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Energy Markets Digest - Summer 2023

Chiron Financial LLC released its first in its new series of Energy Markets Digest, where Chiron Financial LLC will review the key components of the energy markets. In this inaugural digest, the energy markets and pricing are likely to remain non-threatening in the near term as the global economic outlook remains cloudy due to the slow return of growth in China.


Exec­u­tive Summary

A more bal­anced mar­ket outlook 

  • The Brent oil price fell from its June 2022 peak of $123 per bar­rel to $75 in May 2023, and the Hen­ry Hub nat­ur­al gas price dropped from its August 2022 peak of $8.81 per mil­lion British ther­mal units (MMb­tu) to $2.15 in May 2023.1 Elec­tric pow­er mar­kets also saw some wild swings, espe­cial­ly in Europe, but those have been mit­i­gat­ed by renew­ables, nuclear, mild weath­er, and gov­ern­ment subsidies. 
  • With the glob­al eco­nom­ic out­look remain­ing cloudy due to the slow return of growth in Chi­na, and high infla­tion lead­ing to sub­stan­tial­ly high­er inter­est rates as well as some dis­rup­tion in the bank­ing sys­tem, ener­gy mar­kets and pric­ing are like­ly to remain non-threat­en­ing in the near term. 
  • The shift toward clean ener­gy is accel­er­at­ing, Chi­na is lead­ing in elec­tric car pro­duc­tion, the IRA tax cred­its are jump start­ing green ener­gy invest­ments in the US, and the oil mar­ket appears to be ade­quate­ly supplied. 
  • Despite the progress, the rate of invest­ment in clean ener­gy — about $1.3 T this year — is far short of what is need­ed to meet car­bon reduc­tion goals. The Inter­na­tion­al Renew­able Ener­gy Agency says $35 T is need­ed by 2030 to stay on track 


The IEA Oil 2023 report released June 14 projects an ade­quate­ly sup­plied oil mar­ket to meet reduced demand growth over the next five years and declin­ing demand thereafter

  • Glob­al oil demand growth is pro­ject­ed at 2.4 mil­lion bar­rels per day (MMb/​d) in 2023, main­ly in Asia, then falling below 1.0 MMb/​d.
  • China’s demand recov­ery fol­low­ing COVID shut­downs has begun, but more slow­ly than ear­li­er expectations.
  • Oil sup­ply growth of 5.9 MMb/​d is pre­dict­ed in 2023, led by the US and Brazil.
  • Russ­ian oil sup­ply has near­ly recov­ered after a decline in 2022; April exports reached a post-inva­sion high of 8.3 MMb/d.3
  • OPEC+ quo­ta cuts off­set oth­er pro­duc­tion growth but have not been enough to sus­tain high­er prices.
  • Brent oil price pre­dic­tions from var­i­ous ana­lysts are in the $70s to low $80s per barrel.


At the end of 1Q23, Euro­pean hub and Asian spot liq­ue­fied nat­ur­al gas (LNG) prices had fall­en below their sum­mer 2021 lev­els, albeit remain­ing well above their his­toric averages

  • Fol­low­ing the sup­ply shock sparked by Russia’s inva­sion of Ukraine in Feb­ru­ary 2022, spot gas prices across the key north­east Asian, North Amer­i­can and Euro­pean mar­kets dropped by close to 70% between mid-Decem­ber and the end of the 1Q23.
  • Nat­ur­al gas con­sump­tion in Europe’s advanced economies fell by an esti­mat­ed 55 bil­lion cubic meters (bcm) year-over-year (YoY) dur­ing the 202223 heat­ing sea­son, a record drop, reflect­ing mild weath­er and reduced consumption.
  • High stor­age lev­els in Europe are expect­ed to reduce injec­tion demand dur­ing the sum­mer of 2023.
  • The futures mar­ket in US gas is antic­i­pat­ing a near dou­bling in price by year-end to about $4/​MMbtu. Key fac­tors includ­ing adverse weath­er, low­er avail­abil­i­ty of LNG, and the pos­si­bil­i­ty of a fur­ther decline in Russ­ian pipeline gas deliv­er­ies to Europe could eas­i­ly renew mar­ket ten­sions and upward price pressure.
  • The US is pro­ject­ed to account for over half of the LNG glob­al sup­ply increase in 2023 and become the world’s largest LNG exporter. Glob­al LNG sup­ply is fore­cast to increase by a mere 4% (or over 20 bcm) in 2023 which would not be suf­fi­cient to off­set an expect­ed reduc­tion in Russia’s piped gas sup­plies to Europe.

Oil Overview


IEA pre­dicts world oil demand is approach­ing a peak

  • Growth in world oil demand is set to lose momen­tum over the 2022 – 28 fore­cast peri­od as the ener­gy tran­si­tion gath­ers pace, with an over­all peak loom­ing on the hori­zon. Led by con­tin­ued increas­es in petro­chem­i­cal feed­stocks, total oil con­sump­tion growth will remain nar­row­ly pos­i­tive through 2028 as usage ris­es to 105.7 MMb/​d, 5.9 MMb/​d above 2022 levels.

Demand for oil for com­bustible fos­sil fuels – which excludes bio­fu­els, petro­chem­i­cal feed­stocks and oth­er non-ener­gy uses – is on course to peak at 81.6 MMb/​d in 2028

  • The expect­ed post-pan­dem­ic pin­na­cle in oil demand is expect­ed for gaso­line in 2023, road trans­port in 2025 and total trans­port in 2026. Some economies, notably Chi­na and India, will con­tin­ue to reg­is­ter growth through­out the fore­cast. The Orga­ni­za­tion for Eco­nom­ic Coop­er­a­tion and Devel­op­ment (OECD) may crest this year, as a result of the sweep­ing impact of mount­ing vehi­cle effi­cien­cies and electrification.
  • The glob­al ener­gy cri­sis sparked a move­ment towards low­er-emis­sion sources, as well as pol­i­cy empha­sis on ener­gy effi­cien­cy improve­ments, with $2 T mobi­lized for clean ener­gy invest­ments by 2030, and the rapid growth in elec­tric vehi­cle (EV) sales.

Non-OECD nations will be the prin­ci­pal engine of eco­nom­ic growth, account­ing for almost 80% of the 2022 – 28 increase in glob­al GDP

  • The glob­al post-pan­dem­ic eco­nom­ic rebound end­ed con­clu­sive­ly in 2022, after unprece­dent­ed gov­ern­ment stim­u­lus and sup­ply chain dis­rup­tions caused con­sumer infla­tion to soar. This prompt­ed an extra­or­di­nary tight­en­ing of mon­e­tary pol­i­cy that is set to con­strain GDP deep into 2024.
  • Glob­al oil demand growth shriv­els from 2.4 MMb/​d in 2023 to just 400 thou­sand bar­rels per day (Mb/​d) by 2028 but strong petro­chem­i­cal demand and con­sump­tion growth in emerg­ing economies will more than off­set declines in advanced economies.
  • Liqui­fied petro­le­um gas (LPG), ethane and naph­tha will account for more than 50% of the rise between 2022 and 2028 and near­ly 90% of the increase com­pared with pre-pan­dem­ic levels.

The expan­sion in glob­al oil demand through 2028 will be pow­ered by faster-grow­ing economies in the devel­op­ing world – espe­cial­ly in Asia – while oil use in advanced coun­tries contracts

  • Around three-quar­ters of the 2022 – 28 demand increase will come from Asia, with India sur­pass­ing Chi­na as the main source of growth by 2027. The growth in Asia is ini­tial­ly fueled by China’s reopen­ing and will be more per­ma­nent­ly under­pinned by India as it con­sol­i­dates its sta­tus as the world’s fastest-grow­ing major econ­o­my. Demand growth in Chi­na slows marked­ly from 2024 onwards.
  • As in oth­er regions, trans­port fuels lead the gains in the ini­tial stages of the recov­ery. Over­all demand first exceeds its pre-pan­dem­ic lev­el in 2023.

Chi­na will con­tin­ue to account for around one-sixth of world oil demand and half of glob­al oil con­sump­tion growth; how­ev­er, this increase is heav­i­ly front loaded: after the mas­sive rebound of post-lock­downs, oil demand growth decel­er­ates massively

  • This slow­down cor­re­sponds with China’s econ­o­my pro­ceed­ing along a path of struc­tural­ly low­er GDP growth as its era of dou­ble-dig­it eco­nom­ic expan­sion has now end­ed. Its present tar­get is 5% per year. Demo­graph­ics is key, as China’s pop­u­la­tion declined in 2022 after decades of slow­ing birth rates.

India is set to over­take Chi­na in terms of glob­al YoY oil demand growth in 2027

  • The fastest-grow­ing econ­o­my in the world, with GDP growth aver­ag­ing 6.9% for 2024 – 2028, is aid­ed by benign demo­graph­ics. India sur­passed Chi­na to become the world’s most pop­u­lous coun­try in 2023. Although its pop­u­la­tion growth has been slow­ing for decades, it will like­ly not peak until 2065. Fur­ther pro­pelled by trends such as urban­iza­tion, indus­tri­al­iza­tion, and the emer­gence of a wealth­i­er mid­dle-class keen for mobil­i­ty and tourism, Indi­an oil demand will grow by more than 1 MMb/​d between 2022 and 2028.

Nei­ther North Amer­i­ca nor Europe will return to their 2019 levels

  • North Amer­i­ca and Europe, where ener­gy tran­si­tion poli­cies and effi­cien­cy gains will be most pro­nounced, will spend most of the fore­cast peri­od in con­trac­tionary demand mode. North Amer­i­ca will plateau in 2023 at 24.7 MMb/​d, and sub­se­quent­ly decline by 240 Mb/​d per year on aver­age through 2028. Europe, aver­ag­ing 14.9 MMb/​d in 2022, will be but­tressed by the increase in jet fuel con­sump­tion through 2024 before start­ing an over­all decline aver­ag­ing 120 Mb/​d annu­al­ly there­after. Dri­vers include high­er ener­gy effi­cien­cy in the trans­port sec­tor, pen­e­tra­tion of EVs, sub­sti­tu­tion by oth­er ener­gy sources, tele­work­ing, and less fre­quent busi­ness travel.

Price sce­nar­ios based on the brent for­ward curve see only mod­est impact on demand

  • Besides GDP growth rates, assump­tions of future oil prices are a key com­po­nent of demand esti­mates, with fore­casts sen­si­tive to both the absolute price lev­el and intertem­po­ral changes over the out­look. The high-price sce­nario would low­er 2028 glob­al oil demand by 430 Mb/​d. How­ev­er, this would not cause demand to peak ear­li­er. Con­verse­ly, the low-price sce­nario would raise world oil con­sump­tion by 670 Mb/​d at the end of the fore­cast­ing period.

Capac­i­ty build­ing eas­es as ener­gy tran­si­tion accelerates

  • An expan­sion in glob­al oil pro­duc­tion capac­i­ty, dom­i­nat­ed by the Unit­ed States and oth­er pro­duc­ers in the Amer­i­c­as, is set to mod­er­ate pro­gres­sive­ly over the medi­um term. How­ev­er, the gains still keep up with the slow­er pace of pro­ject­ed demand growth over the 2023 – 28 fore­cast peri­od. The world’s total sup­ply capac­i­ty is fore­cast to post a net increase of 5.9 MMb/​d to 111 MMb/​d by 2028, but a marked slow­down in US addi­tions sees over­all glob­al capac­i­ty growth eas­ing annu­al­ly from an aver­age 1.9 MMb/​d in 2022 – 23 to just 300 Mb/​d by the end of the forecast.

Glob­al upstream oil and gas invest­ment is on track to increase by an esti­mat­ed 11% in 2023 to $528 B, com­pared with $474 B in 2022

  • This lev­el of invest­ment would be ade­quate to meet fore­cast demand in the peri­od cov­ered by the report. Indus­try invest­ment in giant projects has slowed sharply amid the shift towards a low­er car­bon future. Com­pa­nies are tar­get­ing small­er, short-cycle projects and select oil field devel­op­ments with short­er pay­back peri­ods in the Amer­i­c­as and Mid­dle East.
  • Oil pro­duc­ing coun­tries out­side the OPEC+ alliance (non-OPEC+) dom­i­nate medi­um-term capac­i­ty expan­sion plans, with a 5.1 MMb/​d sup­ply boost led by the Unit­ed States, Brazil and Guyana. Sau­di Ara­bia, the Unit­ed Arab Emi­rates (UAE) and Iraq lead the capac­i­ty build­ing with­in OPEC+, while African and Asian mem­bers strug­gle with con­tin­u­ing declines. This makes for a net capac­i­ty gain of 800 Mb/​d from the 23 mem­bers in OPEC+ overall.
  • The broad decel­er­a­tion in pro­duc­tion capac­i­ty build­ing large­ly reflects the glob­al piv­ot towards clean­er ener­gy and a cor­re­spond­ing weak­er demand out­look. This cre­ates a spare capac­i­ty cush­ion of an aver­age 4.1 MMb/​d, con­cen­trat­ed in Sau­di Ara­bia and the UAE, which should help ensure that world mar­kets are ade­quate­ly supplied.
  • The out­look for Rus­sia is cloud­ed by the cur­rent geopo­lit­i­cal sit­u­a­tion, but the IEA fore­casts capac­i­ty to fall as sanc­tions lim­it its abil­i­ty to export, forc­ing some pro­duc­tion to be shut in. Longer term, the depar­ture of West­ern com­pa­nies in the wake of Russia’s inva­sion of Ukraine may also curb capac­i­ty growth due to project delays stem­ming from a lack of tech­nol­o­gy and equipment.

Glob­al oil sup­ply growth con­cen­trat­ed in the Amer­i­c­as

  • The out­look for actu­al sup­ply growth, as opposed to capac­i­ty, shows the Unit­ed States, along with Brazil and Guyana, dom­i­nat­ing gains, account­ing for 80% of the increase over the fore­cast period.

US shale matures to a high­er return, low­er growth trajectory

  • A post COVID-19 recov­ery in US oil pro­duc­tion was solid­i­fied in 2022 with pro­duc­tion up 1.1 MMb/​d YoY. The pace of expan­sion marked­ly slows from 2024 onwards as pro­duc­ers nav­i­gate the ener­gy tran­si­tion and US light tight oil (LTO), com­pa­nies strug­gle with high­er costs, increas­ing decline rates and low­er out­put from new wells drilled. US crude oil pro­duc­tion grows to 13.6 MMb/​d in 2028, set­ting new record highs through 2027. The increase is led by LTO, pri­mar­i­ly from the Per­mi­an Basin. The shale patch has matured finan­cial­ly to a low­er growth tra­jec­to­ry as it focus­es on dis­ci­plined invest­ing, de-lever­ag­ing and return­ing cash to shareholders.
  • Despite cli­mate action, con­cerns of under­in­vest­ment and a sharp slow­down in LTO, the Unit­ed States is still the largest con­trib­u­tor to medi­um-term sup­ply growth at 2.6 MMb/​d by 2028, of which 1.7 MMb/​d is crude oil. Nat­ur­al gas liq­uids (NGL) pro­duc­tion is fore­cast to rise by 860 Mb/​d to 6.7 MMb/​d, led by high­er ethane exports, as US LTO con­tin­ues to grow and nat­ur­al gas pro­duc­tion shifts to more liq­uids-rich plays.
  • Invest­ment rates have con­tin­ued to recov­er but may nev­er return to pre-COVID lev­els as improve­ments in pro­duc­tiv­i­ty had, in aggre­gate, been lead­ing to low­er recov­ery costs from 2016 until 2022. Although that may be lit­tle con­so­la­tion for drillers today as they feel the pinch of high spec rig day rates that have increased over 50% in the last year, con­tin­ued tight­ness of hydraulic frack­ing equip­ment and per­sis­tent labor issues, as well as reduced well flow rates.

Refin­ery activ­i­ty and trade upended

  • A third wave of refin­ery capac­i­ty clo­sures, con­ver­sions to bio­fu­el plants and project delays since the pan­dem­ic reduced the over­hang in glob­al refin­ery capac­i­ty. This, com­bined with a sharp drop in Chi­nese oil prod­uct exports and an upheaval of Russ­ian trade flows, result­ed in tight capac­i­ty and record prof­its for the indus­try in 2022.
  • While net refin­ery capac­i­ty addi­tions of 4.4 MMb/​d expect­ed by 2028 out­pace demand growth for refined prod­ucts, con­trast­ing trends among prod­ucts means that a repeat of the 2022 tight­ness in mid­dle dis­til­lates is possible.

Refin­ing sec­tor on cusp of trans­for­ma­tion­al shift

  • Refin­ers may need to shift their prod­uct yields towards mid­dle dis­til­lates and petro­chem­i­cal feed­stocks to reflect chang­ing demand pat­terns. Demand for petro­le­um-based pre­mi­um road trans­port fuels, such as gaso­line and diesel, is 1 MMb/​d below 2019 lev­els at the end of the fore­cast period.
  • At the same time, robust petro­chem­i­cal activ­i­ty and slow­er growth in NGLs sup­ply rais­es demand for refin­ery-sup­plied LPG and naph­tha. China’s inter­nal poli­cies aimed at reduc­ing emis­sions could lead to con­tin­ued volatil­i­ty in prod­uct export vol­umes and again upend glob­al sup­ply flows and mar­gins in the medi­um term. Chi­na now has the great­est share of installed capac­i­ty in the world, after over­tak­ing the Unit­ed States in 2022. Cru­cial­ly, prod­uct bal­ances are heav­i­ly depen­dent on high­er Chi­nese prod­uct exports, espe­cial­ly for diesel, and the mid­dle dis­til­late mar­kets could be very tight by 2028.
  • China’s dom­i­nance of spare refin­ing capac­i­ty and the loom­ing peak in trans­porta­tion fuel con­sump­tion will require refin­ers to deft­ly man­age their oper­a­tions to sus­tain the prof­itabil­i­ty of their assets and meet oil demand in their mar­kets. They will also need to adjust to a chang­ing crude oil slate amid slow­er growth in US LTO and the poten­tial for OPEC+ pro­duc­ers to reduce exports of heav­ier crudes. Those refiner­ies most exposed to these changes face the renewed risk of closure.

Nat­ur­al Gas Overview


Glob­al gas demand is expect­ed to remain flat in 2023, with high­er demand in Asia Pacif­ic and the Mid­dle East off­set­ting the expect­ed declines in Europe and North America

  • In Asia, gas demand is pro­ject­ed to increase by close to 3%, with Chi­na and India as the main dri­vers. Gas demand in Chi­na is fore­cast to increase by over 6% in 2023, sup­port­ed by a recov­ery in eco­nom­ic activ­i­ty and poten­tial­ly high­er gas use in industry.
  • Gas demand in Europe’s advanced economies is pro­ject­ed to decline by 5% as rapid­ly expand­ing renew­ables weigh on gas-fired gen­er­a­tion. After strong growth in 2022, gas demand in North Amer­i­ca is expect­ed to decline by 2% as a result of low­er gas use for space heat­ing, pow­er gen­er­a­tion and industry.
  • The Russ­ian gas indus­try is fac­ing mul­ti­ple chal­lenges. If flows to the Euro­pean Union con­tin­ue at the lev­els seen in the first quar­ter, Russ­ian piped gas deliv­er­ies to Europe’s advanced economies would drop by 45% (or over 35 bcm) in 2023 com­pared with 2022. Fol­low­ing a 90 bcm drop in Russ­ian gas pro­duc­tion in 2022, low­er exports and mut­ed domes­tic demand are expect­ed to fur­ther reduce Russia’s out­put by over 50 bcm in 2023.

North Amer­i­can gas demand increased dur­ing the win­ter, but is expect­ed to con­tract in 2023

  • Nat­ur­al gas con­sump­tion in the US saw a 5.3% rise in 2022, dri­ven by the use of nat­ur­al gas for pow­er gen­er­a­tion, stim­u­lat­ed by the retire­ment of coal-fired pow­er plants and rel­a­tive­ly high coal prices, along with low­er than aver­age coal stocks.
  • North Amer­i­can gas con­sump­tion is expect­ed to decrease by about 2.9% in 2023. In the Unit­ed States, slow­er eco­nom­ic growth is set to depress gas demand in indus­try, while an unsea­son­ably mild Q1 reduced gas use in the res­i­den­tial and com­mer­cial sec­tors, weigh­ing on the out­look for the full year. The eco­nom­ic slow­down cou­pled with the strong expan­sion of renew­ables is set to reduce the call on gas-fired pow­er plants, although con­tin­ued coal-to-gas switch­ing could mod­er­ate the over­all decline in gas demand for pow­er generation.

Euro­pean gas demand dropped by a record 55 bcm dur­ing the 202223 heat­ing season

  • High gas prices con­tin­ued to weigh on gas use in indus­try, while milder weath­er con­di­tions – togeth­er with ener­gy sav­ing mea­sures – depressed dis­tri­b­u­tion net­work-relat­ed demand and gas burn in the pow­er sector.
  • Gas-sav­ing mea­sures enact­ed in pub­lic build­ings (such as manda­to­ry tem­per­a­ture con­trols), fuel-switch­ing in rur­al house­holds (includ­ing to bio­mass, fuel oil and waste), the instal­la­tion of heat pumps, effi­cien­cy gains and behav­ioral changes all played a crit­i­cal role in reduc­ing dis­tri­b­u­tion net­work-relat­ed demand.
  • In 2021, the share of peo­ple unable to heat their homes in the EU stood at 6.9%. This sit­u­a­tion is expect­ed to have sig­nif­i­cant­ly wors­ened dur­ing the 202223 win­ter season.

Asian gas demand came under pres­sure in 2022; recov­ery in 2023 is expect­ed to be modest

  • Asia’s gas con­sump­tion expe­ri­enced an unprece­dent­ed slow­down of 2% in 2022 because of high LNG prices, COVID-relat­ed dis­rup­tion in Chi­na and mild weath­er for most of the year in North­east Asia. Demand is pro­ject­ed to return to mod­est growth of around 3% in 2023 due to the lift­ing of China’s zero-COVID policy.
  • China’s coal imports reached record lev­els dur­ing 1Q23; this trend may con­tin­ue through­out the year sup­port­ed by the exten­sion of the pro­vi­sion­al zero” import tax pol­i­cy until the end of 2023 as part of Bei­jing safe­guard­ing its ener­gy secu­ri­ty. The largest coal ports in Chi­na are locat­ed on the east coast, where some of China’s largest LNG import ter­mi­nals are based where pow­er pro­duc­ers can switch between coal and nat­ur­al gas for ener­gy gen­er­a­tion to achieve the most cost-effec­tive production.

Chi­na grad­u­al­ly recov­ers its appetite for LNG, although imports are set to remain below their 2021 levels

  • China’s LNG imports declined by an unprece­dent­ed 20% in 2022, enabling high­er LNG deliv­er­ies to the Euro­pean mar­ket. China’s LNG import growth recov­ered to dou­ble-dig­it growth in March 2023, sup­port­ed by high­er domes­tic gas demand. The country’s LNG inflows are expect­ed to increase by 10 – 15% com­pared with 2022 while remain­ing below their 2021 levels.

LNG became effec­tive­ly a new base­load sup­ply for Europe, account­ing for two-third of the region’s gas imports and meet­ing around one-third of its gas demand through the 202223 win­ter season

  • After strong growth in 1Q23, OECD Europe’s LNG imports are expect­ed to decline for the remain­der of the year amidst low­er injec­tion needs and a con­tin­ued decline in Euro­pean gas consumption.

Glob­al LNG demand mod­er­at­ed in Q1, expand­ing by 2% YoY (net of re-exports), with strong growth in Europe

  • After months of YoY declines in China’s LNG imports (net of re-exports), vol­umes rebound­ed in Feb­ru­ary, up by 2% on the same month in 2022 accord­ing to ICIS LNG Edge. This was the first time that month­ly Chi­nese LNG imports record­ed a YoY increase since Decem­ber 2021. This rebound seemed to be con­firmed in March as net LNG imports increased by 11% YoY.
  • Although they remained well above his­tor­i­cal aver­ages, Asian LNG spot prices fell sig­nif­i­cant­ly in 1Q23 from the record lev­els reached in the sum­mer of 2022. In 1Q23 the aver­age JKM spot price was around $18/​MMbtu, com­pared with $30/​MMbtu in the first quar­ter of 2022 and hav­ing reached $70/​MMbtu at the peak in August 2022. In March 2023 spot LNG prices in North­east Asia aver­aged at $13/​MMbtu, encour­ag­ing South Asian buy­ers to return to spot mar­kets via tenders.
  • Europe’s net LNG imports rose by 8% (or 3.5 bcm) YoY in 1Q23 as the con­ti­nent con­tin­ued to off­set declin­ing Russ­ian pipeline gas sup­plies, main­ly by increas­ing LNG imports and tak­ing advan­tage of low gas price lev­els not seen since August 2021. How­ev­er, LNG inflows into France dropped by 23% YoY in 1Q23 (or 2 bcm) and by 55% YoY in March alone, due to a strike at French LNG ter­mi­nals. France accounts for around 12% (or 26 mil­lion tons per year (MMt/​yr)) of Europe’s total regasi­fi­ca­tion capac­i­ty. It became the largest importer of LNG in Europe in 2022, with its LNG imports more than dou­bling on the pre­vi­ous year.

Glob­al LNG sup­ply was up by 2% YoY in 1Q23 mea­sured on an import basis. This was dri­ven by the Asia Pacif­ic region and the Mid­dle East

  • In con­trast to 1Q22, the Unit­ed States expe­ri­enced a mod­er­ate 4% (or 1 bcm) decline in LNG exports, explained by the delayed and only par­tial restart of the Freeport LNG facil­i­ty fol­low­ing an eight-month out­age caused by a fire. Once the Freeport LNG facil­i­ty ful­ly resumes oper­a­tion, glob­al LNG trade is expect­ed to increase by 4% in 2023.
  • Demand growth will be large­ly dri­ven by Asia. China’s LNG imports are expect­ed to increase at a rate of 10 – 15% com­pared with 2022, while remain­ing below their 2021 lev­els. After strong growth in 1Q23, OECD Europe’s LNG imports are expect­ed to decline for the remain­der of the year amidst low­er injec­tion needs and a con­tin­ued decline in Euro­pean gas consumption.

LNG became a base­load sup­ply for Europe account­ing for two-thirds of gas imports dur­ing the 202223 heat­ing season

  • LNG imports are expect­ed to remain broad­ly flat com­pared to last year. Fol­low­ing a strong increase in 1Q23, OECD Europe’s LNG inflows are expect­ed to decline through the remain­der of the year amidst low­er injec­tion needs and a con­tin­ued decline in Euro­pean gas consumption.
  • While the share of OECD Europe’s gas demand met by Russ­ian piped gas fell to well below 10% in the 202223 heat­ing sea­son, LNG effec­tive­ly became a base­load sup­ply for Europe, meet­ing over one-third of the region’s gas demand over the win­ter. Russ­ian piped gas exports to OECD Europe fell by an esti­mat­ed 70% (or 50 bcm) YoY dur­ing the 202223 heat­ing season.
  • LNG imports rose by over 25% (or 20 bcm) YoY to reach a record 94 bcm dur­ing the 202223 heat­ing sea­son. LNG flows from the Unit­ed States increased by 30% (or almost 10 bcm) YoY to account for over 45% of incre­men­tal LNG sup­ply into Europe. This fur­ther rein­forced the posi­tion of the Unit­ed States as Europe’s largest sup­pli­er, account­ing for over 40% of the region’s total LNG imports and meet­ing almost 15% of its gas demand.
  • Assum­ing that Russ­ian flows to the Euro­pean Union con­tin­ue at their 1Q23 lev­els, Russ­ian piped gas deliv­er­ies to OECD Europe would drop by 45% (or over 35 bcm) in 2023 com­pared with 2022.

US nat­ur­al gas out­put main­tains its growth, dri­ven by Per­mi­an oil-dri­ven production

  • US dry gas pro­duc­tion increased by an esti­mat­ed 4% YoY dur­ing Octo­ber 2022 to March 2023, reach­ing an aver­age dai­ly lev­el of 100 bil­lion cubic feet (bcf) in the first quar­ter of 2023 (or a 5.7% YoY increase). Oil dri­ven shale plays increased by close to 8% YoY dur­ing Octo­ber to Jan­u­ary. By com­par­i­son, nat­ur­al gas out­put from gas-dri­ven shale plays was close to sta­ble with a mea­gre 1.1% YoY increase dur­ing Octo­ber to January.
  • Out­put from the Per­mi­an Basin, the largest oil-dri­ven shale play, grew by close to 11% YoY over the same peri­od. This has been sup­port­ed by strong drilling activ­i­ty, with an aver­age of close to 430 new wells drilled per month in the Per­mi­an dur­ing Octo­ber to Jan­u­ary, or a 33% YoY increase, where­as com­ple­tion rates increased by only 4% YoY over the same peri­od, to a month­ly aver­age of 435 wells. Jan­u­ary 2023 marked the high­est lev­el of drilling activ­i­ty in the Per­mi­an since March 2020, with 437 new wells drilled.
  • Total US nat­ur­al gas pro­duc­tion increased by 3.7% in 2022, but this is expect­ed to slow in 2023 due to a com­bi­na­tion of con­tin­ued con­ser­v­a­tive upstream spend­ing, cost infla­tion, lim­it­ed export out­lets and an expect­ed decline in domes­tic demand. This fore­cast expects US dry gas out­put to increase by about 2% in 2023, prin­ci­pal­ly sup­port­ed by asso­ci­at­ed gas production.

The steep decline in nat­ur­al gas demand depressed stor­age with­drawals in Europe and the Unit­ed States over the 202223 win­ter season

  • The Euro­pean Union’s net stor­age with­drawals stood 38% (or 20 bcm) below their five-year aver­age dur­ing the 202223 heat­ing sea­son and totaled 32 bcm; alto­geth­er, net stor­age with­drawals met around 15% of EU gas demand over the 202223 heat­ing. These aver­age val­ues hide the crit­i­cal role of gas stor­age in ensur­ing gas sup­ply ade­qua­cy dur­ing peak days: stor­age met over 40% of EU gas demand dur­ing the cold­est win­ter days in ear­ly Decem­ber 2022 and late Jan­u­ary 2023. EU stor­age sites closed the 202223 heat­ing sea­son 55% full and with inven­to­ry lev­els stand­ing 67% (or 22 bcm) above their five-year average.
  • In the US, stor­age sites were 80% full at the begin­ning of Novem­ber, well aligned with their five-year aver­age. Unsea­son­ably mild weath­er con­di­tions com­bined with a strong increase in domes­tic pro­duc­tion reduced stor­age with­drawals. Net stor­age with­drawals stood almost 30% (or 15 bcm) below their five-year aver­age dur­ing Octo­ber 2022-March 2023, and met approx­i­mate­ly 7% of US gas demand dur­ing this peri­od. As a con­se­quence of below aver­age draw on stor­age, US stor­age sites closed the 202223 heat­ing sea­son 43% full, stand­ing 20% (or 12 bcm) above their five-year average.

Gas prices mod­er­at­ed sig­nif­i­cant­ly dur­ing the 202223 win­ter attrib­ut­able to unsea­son­ably mild weath­er, low­er gas demand and improv­ing sup­ply fundamentals

  • In Europe, Title Trans­fer Facil­i­ty (TTF) spot prices aver­aged $23/​MMbtu dur­ing the 202223 heat­ing sea­son – almost 30% below the lev­els expe­ri­enced in the pre­vi­ous win­ter. Gas prices on the TTF declined by almost 70% between mid-Decem­ber 2022 and the end of March 2023.
  • In the Unit­ed States, Hen­ry Hub prices aver­aged $4/​MMbtu in the 202223 heat­ing sea­son, almost 15% below the lev­els expe­ri­enced dur­ing the pre­vi­ous winter.
  • For­ward curves as of the end of April 2023 indi­cate that TTF is set to aver­age $15/​MMbtu in 2023, with Asian spot LNG aver­ag­ing just below $15/​MMbtu and Hen­ry Hub aver­ag­ing $2.6/MMbtu. The price spread between TTF and Asian spot LNG is expect­ed to tight­en sig­nif­i­cant­ly in 2023.

Nat­ur­al gas con­sump­tion for elec­tric­i­ty in the US dur­ing the sum­mer of 2023 is fore­cast­ed to aver­age 38 bcf, sec­ond most on record behind the 39 bcf/​d record­ed last year

  • High demand will be dri­ven by a decline in coal-fired elec­tric­i­ty gen­er­a­tion, rel­a­tive­ly low nat­ur­al gas prices, and more over­all elec­tric­i­ty gen­er­a­tion due to warmer-than-nor­mal temperatures.

At the end of April, US nat­ur­al gas stor­age inven­to­ries totaled 2,114 bcf, 19% more than the five-year aver­age. The fore­cast for nat­ur­al gas inven­to­ries is expect­ed to increase by 1,648 bcf from the end of April to reach 3,762 bcf at the end of Octo­ber, 4% more than the five-year average

  • The Hen­ry Hub nat­ur­al gas spot price is fore­cast­ed to aver­age $2.35/MMbtu in May and rise to around $3.00/MMbtu in July and August, when pow­er demand peaks.

Ener­gy Tran­si­tion Overview


The Inter­na­tion­al Renew­able Ener­gy Agency’s (IRE­NA) 1.5°C path­way posi­tions elec­tri­fi­ca­tion and effi­cien­cy as key dri­vers of the ener­gy tran­si­tion, enabled by renew­ables, hydro­gen, and sus­tain­able biomass

  • This path­way, which requires a mas­sive change in how soci­eties pro­duce and con­sume ener­gy, would result in a cut of near­ly 37 giga­tons (Gt) of annu­al CO2 emis­sions by 2050.11 Cur­rent ener­gy demand fore­cast do not include sub­stan­tial addi­tion­al pow­er needs to sup­port AI
  • Renew­ables-based elec­tric­i­ty is now the cheap­est pow­er option in most regions. The glob­al weight­ed-aver­age lev­elized cost of elec­tric­i­ty from new­ly com­mis­sioned util­i­ty-scale solar pho­to­volta­ic (PV) projects fell by 85% between 2010 and 2020. The cor­re­spond­ing cost reduc­tions for con­cen­trat­ed solar pow­er (CSP) were 68%; onshore wind, 56%; and off­shore wind, 48%.
  • Decar­boniza­tion of end uses is the next fron­tier, with many solu­tions pro­vid­ed through elec­tri­fi­ca­tion, green hydro­gen and the direct use of renew­ables. Despite good glob­al progress in deploy­ment of renew­ables in the pow­er sec­tor, the end use sec­tors have lagged, with indus­tri­al process­es and domes­tic heat­ing still heav­i­ly reliant on fos­sil fuels. In the trans­port sec­tor, oil con­tin­ues to dom­i­nate. In these sec­tors, deep­er pen­e­tra­tion of renew­ables, expand­ed elec­tri­fi­ca­tion and improve­ments in ener­gy effi­cien­cy can play a cru­cial role in alle­vi­at­ing con­cerns about prices and secu­ri­ty of supply.

To ful­fil the 1.5°C Sce­nario the elec­tric­i­ty sec­tor will have to be thor­ough­ly decar­bonized by mid-century

  • A port­fo­lio of projects in gen­er­a­tion and grid infra­struc­ture will have to be set up in this decade to begin a pipeline for con­tracts over the ensu­ing decades to 2050. What is need­ed is an annu­al aver­age of at least 800 GW of new renew­able capac­i­ty addi­tions each year through 2030, up from around 264 GW added in 2020. The installed gen­er­a­tion capac­i­ty of renew­able pow­er will need to expand to 10,770 GW in 2030 and close to 27,800 GW by 2050, a four-fold and ten-fold increase by 2030 and 2050, respec­tive­ly, over the 2020 level.
  • Decar­boniza­tion of end uses is the next fron­tier, with many solu­tions pro­vid­ed through elec­tri­fi­ca­tion, green hydro­gen and the direct use of renew­ables. Despite good glob­al progress in deploy­ment of renew­ables in the pow­er sec­tor, the end use sec­tors have lagged, with indus­tri­al process­es and domes­tic heat­ing still heav­i­ly reliant on fos­sil gas. In the trans­port sec­tor, oil con­tin­ues to dom­i­nate. In these sec­tors, deep­er pen­e­tra­tion of renew­ables, expand­ed elec­tri­fi­ca­tion and improve­ments in ener­gy effi­cien­cy can play a cru­cial role in alle­vi­at­ing con­cerns about prices and secu­ri­ty of supply.
  • Again, solar PV and wind will lead the way. The installed capac­i­ty of solar PV pow­er will exceed 5,200 GW by 2030; wind instal­la­tions will pass 3,300 GW by 2030. Coal-fired gen­er­a­tion will drop sharply over the decade, its share in total elec­tric­i­ty gen­er­a­tion falling from 37% in 2019 to 11% in 2030, before being phased out entire­ly by 2050. Nat­ur­al gas will pro­vide 16% of total elec­tric­i­ty needs in 2030, com­pared with 24% in 2019. Nuclear-fueled gen­er­at­ing capac­i­ty will hold steady at around 10% of total installed capacity.

All types of renew­able pow­er gen­er­a­tion capac­i­ty must be scaled up in all regions to meet the 1.5°C target

  • Asia, North Amer­i­ca, and Europe will account for more than 80% of instal­la­tions by 2030. Asia needs to scale up four times to reach more than 5,400 GW of renew­able capac­i­ty by 2030, while North Amer­i­ca and Europe will have to ramp up instal­la­tions by around five-fold and three-fold, respec­tive­ly. The scal­ing fac­tors for the Mid­dle East and Africa are even greater.
  • Wind will be one of the largest gen­er­a­tion sources by 2030, sup­ply­ing 24% of total elec­tric­i­ty needs. Asia will almost cer­tain­ly dom­i­nate the glob­al onshore mar­ket by 2030, with annu­al wind addi­tions of 142 GW dur­ing this decade. North Amer­i­ca and Europe also have con­sid­er­able poten­tial to pro­mote capac­i­ty expan­sion. In this decade, the 1.5°C path­way to 2050 requires annu­al instal­la­tions in these regions of more over 40 GW and 20 GW, respec­tive­ly. Latin Amer­i­ca will have to add 12 GW each year; Oceania/​Pacific more than 2 GW; the Mid­dle East and Africa, more than 8 GW.
  • The installed capac­i­ty of solar PV is expect­ed to increase sev­en-fold by 2030 (to near­ly 5,200 GW) and twen­ty-fold by 2050 to exceed 14,000 GW. Over the past decade, Asia added 40 GW of solar PV each year – and near­ly 80 GW in 2020. With annu­al addi­tions of 210 GW expect­ed through 2030, Asia will con­tin­ue to dom­i­nate the mar­ket, with expan­sions con­cen­trat­ed in India and Chi­na. The region will account for rough­ly 50% of the globe’s installed solar PV capac­i­ty in 2030. Like Asia, Europe and North Amer­i­ca dou­bled their solar PV instal­la­tions in 2020 over the aver­age lev­els in the pre­vi­ous decade. The two regions are expect­ed to account for 19% and 14%, respec­tive­ly, of glob­al solar PV instal­la­tions by 2030.

Glob­al invest­ment in ener­gy tran­si­tion tech­nolo­gies, includ­ing ener­gy effi­cien­cy, reached a record high of $1.3 T in 2022; how­ev­er, annu­al invest­ments need to at least quadru­ple to remain on track to achieve the 1.5°C Sce­nario in IRENA’s World Ener­gy Tran­si­tions Out­look 2023

  • Invest­ment in renew­able ener­gy was also unprece­dent­ed – at $0.5 T – but rep­re­sent­ed less than one third of the aver­age invest­ment need­ed each year. Invest­ments are also not flow­ing at the pace or scale need­ed to accel­er­ate progress towards uni­ver­sal ener­gy access. More­over, invest­ments have become fur­ther con­cen­trat­ed in spe­cif­ic tech­nolo­gies and uses, and in a small num­ber of countries/​regions. More than 50% of the world’s pop­u­la­tion, most­ly resid­ing in devel­op­ing and emerg­ing coun­tries, received only 15% of glob­al invest­ments in 2022. The dis­par­i­ty in renew­able ener­gy financ­ing received by devel­oped ver­sus devel­op­ing coun­tries has increased sig­nif­i­cant­ly over the past six years. For exam­ple, the renew­able ener­gy invest­ment per capi­ta in Europe and North Amer­i­ca (exclud­ing Mex­i­co) was almost 23 times high­er than that in Sub-Saha­ran Africa in 2015. In 2021, invest­ment per capi­ta in Europe was 41 times that in Sub-Saha­ran Africa, and in North Amer­i­ca it was 57 times more.

Achiev­ing an ener­gy tran­si­tion in line with the 1.5°C Sce­nario requires the redi­rec­tion of $1 T per year from fos­sil fuels to ener­gy-tran­si­tion-relat­ed tech­nolo­gies; but fos­sil fuel invest­ments are still on the rise

  • Invest­ment in new oil and gas devel­op­ment is esti­mat­ed to aver­age $570 B annu­al­ly until 2030.
  • Fos­sil fuel com­pa­nies based in emerg­ing mar­kets and devel­op­ing economies have con­tin­ued to attract sub­stan­tial vol­umes of financ­ing. Between 2016 and 2022, their out­stand­ing debt rose by 400% for coal and 225% for oil and gas, despite the need to align invest­ments with the goals out­lined in the Paris Agree­ment. In Africa, cap­i­tal expen­di­tures for oil and gas explo­ration rose from $3.4 B in 2020 to $5.1 B in 2022. Fos­sil fuel sub­si­dies con­tin­ue, and in 2020, Europe was the region pro­vid­ing the most sub­si­dies, which were expand­ed dur­ing the ear­ly 2022 nat­ur­al gas price spike.

Although renew­able ener­gy invest­ments are on the rise glob­al­ly, they are increas­ing­ly focused in cer­tain regions

  • Chi­na leads in East Asia and Pacif­ic region aid­ed by a suite of poli­cies includ­ing tax exemp­tions have dri­ven invest­ments in solar and wind, putting the coun­try on track to meet­ing the tar­gets set out in the 14th Five-Year Plan.
  • North Amer­i­ca exclud­ing Mex­i­co attract­ed the sec­ond-largest share of invest­ment in 2022, main­ly dri­ven by the pro­duc­tion tax cred­it in the Unit­ed States. The 2022 Infla­tion Reduc­tion Act (IRA) – encom­pass­ing new tax cred­its, $30 B in grants and loans for clean ener­gy gen­er­a­tion and stor­age, and $60 B in sup­port of man­u­fac­tur­ing of low-car­bon com­po­nents – is expect­ed to attract $114 B invest­ment by 2031.
  • Europe’s growth in renew­able invest­ments is dri­ven by its net-zero com­mit­ments and exten­sive poli­cies such as those pro­posed in the Green Deal Indus­tri­al Plan for the Net-Zero Age, which looks to mobi­lize €225 B in loans from its exist­ing Recov­ery and Resilience Facil­i­ty, and an addi­tion­al €20 B in grants.

Elec­tric­i­ty gen­er­a­tion from renew­able sources is fore­cast­ed to rise from 22% in 2022 to 23% in 2023 and to 26% in 2024

  • Low­er oper­at­ing costs sup­port a dis­patch advan­tage over fos­sil fuel-fired pow­er plants.
  • Coal use reduc­tion dri­ven by gen­er­at­ing plant retire­ments (11 GW sched­uled in 2023), low nat­ur­al gas prices, and more renew­able generation.
  • The IRA and oth­er gov­ern­ment poli­cies are sharply expand­ing efforts to decar­bonize elec­tric gas supply.

Nuclear pow­er has avoid­ed about 66 Gt of CO2 emis­sions over the past 50 years, con­cen­trat­ed in long-time mar­ket leaders

  • With­out nuclear pow­er, pow­er sec­tor CO2 emis­sions in advanced economies would have been 20% high­er over the past 50 years, led by the Unit­ed States and Euro­pean Union. Emerg­ing mar­ket and devel­op­ing economies have recent­ly seen strong growth in nuclear pow­er, led by Chi­na and India, help­ing to cut some 9 Gt of emis­sions to date.
  • In 2021 nuclear pow­er capac­i­ty declined by almost 3 GW glob­al­ly, as new­ly com­plet­ed reac­tors were not able to com­pen­sate for over 8 GW of retire­ments. Emerg­ing mar­ket and devel­op­ing economies account­ed for all the new capac­i­ty while the major­i­ty of these per­ma­nent shut­downs were in Ger­many, the Unit­ed King­dom and the Unit­ed States, which are all G7 members.
  • To get on track with the Net Zero Sce­nario, glob­al nuclear capac­i­ty would need to expand by about 10 GW per year to 2030. Pri­or­i­tiz­ing life­time exten­sions in G7 mem­bers would bol­ster the low-emis­sions foun­da­tion in place and make the most of new nuclear capacity.
  • The ambi­tions reflect­ed in net zero tar­gets have encour­aged inno­va­tion in nuclear pow­er tech­nolo­gies, such as small mod­u­lar reac­tors (SMRs), which have a small­er size of under 300 MW per reac­tor, down to 10 MW. SMRs hold the promise of being more afford­able, and eas­i­er and faster to build than con­ven­tion­al large reac­tors. Close to 70 designs are cur­rent­ly under devel­op­ment. SMRs can poten­tial­ly be fac­to­ry-built and trans­port­ed to the final loca­tion, short­en­ing project time­lines and poten­tial­ly reduc­ing con­struc­tion risk and financ­ing costs. As pow­er sys­tems decar­bonize and solar and wind shares increase, SMRs could become a key­way to meet ris­ing flex­i­bil­i­ty needs in pow­er gen­er­a­tion. They can also be used for heat and hydro­gen production.


1. EIA – Short-Term Ener­gy Out­look – May 2023

2. Thom­son Reuters

3. IEA – Oil Mar­ket Report – May 2023

4. IEA – Gas Mar­ket Report – Q2 2023

5. IEA – Oil 2023 – Analy­sis and Fore­cast to 2028 – June 2023

6. Amer­i­can Oil and Gas Reporter

7. EIA – Drilling Pro­duc­tiv­i­ty Report – May 15, 2023

8. Reuters – Glob­al refin­ers fal­ter in efforts to keep up with demand

9. EIA – Petro­le­um & Oth­er Liq­uids

10. IEA – Ener­gy Prices – Month­ly Oil Prices Excerpt

11. IRE­NA – World Ener­gy Tran­si­tions Out­look 2022: 1.5oC Path­way

12. IRE­NA – Inter­na­tion­al Renew­able Ener­gy Agency – Renew­able Ener­gy Finance 2023

13. IEA – Nuclear Elec­tric­i­ty – Sep­tem­ber 2022

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