog of war.


Current (November) OPEC production is 28.8 MBD, down ~745 KBD m/m, according to OPEC secondary sources. The IEA’s projected call on 2023 OPEC production required to achieve inventory neutrality is ~29.9 MBD (OPEC MOMR ~29.2 MBD). If one assumes flattish as opposed to increasing OECD demand (still optimistic?), flat-to-down Russian oil production, and more modulated US production growth, the adjusted call is closer to ~28.5-29 MBD. This could easily be higher with vigorous China PUD (pent up demand) growth and meaningfully dislocated Russian production but it could also be lower based on inconvenient outcomes, not only as it relates to China but ROW economic growth and resilient Russian oil production and market penetration. Finally, many presume broader OPEC stability in the monthly production data, but this is too serene as Libyan and Iranian (more below under “Iranian convulsions and implications”) production, among other OPEC production sources, could easily be considerably lower depending on “events.” OPEC isn’t a case study in comforting and stable surplus production capacity.


China is the demand fulcrum for 2023 (sources: Bloomberg, OPEC MOMR, FT, WSJ).  The fulcrum of the near-term outlook is China and its emergence from Covid purgatory. China November oil imports, which have been ascendant since June, were up ~8.5% m/m and 12% y/y to 47.7 metric tons or 11.4 MBD. Imports have been strong over the past ~five months due, in part, to higher export quotas (oil product exports have almost doubled since June). Run rates for China state-owned refiners rose to ~78%, highest since March. But refinery runs are likely to weaken materially as maintenance is carried out and domestic demand weakens due to the Covid contagion.


The potential demand outcomes for China feel binary. A relatively seamless and sustained emergence from draconian lockdowns and Orwellian surveillance could yield a cathartic PUD recovery and tightening market balances for oil as well as the broader commodity complex. On the other hand, if it’s fitful, turbulent, and destabilizing, the economic and oil/commodity demand outlook will be fraught with uncertainty. Benchmark agency projections for China demand this year appear sensibly restrained/reasonable following the contraction of last year. In the latest OMR, the IEA projects a y/y demand contraction of ~420 KBD in 2022 and an expansion of ~820 KBD in 2023, with a ~400 KBD contraction in Q1 followed by 1.2-1.3 MBD PUD surge for each of Q2-Q4. The product demand growth buckets are ~evenly distributed between jet, diesel, LPG/ethane and naptha, with the presumption that PUD travel, renewed policy support for real estate and pet chem will be the main drivers of resurgence. In the latest MOMR, OPEC projects a demand contraction of ~200KBD for last year followed by an expansion of ~520 KBD for this year. The sell-side and energy commentariat have a more expansive view for 2023 Chinese oil demand growth, with the upper reaches ranging between 1 MBD to 3 MBD.


While professions from China’s political leadership portend resolve for “normalization,” leading-edge Covid developments are cause for some concern. In a recent WSJ column (China’s Let-It-Rip Reopening), public health authority Zeke Emanuel, expressed that China ended “zero Covid in the most dangerous way possible – precipitously.” The current contagion is unbridled, with Chinese health authorities reporting a current “R” (rate of spread – the average number of people to whom one infected patient spreads a pathogen) of 16 vs. 10 last winter (and 2-3 during SARS) when Omicron was running rampant. According to the FT, several models, including one funded by the Chinese CDC, have forecast that China could have up to 1M deaths during its attempted reopening. Notwithstanding, there is growing evidence that China is moving on from the untenable Zero Covid policy (electronic tracking, mandatory testing, severe lockdowns of neighborhoods/cities/regions), albeit in a brutally Darwinian fashion with an unfolding Covid “explosion.” Notwithstanding the “explosion,” the FT reported this past Wednesday that “Beijing’s streets are once again jammed with traffic, tourists are rushing to book foreign holidays and businesses anticipate a pick-up in activity as China’s economy reawakens…even as the country endures its worst outbreak of the pandemic.” Given the speed of the contagion, some expect the present fury to abate within the next few months.  Airline bookings have witnessed a step-change increase, with outbound flights from China jumping ~250% this past Tuesday morning (Bloomberg). “Pre-pandemic, China was the world’s largest source of outbound tourists, with 150M travelers going abroad each year,” according to McKinsey (FT). Media outlets reported that Italian health authorities will begin testing all arrivals from China after ~50% of the passengers on two flights to Milan were found to have Covid (thanks China). China recently announced that, as of January 8th, it is ending quarantines for international/inbound travelers, which is in stark contrast to the current requirement of 8 days of isolation, five of which are at a quarantine hotel.


Yes, the global economic outlook for ROW is relevant and the depth and the duration of a recessionary malaise will influence demand outcomes but, nonetheless, China will have disproportionate influence over the near-term (2023) demand trajectory. China is the most prominent demand wildcard for this year.


China longer-term outlook is fluid, if not opaque (sources: IEA, Ruchir Sharma, WSJ).  China is also at the forefront of longer-term opportunity and threats for oil. Over the most recent pre-pandemic decade, China accounted for ~40% of global oil demand growth. China’s ambition is to become a mid-level developed country in the next decade. According to Ruchir Sharma, this aspiration implies annualized economic growth of ~5%. Beyond the looming PUD recovery, however, China’s longer-term economic outlook is uncertain given its unenviable demographic profile (low birth rates, aging and stagnating population, working-age population decline since 2015), balance sheet (government and private sector debt ~275% of GDP) and challenged productivity (“brain drain” is ongoing, global enterprises are reconsidering their China exposure, increased role of the state doesn’t augur well for capital efficiency), which collectively portend normalized economic growth closer to 2.5%. According to Mr. Sharma, “the implications of China growing at 2.5% GDP have yet to be fully digested anywhere…” Assuming normalized growth of 1.5% for the US, Mr. Sharma contends that China won’t overtake the US as the world’s largest economy until 2060, “if ever.” Moreover, the WSJ reported that the Japan Center for Economic Research (JCER) recently updated its long-term nominal GDP forecast for China which no longer concludes that China’s economy will surpass the US’ by the end of the decade. The JCER now projects that China normalized GDP growth will decelerate to 2% (and possibly even lower in the 2030s) due to demography and weakening productivity and growing concerns about a “Taiwan contingency.”


India leads the world in oil demand growth (sources: IEA, IMF, FRED).  While China’s longer-term demand outlook, beyond the PUD recovery, isn’t encouraging, India, in recent quarters, has led the world in oil demand growth. India is now the world’s third largest oil consumer at 5 MBD (US ~20.3 MBD, China ~15; fourth if you count Europe at ~13.6). According to the IEA, India generated the fastest rate of absolute demand growth for each of Q2 and Q3, expanding by 670 KBD and of 410 KBD y/y, respectively. The IEA expects India’s best-in-class growth to continue in Q4 (+250 KBD) and Q1 (+170 KBD) before China’s PUD recovery hopefully commences in earnest. According to the IMF, India’s GDP was the strongest globally last year at 6.8% and vigorous growth is expected to persist next year with projected GDP growth of 6.1% in 2023 vs. the global average of 2.7%. High birth rates (17.4 births per 1,000 people vs. 8.5 for China, 10.9 for US and 9 for Europe), population growth and urbanization are expected to propel oil demand growth for the foreseeable future.


Governments now have the upper hand in determining energy outcomes.  Governments now have the upper hand in determining energy outcomes. China Covid policy, Russian revanchist aggression, G-7/Western Democratic Alliance oil price caps, US SPR depletion and replenishment, Saudi/UAE/Kuwaiti oil production policy and the recently enacted IRA bill in the US are, collectively, the primary drivers of energy outcomes. Europe’s CBAM (Carbon Border Adjustment Mechanism) will soon likely join the growing list of government drivers. As the FT recently observed, “Governments will remain the decisive actors in 2023.”


The need for energy realism and refortification of security and reliability of supply.  Over the intermediate and longer-term, energy security should be at the forefront of policy-making considerations. Former Defense Secretary Robert Gates, observed that the Russian invasion had ended “America’s 30-year holiday from history.”  Accordingly, the hackneyed “energy transition” label should be reconsidered not only to reflect the development of low-carbon sources of energy, but also encompass fortifying security and reliability of conventional energy supply. The world is in the early stages of “friendshoring,” “reshoring” and “onshoring” of global supply chains given crystallizing geopolitical realities. US crude inventories are currently ~30% below pre-pandemic average levels. “Normalizing” inventories and fortifying security of supply will require considerable lead-times, sustained capital investment and realism.


Diminishing deliverability (Super-Spiked, IEA, EIA, Bloomberg, Enverus FT).  Arjun Murti (COP board member) recently observed in his Super-Spike blog that the world is “essentially structurally short deliverable crude oil.” He goes on to emphasize the term deliverable as the world is “nowhere near the point of resource exhaustion.” He adds that “every ~20 or 30 years…demand outstrips supply and we have a new cycle. That is where we are today.” We would also add that the singularity of the moment also encompasses an amplified need for improved energy security and reliability. Estimated effective OPEC spare capacity (Saudi, UAE, Kuwait) is now hovering at ~2.6 MBD, or ~2.5% of global demand, which is caressing the low-end of the historic range. US upstream capital allocation has fundamentally changed from the pursuit of profligate growth to generating and distributing cash flow. There is incipient evidence that Permian inventory breadth and depth is becoming less generous as is well performance.  According to BloombergNEF (BNEF), wells drilled last year produced 8-13% less oil per lateral foot than a year earlier, representing the first major reversal following a decade of productivity gains. While the White House has exhorted the domestic E&P industry to reinvest rather than distribute cash flow, PXD CEO Scott Sheffield, in a recent FT interview, responded that were resource holders to acquiesce to these entreaties, the industry would self-immolate given the prolonged pre-pandemic legacy of generating abysmal ROCE. Sheffield added that the WH is failing to consider acute supply-chain challenges and occlusions and rampant well-cost inflation: “if we wanted to grow by more than 5%, I’d have to call up all the service contractors; they’re going to charge me 30-40% more; it’s going to take a year to build new equipment; it’s going to take two years to start showing results. By that time you go through an oil price collapse.” Sheffield contends that the WH’s ~$70/bbl price threshold to replenish the SPR was too low: “putting a floor of $70/bbl is no help for the producer…If they want to encourage additional activity, they will have to put a floor somewhere around $100/bbl – especially with significant increases in service costs.” Barring a resolution of the Ukrainian war and reintegration of Russia back into the community of nations, or regime change in Iran (more below), we don’t see a quick and seamless solution to the deliverability challenge.


SPR cathartic depletion is behind us, and the need to Replenish is at hand (sources: EIA, FT).  At the beginning of last year, the SPR (Petroleum Reserve) held ~593M barrels of oil. Following the Biden Administration’s announced drawdowns of 180M barrels last year, which was the largest release of US emergency inventory, the SPR has winnowed to ~379M barrels (down ~35% from early-2022 and ~45-50% from the 2009 peak), representing the lowest level since the mid-1980s. The Biden Administration announced late last year its intent to begin replenishing the SPR at a ~$70/bbl or lower threshold. The average monetization price of SPR inventory last year was ~$96/bbl. The DOE recently announced that it would start repurchasing crude for the SPR employing a pilot program beginning with a purchase of 3M barrels of oil, with “contracts” to be awarded “no later than January 13th” for delivery to the Big Hill SPR site in February.  SPR is the world’s largest supply of emergency crude oil and encompasses four storage sites in TX and LA.


Embargoed Russian Oil (IEA, Bloomberg, Dan Yergin, FT, WSJ, Kpler).  According to the IEA, Russian November liquids production rose to 11.2 MBD, only 200 KBD below pre-invasion levels, and oil exports rose to 8.1 MBD, highest since April. Sakhalin (previously operated by XOM, now by Rosneft) apparently drove the increase. The EU/UK ban on Russian crude imports and the G7/Australia price cap on Russian seaborne crude at $60/bbl went into effect on Dec 5th. The price cap was formulated because the US was concerned that the proposed EU/UK embargo would lead to a shortage of oil and materially higher prices. The objective of the price cap is to suppress Russian revenues while maintaining oil exports. Dan Yergin recently observed in a WSJ op-ed, “As long as Russian oil is bought below $60/bbl, a trader can handle it, a broker can insure it, and a tanker can carry it…Players along the value chain, from initial purchasers to shippers, must attest that they don’t exceed the price cap.” The current price of Urals is ~$40-45/bbl, ~45-50% below Brent and ~40% below the $70/bbl estimated price on which Russia’s 2023 budget is based.


Notwithstanding the fog of uncertainty, a fundamental law of nature will likely continue to exert itself: heavily discounted crude will eventually find a home somewhere in the marketplace. But, at some point, this premise has limits. Should the universe of buyers contract to such a small number, saturation will be reached no matter how cheap the crude.  The IEA believes Russia will need to shut-in 400 KBD of production in December and even more in Q1 (1.8 MBD by the end of Q1) following the EU ban on product imports as of Feb 5th. Vitol in November expressed that it expected Russian seaborne exports to fall by as much as 1 MBD if Russia is unable to secure the required tanker capacity. Multiple sources profess that Russia has assembled a tanker fleet of more than 100 vessels, but they’ll likely need ~200 (it all depends on the mix of vessels) to maintain seaborne exports. No matter, the EU ban and price cap, at a minimum, will likely add friction to Russia’s ability to clear barrels in Asia.


Russian Deputy PM Alexander Novak has threatened that Russia will slash production by 700 KBD in response to the price cap. And last Tuesday Russia banned the sale of oil and products to countries imposing the price cap. And yet the decree asserts that deliveries of Russian crude to countries imposing the price cap would be allowed with “special permission” by Putin (WSJ). The real test of Russia’s resolve will be if it decides to cut-off oil exports to non-western buyers.  China and India (collectively represented 70% of Russia’s seaborne crude exports in December), which have been the largest importers of Russian oil and primary beneficiaries of heavily discounted prices, would likely be resistant to paying markedly higher prices.


The FT recently reported that at least 18 Russian oil cargoes have been loaded onto western-insured tankers since the price cap commenced December 5th, representing ~25-30% of the 63 vessels identified by Kpler carrying Russian crude between December 5-25th.  According to this account, nine vessels were destined to India, six to China and one to Turkey. An additional four vessels insured by western companies were headed to Bulgaria (exempt from the EU ban until end of 2024). According to Kpler, however, since the price cap went into effect, Russian seaborne exports have dropped to ~2.4 MBD, ~25% below the average for the first eleven months of last year (WSJ). For the first three full weeks of December, Russia exported 50M of seaborne crude, compared with 67M for the same period in November. Kpler contends that the contraction is due, in part, to harsh winter weather as well as weak China demand, but that the “number of buyers of seaborne Russian crude has dropped to half a dozen or so countries.” (WSJ).  Kpler, in the FT interview, expressed that it “is still too early to draw any firm conclusions about the medium-term effect.” Fair enough. Uncertainty reigns.


European Energy Crisis (sources: FT, Bloomberg, EIA, IMF).  According to Bloomberg, the European energy crisis has, thus far, cost $1T. What Bloomberg describes as Europe’s “deepest crisis in decades,” has only just begun. In an FT survey of 37 economists, the collective view for 2023 is a flat-to-down economic contraction in the Eurozone (vs. the IMF prophecy of +0.5%). European governments have been responding to the new energy reality with consumer subsidies, and they recently reached an agreement on a wholesale price-cap at €180/MWh, which should come into effect Feb 15th. The price threshold needs to persist for three days for the cap to be triggered. According to the FT, several market protagonists have warned that the price cap increases the risk of heightened volatility (as if the volatility over the past year has been anything short of frenetic) as “traders would circumvent it through unregulated” OTC trades.  The agreement also stipulates that prices must be €35/MWh above an average of global LNG prices for three days to be triggered.  But price-caps aren’t a structural solution.  Following winter, Europe will be confronted with having to rebuild natural gas storage in a world in which LNG cargoes will likely be more competitively bid (China gas imports likely to increase ~7% in 2023 according to CNOCC). TTF nat gas prices are currently sub-€80/MWh and were as high as ~€340 this summer vs. pre-pandemic prices of ~ €10. The S&P chief economist for Europe observed that while “the tail risk of gas rationing has likely been avoided this winter…the question of energy supply for the next winter is still open.” (FT). Energy is inherently a long lead-time industry and global LNG export capacity is unlikely to be materially increased until 2025-2026, with over 50% of the incremental capacity expected to come from the US (BNEF – 2021 global LNG supply = 387M metric tons, 2026 = 460M). But between here and there, the LNG market is expected to remain tight with Europe facing persistent energy insecurity.  While European resolve in supporting the Ukrainian defense effort against the Russian assault has exceeded expectations, we wonder about its staying power in the event of extreme privation this winter. French President Macron recently decried the impact the IRA was having in drawing renewable energy investment away from Europe to the US. Memo to French President: It’s not just US government subsidies drawing capital formation and investment away from Europe but, more fundamentally, the lack of energy security which is impacting European competitiveness.


Iranian convulsions and implications (NYT, UN, Bloomberg, Robert Kaplan, FGE).  Recent developments in Iran have been arresting, profound, horrifying, and inspiring. Protests erupted in September over the death of a 22 year-old woman following detention by Iran’s infamous morality police due to the “hijab rule.” Since then, according to the NYT, Iran’s security forces have killed hundreds of Iranians, in a savage response of “mass arrests and beatings, military assaults and the killings of dozens of teenagers and children.” According to human rights groups and the UN, ~500 protestors have been killed and 14,000 arrested. Trotsky’s maxim on revolutions comes to mind: “Revolution is impossible until it’s inevitable.” Is the Islamic regime at a breaking point? The noted historian Robert Kaplan, and others, believe that “a 44-year epoch of the Middle East may be coming to an end, as the region begins to turn on its axis.” Mr. Kaplan goes onto observe in a Bloomberg op-ed that “cracks are starting to appear in the Islamic Republic’s power structure. Because Iran constitutes the Middle East’s geopolitical pivot point, nothing has the potential to change the region as a much as a more liberal, post-revolutionary regime which could change the Middle East as a much as the collapse of the Berlin Wall changed Europe.” Reuel Marc Gerecht (ex-CIA “Iranian-targets” officer), in a WSJ op-ed, observed that Iran’s rulers are “uncertain, fearful, and increasingly incoherent in their public statements. They surely know that these demonstrations aim to foment revolution, not reform. And they have reason to worry that the demonstrations will be successful.” What does this potentially mean for oil and gas production? In the event the Islamic regime falls, FGE consultants believe production would likely gap lower in the immediate aftermath, but eventually Iran would open to international investment, crude oil production capacity could increase to 5.5+ MBD (current production, according to MOMR, ~2.6 MBD), natural gas production could increase to 50 BCFD and Iran could become an LNG exporter within five years. While several dominoes need to fall in the right direction for this prophecy to be realized, it’s worthy of contemplation as the turbulence in Iran continues to unfold.


The imperative for low-carbon sources of energy isn’t going away (IEA, Bloomberg, EV Volumes, WSJ).  Oil and natural gas are now front-page news but the need for renewable and low-carbon sources of energy remains. Notwithstanding public market volatility and a considerably less accommodating IPO market, significant private investment continues to unfold due to the size of the end markets and the perceived duration of the investment themes. Moreover, throbbing geopolitical threats have accentuated the need for holistic energy security, including renewables.  The IEA projects that global renewable power capacity is now expected to expand by 2,400 GW over the 2022-2027 period, an amount equal to the entire power generating capacity of China. This represents a 30% increase in the IEA’s forecast of just a year ago. Renewables are projected to account for 90% of global electricity expansion over the next five years. IEA Executive Director Fatih Birol recently asserted that “the world is set to add as much renewable power in the next five years as it did in the previous 20.” Global EV sales doubled in 2021 and represented 9% of global PLDV sales and last year they were expected to rise to 13% (1H’22 sales were up ~60-65%, ICE sales down sharply, according to EV Volumes)). According to JD Power, 53 new EV models are either on the US market or soon to be rolled out (WSJ). China NEV sales more than doubled in the first eleven months of last year – ~25% of new car sales are now NEVs (WSJ). Moreover, China accounted more than 1/2 of all EVs sold globally in 2022. Sales will slow in 2023, however, as EV subsidies expired at the end of last year. But exports, which more than doubled last year, are expected to remain well-behaved.   BNEF recently projected that cumulative investment in EV charging hardware and installation will reach $62B at the end of 2022, with ~$29B having been invested in last year alone, up 228% y/y. Of the total investment in 2022, ~60% is attributed to more than 600K public chargers built in China. Cumulative global investment is expected to surpass $100B this year should China keep up its current pace.  The recently enacted IRA bill is resulting in non-trivial renewable/EV battery and charging capital investment in the US, as, according to BNEF, “factories are scaling up and purchase commitments are increasing. There’s an influx of infrastructure investors and coordination across the charging ecosystem, with automotive, charging, utility and retail sectors working together.”  It’s all hands-on-deck, including renewables/EVs writ large.


Industry M&A & Implications.  Plenty of M&A announcements within both E&P and OFS this year with two OFS deals announced this past holiday week: ACDC’s acquisitions of REV Energy Services (frac) and Performance Proppants (sand).  Not going to comment on deal valuation metrics other than to say the deals don’t screen offensive; we like the use of earn-outs in the Rev transaction; and there is value in more scale for ACDC within the Rockies.  Moreover, the integration theme with Performance is transformative given the size of the Performance operations.  As for the bigger picture, numerous PE-backed private companies still exist (either via the original sponsor and/or creditors who became owners in 2020/2021), thus one would think more M&A transactions are likely to unfold within both E&P and OFS.  Moreover, we know from multiple small private contacts, a desire to transact exists, but differences on valuation have largely limited many deals to date.


With respect to the current consolidation theme, acquisitions, on the one hand, can be a good thing to the extent buyers can achieve the advertised synergies and retain the people it wants to retain.  In the case of OFS, the unwritten benefit, but one that is well understood, is potentially greater pricing power.  Meanwhile, E&P deals may enhance winnowing Tier 1 inventory.  Neither of these are new revelations to our readers.  But the recent spate of M&A also presents risks as well.  With E&P, we have seen recent deals result in a near-immediate reduction in drilling activity as buyers drop seller rigs.  Obviously, not good for our OFS friends as fewer rigs yields reduced opportunities for other OFS verticals that follow the rig.  We have also witnessed (and are witnessing) multiple sellers staying in the game with some now gathering more acreage to do it again.  In time, this becomes more D&C activity, thus good for OFS.  Dumbing it down: it seems E&P M&A yields a short-term risk to OFS, but over time, the risk would appear to fade.


Within OFS, a similar situation exists.  Consolidating deals potentially create a headache for E&P customers as the reduction in service providers yields fewer bidders which often leads to higher service costs, all else being equal (i.e., short-term risk).  But consider the fact the headaches may also be shared by more than just the E&P customer, a point which we believe some folks may not appreciate.  Specifically, some vendors likely see the transactions as similarly disruptive, at least initially.  Imagine for a moment that your company sells sand and/or pump-related parts.  If your customer is acquired, there’s a risk the business goes away, particularly if the buyer is vertically integrated.  Or imagine you sell wireline-related capital equipment and goods.  Your customer is acquired by another wireline player who prefers alternative capital equipment/supplies.  Now, all of a sudden, your addressable market is reduced.  This list of examples could go on.


So, what is one to do?  In the old days, we would wait for management teams to “do it again” via funding from traditional PE shops.  The build-and-flip model worked well for many years.  Now, however, the traditional PE market is effectively dead, at least for OFS, and strategic buyers are smarter about how they acquire.  Moreover, long lead times likely keep material new expansion efforts at bay even if capital were readily available, which it’s not.  Notwithstanding these points, if the OFS consolidation process persists, we wonder if the business model will be a return to 2011/2012 timeframe, a period when E&P’s effectively underwrote the newbuild risk for OFS start-up’s (i.e., take-or-pay contracts).  Or, could we see a new twist where vendors to the OFS space come together to create a new customer base?  Time will tell, but we know E&P customers and well as equipment vendors/suppliers like choice.  Therefore, it’s hard to envision a scenario where impacted companies sit back and do nothing.  That said, we reiterate our view that in the near-term with lead times remaining stubbornly long and access to capital remaining sufficiently extinct, we believe the runway for consolidators is quite good, particularly if industry activity remains relatively stable (i.e., +/- 50 rigs).  Further, we would bet we see more OFS M&A before we see new start-up businesses, at least those in pressure pumping and sand.  Therefore, barring a collapse in the commodity complex, we envision a continued tight market, especially for higher-end equipment.


Social Media Observation. We admit to perusing social media more than we probably should.  Can’t help but point out a recent LinkedIn post by a frac company this past week seeking to “add some frac dates” for one its regional crews.  As a stand-alone data point, that doesn’t scream bullish and frankly conflicts with our glass half-full view expressed in the prior bullet.  Advertising open dates doesn’t imply a sold out market.  Interestingly, the post seems to imply the frac company now has multiple crews in at least two basins which we are ashamed to say is news to us.  We had erroneously assumed they were in just one region.  Congrats to them for their growth.




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Daniel Energy Partners is pleased to announce the publication of its first market research note. In this note, we reached out to executives across the oil service and E&P sectors to gauge leading edge sentiment.

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