Prisene på naturgass er på 19 måneder høye: Hva betyr det 21. september 2016 slo aktive naturgass futures høyest på 3,06 på sluttkurs grunnlagets høyeste nivå siden januar 2015. Hvorfor er prisene på naturgass økende Stigningen i naturlig gass kan tilskrives rekordhøye temperaturer. Dette førte til økt etterspørsel etter naturgass ved gassfyrte kraftverk for å tilfredsstille kjøleefterspørselen. Den naturlige gastargeted boreaktiviteten har vært svak. Godt diskutere naturgass og råolje rigger i neste del. Markedet forventer også at gapet mellom de nåværende lagernivåene og historiske gjennomsnitt for å lukke. Nå diskutere dette i detalj i del 3. Naturgassopplysninger I fjor var naturgassbruk for oppvarming svak på grunn av mildt vær. Som et resultat var prisene svake. I slutten av mars 2016 var amerikanske naturgassbeholdninger på 2,5 billioner kubikkmeter67 høyere enn nivåene i 2015 og 53 høyere enn gjennomsnittet på fem år. Naturgass futures rammet en 2016 og 17-årig lav på 1,64 på 3. mars. VVM (US Energy Information Administration) prosjekterer at naturgassinventarene vil bli 4.042,4 Bcf (milliarder kubikkfot) i slutten av oktober 2016. Dette ville være høyeste nivå på rekord i slutten av oktober. I løpet av uken som sluttte 2. september, var naturgassbeholdningen på 3 377 Bcf10 høyere enn gjennomsnittet på fem år og 6 høyere enn nivået i fjor. Netto glidende gjennomsnitt Den 21. september var naturgass futures trading 17,8 over deres 100-dagers glidende gjennomsnitt og 6,7 over deres 20-dagers glidende gjennomsnitt. Dette indikerer bullishiteten i naturgasspriser. Ovennevnte graf viser prisutviklingen for naturgass futures i forhold til sentrale glidende gjennomsnitt. Naturgassensen påvirker også ETFer som ProShares Ultra Oil Amp Gas ETF (DIG), PowerShares DWA Energy Momentum Portfolio (PXI), Vanguard Energy ETF (VDE), iShares US Energy ETF (IYE) og Fidelity MSCI Energy Index ETF (FENY). I neste del av denne serien diskuterer du røntgenriggen. Vel, se hvordan det påvirker naturgassproduksjonen og prisene. Hva koster naturgassprisene Høyere Den 1. juli slo aktive naturgass futures en 2016 høyde på 2,99 høyeste nivå siden mai 2015, til sluttkurs. For tiden er naturgass 5 under 2016 høy. Hvorfor naturgasspriser falt tidlig i 2016 I vinter var naturgassbruk for oppvarming svak på grunn av mildt vær. Som et resultat var prisene svake. I slutten av mars 2016 var amerikanske naturgassbeholdninger på 2,5 billioner kubikkmeter67 høyere enn nivåene i 2015 og 53 høyere enn gjennomsnittet på fem år. Naturgass futures slo en 2016 og 17-årig lav på 1,64 på 3. mars. Nøkkelen beveger seg i gjennomsnitt 8,3 over deres 100-dagers glidende gjennomsnitt og 3,3 over 20-dagers glidende gjennomsnitt. Prisene på naturgass brøt seg over deres 20-dagers glidende gjennomsnitt 23. august. Dette indikerer kortsiktig bullishness i naturgasspriser. Ovennevnte graf viser prisutviklingen for naturgass futures i forhold til sentrale glidende gjennomsnitt. Naturgassensen påvirker også ETFer som ProShares Ultra Oil Amp Gas ETF (DIG), PowerShares DWA Energy Momentum Portfolio (PXI), Vanguard Energy ETF (VDE), iShares US Energy ETF (IYE) og Fidelity MSCI Energy Index ETF (FENY). I neste del av denne serien diskuterer du røntgenriggen. Vel, se hvordan det påvirker naturgassproduksjon og priser. U. S. Energi Informasjonsadministrasjon - VVM - Uavhengig Statistikk og Analyse Internasjonal Energi Utsikt 2016 Kapittel 3. Naturgass Forbruket av naturgass over hele verden forventes å øke fra 120 billioner kubikkfot (TCF) i 2012 til 203 Tcf i 2040 i International Energy Outlook 2016 ( IEO2016) Referansesaker. Av energikilde står naturgass for den største økningen i verdens primære energiforbruk. Rikelig naturgassressurser og robust produksjon bidrar til den sterke konkurranseposisjonen for naturgass blant andre ressurser. Naturgass forblir et nøkkelbrensel i elkraft og i industrisektoren. I kraftsektoren er naturgass et attraktivt valg for nye generatorer på grunn av drivstoffeffektiviteten. Naturgass brenner også renere enn kull eller petroleumsprodukter, og etter hvert som flere regjeringer begynner å implementere nasjonale eller regionale planer om å redusere utslipp av karbondioksid, kan de oppmuntre til bruk av naturgass for å forflytte mer karbonintensive kull og flytende brensel. Verdenskonsumet av naturgass til industriell bruk øker med i gjennomsnitt 1,7 år, og naturgassforbruket i elsektoren øker med 2,2 år, fra 2012 til 2040 i IEO2016-referansesaken. Industrisektoren og elektrisitetssektoren står sammen for 73 av den totale økningen i verdensforbruket av naturgass, og de står for rundt 74 av totalt naturgassforbruk gjennom 2040. Forbruket av naturgass øker i alle IEO-regioner, med etterspørsel i nasjoner utenfor Organisasjonen for økonomisk samarbeid og utvikling (ikke-OECD) øker mer enn dobbelt så fort som i OECD (Figur 3-1). Den sterkeste veksten i naturgassforbruket er projisert for landene i OECD Asia, der økonomisk vekst fører til økt etterspørsel. Naturgassforbruket i ikke-OECD-regionen vokser med i gjennomsnitt 2,5 år fra 2012 til 2040, sammenlignet med 1,1 år i OECD-landene. Som et resultat står ikke-OECD-land for 76 av verdensøkonomien i naturgassforbruket, og deres andel av verdens naturgassbruk vokser fra 52 i 2012 til 62 i 2040. figurdata For å møte den stigende etterspørselen etter naturgass som forventes i IEO2016 Referansesaken, verdensomsyns naturgassprodusenter øker forsyningene med nesten 69 fra 2012 til 2040. De største økninger i naturgassproduksjon fra 2012 til 2040 forekommer i ikke-OECD Asia (18,7 Tcf), Midtøsten (16,6 Tcf), og OECD Americas (15,5 Tcf) (Figur 3-2). Kun i Kina øker produksjonen med 15,0 Tcf da landet utvider utviklingen av sine skiferressurser. USA og Russland øker naturgassproduksjonen med henholdsvis 11,3 Tcf og henholdsvis 10,0 Tcf. I Russland støttes produksjonsveksten først og fremst ved å øke ressursutviklingen i countryrsquos arktiske og østlige regioner. USAs produksjonsvekst kommer hovedsakelig fra skiferressurser. Total naturgassproduksjon i Kina, USA og Russland står for nesten 44 av den totale økningen i verdens naturgassproduksjon. figurdata Selv om det er mer å lære om omfanget av verdensomspennende stramme gass-, skifergass - og kullsyre-metanressursbas, vil IEO2016 Reference-saken utvide en betydelig økning i disse forsyningene, spesielt i Kina, USA og Canada (Figur 3- 3). Anvendelsen av horisontale boring og hydraulisk fraktureringsteknologi har gjort det mulig å utvikle den amerikanske skifergassressursen, noe som bidrar til en nesten dobling av estimater for totale amerikanske teknisk gjenvinnbare naturgassressurser i løpet av det siste tiåret. Skifer gass står for mer enn halvparten av USAs naturgassproduksjon i IEO2016 Reference saken, og tett gass-, skifergass - og kullsyre-metanressurser i Canada og Kina står for rundt 80 av totalproduksjonen i 2040 i disse landene. figurdata Flytende naturgass (LNG) står for en økende andel av verdens naturgasshandel i referansesaken. World LNG-handel handler mer enn dobler, fra om lag 12 tcf i 2012 til 29 tcf i 2040. Det meste av økningen i flytende kapasitet oppstår i Australia og Nord-Amerika, hvor en rekke nye flytforbedringsprosjekter er planlagt eller under bygging, hvorav mange vil bli operativ innen det neste tiåret. Samtidig har eksisterende anlegg i Nord-Afrika og Sørøst-Asia vært underutnyttet eller slått av på grunn av produksjonen avtar på mange av de eldre feltene som er knyttet til flytende anlegg, og fordi det er høyt verdsatt inntekt for naturgass i eksporten. OECDs naturgassforbruk OECD Americas Årlig naturgassforbruk i OECD Americas-regionen stiger jevnt til 40,1 Tcf i 2040 (figur 3-4), inkludert økninger på 1,0 tcf fra 2012 til 2020 (0,4 år) og 7,3 tcf fra 2020 til 2040 ( 1.0year). OECD Americas-regionen står for 41 av den totale økningen i naturgassbruk fra OECD-landene og 13 av økningen i verdensomspennende naturgassforbruk over prognoseperioden. figurdata United States8212 verdens største forbruker av naturgass8212 fører til OECD Americas-regionen i årlig vekst i naturgassforbruket med en økning på 4,2 Tcf fra 2012 til 2040, eller 51 av totaløkningen i regionrsquos (figur 3-5). Selv om de nylig avsluttede Clean Power Plan-reglene (CPP) i USA ikke er inkludert i IEO2016 Reference-saken, vurderes effektene i diskusjoner, tabeller og figurer gjennom rapporten, basert på tidligere analyse fra USAs energiforvaltningsinformasjon (EIA) av den foreslåtte regelen som har lignende elementer. Ved implementering av den foreslåtte CPP ville USAs naturgassforbruk være 1,7 Tcf høyere i 2020 sammenlignet med IEO2016 Reference-saken. Mesteparten av økningen i naturgassforbruket vil forekomme i elkraftsektoren som en erstatning for kullfyrte generasjoner. Etter 2020 reduseres effekten av CPP på naturgassbruk i kraften som generasjon fra fornybar energiøkning. I 2040 er det forventede amerikanske naturgassforbruket 1,0 Tcf lavere med CPP enn i IEO2016 Reference-saken. Effekter av den endelige CPP på naturgassfyrt generasjon vil avhenge av naturgasspriser, fornybare teknologikostnader og vedtak på statsnivå. En økning i naturgassbruk gjennom 2040 er sikkert mulig i scenarier med lave gasspriser og implementeringsstrategier som favoriserer gass. Figurdata Prognoser for kombinert årlig naturgassforbruk i Mexico og Chile inkluderer absolutt vekst i de to landene på 2,2 Tcf (26 av OECD Americas totale økning), etterfulgt av Canada med 1,9 Tcf (23 av OECD Americas Total Increase). I økende grad har Mexico møtt sin økende etterspørsel etter elektrisitet med generering fra naturgassfyrte enheter, ved hjelp av naturgass importert av rørledning fra USA, spesielt siden 2011, da veksten i Mexicorsquos samlede naturgassforbruk har oversteget den innenlandske produksjonsveksten. I IEO2016-referansesaken utgjør elektrisitetssektoren 39 (3,2 Tcf) av veksten i naturgassforbruket fra 2012 til 2040 i OECD Americas-regionen, med 1,6 Tcf av økningen som skjer i Mexico og Chile og 1,3 Tcf i Canada . Naturgassbruk i OECD Americas industrisektoren vokser med 1,4 Tcf fra 2012 til 2020, med 1,3 Tcf (97) tilført i USA, der industrielt forbruk øker med i gjennomsnitt 1,8 år. Veksten i naturgassbruk i den amerikanske industrisektoren minker noe fra 2020 til 2040 i gjennomsnitt 0,5 år og øker med i alt 1,0 Tcf over denne perioden. I Canada vokser naturgassforbruket i industrisektoren med i gjennomsnitt 0,2 år fra 2012 til 2020 og med 1,1 år fra 2020 til 2040. I MexicoChile-regionen vokser bruk av industrisektoren naturgass i gjennomsnitt på 0,1 år fra 2010 til 2020 og 1,2 år fra 2020 til 2040. OECD Europe Naturgassforbruket i OECD Europe-regionen vokser med gjennomsnittlig 1,3 år, fra 17,8 Tcf i 2012 til 25,3 Tcf i 2040 i Referansesaken (Figur 3-6), med elektrisk kraft sektor regnskap for mer enn halvparten (4,6 tcf) av den totale økningen. Den gjennomsnittlige økningen på 3,6 år i naturgassforbruk for kraftproduksjon fra 2020 til 2040 er høyere enn for enhver annen energikilde som brukes i sektoren. Andelen naturgass i kraftproduksjonsblandingen forventes å vokse, da eldre kjernefysiske og kullfyrte enheter gradvis vil bli avviklet og erstattet primært av ny naturgassfyrt og fornybar kapasitet. figurdata Naturgasspriser i Asia På asiatiske markeder, i motsetning til de i USA, reflekterer naturgasspriser typisk kontrakter som er indeksert til priser på råolje eller petroleumsprodukter. Nedgangen i råoljeprisene mellom august 2014 og januar 2015 og lave oljepriser siden da (figur 3-7) hadde en betydelig effekt på asiatiske naturgasspriser og markeder. Men asiatiske land utvikler regionale handelshubber for å sette naturgasspriser som bedre reflekterer naturgassmarkedsdynamikken. I 2014 skjedde nesten 30 av verdenshandelen i LNG på kort sikt 54 eller spot. Asiatiske land utgjorde tre fjerdedeler av den totale og en tredjedel av den globale naturgasshandelen 55. Høye råoljepriser fra 2011 til 2014 resulterte i høyere priser på LNG-import. I Asia importeres mest naturgass som LNG, med LNG-priser som tradisjonelt er indeksert til råolje på langsiktig, kontraktsbasis. figurdata For tiden er det ikke et globalt integrert marked for naturgass, og prismekanismer varierer fra region til marked. I de fleste tilfeller er internasjonal handel med naturgass indeksert til råoljeprisene, som for eksempel Nordsjøbrent eller Japan-tollklarert råstoff (JCC), på grunn av likviditeten og gjennomsiktigheten av råoljeprisene og substituerbarheten av naturgass og petroleumsprodukter i noen markeder. For eksempel har noen asiatiske land muligheten til å forbrenne enten naturgass eller petroleum til elektrisitetsproduksjon. Selv om langsiktige kontrakter indeksert til råoljeprisene fortsatt er Asiarsquos overordnede prismekanisme, begynner naturgass i engangstransaksjoner på spotmarkedet eller under kortsiktige kontrakter som nærmere reflekterer internasjonal naturgassforsyning og etterspørsel . Kortsiktig og spot LNG-handel i Asia Pacific-markedet var nesten tredoblet fra 2010 til 2014 (figur 3-8), da den representerte 21 av verdens LNG-handel og 7 av naturgasshandel. figurdata Flere asiatiske landesamfunn, inkludert Japan, Kina og Singapore8212 utvikler regionale handelshubs med sikte på å øke prisdannelsens gjennomsiktighet: I september 2014 lanserte Japan en LNG-futureskontrakt på Japans over-the-counter-utveksling (JOE), avgjort mot Rim Intelligence Co. Daglig prisindeks. Imidlertid er det bare en handel på JOE siden starten. Landets mangel på rørledningstilkobling med andre markeder, lave volumer fleksibel LNG og mangel på LNG-pris gjennomsiktighet og likviditet har begrenset LNG-handelsaktivitet på JOE. I juni 2015 lanserte Singapore Stock Exchange Singapore SGX LNG Index Group (SLInG). Indeksen vil gi priser utenom bord (unntatt fraktkostnader) for LNG-laster fra Singapore til forskjellige destinasjoner som reflekterer regionale spotpriser. Fra og med juni 2015 hadde 13 markedsaktører registrert seg for å delta i indeksen, og ytterligere 10 ventet å bli med, men handelsvolumene til dags dato har vært moderate. Den 1. juli 2015 lanserte Kina Shanghai Olje - og gassutveksling, som vil handle både rørledning gass og LNG. Chinarsquos diversifiserte naturgassmarked, med utvidet rørledningsinfrastruktur og gass-til-gass konkurranse, kan tilby en mer flytende asiatisk naturgassprisindeks, men høye nivåer av offentlig regulering gjør det mindre attraktivt som et regionalt referanseindeks. I Europa, hvor naturgass importeres både etter rørledning og som LNG, blir naturgasspriser enten indeksert til råoljepris eller basert på spotmarkedet. Selv om det meste av handel i Europa er basert på langsiktige kontrakter, har navbasert spothandel økt betydelig det siste tiåret. De primære referanseprisene for spot trading er Nasjonal Balansepunkt (NBP) i Storbritannia og Tittel Transfer Facility (TTF) i Nederland. NBP - og TTF-prisene har stor innflytelse på navpriser i andre europeiske markeder på grunn av likviditet og sammenkobling med det kontinentale Europa. Andre handelshubber i det kontinentale Europa vokser når det gjelder handlet volumer og antall nav og deltakere. Med de økende volumene og likviditeten i de europeiske knutepunktene, begynner navneprisene å spille en større rolle. Noen nyere rørledningskontrakter i kontinentaleuropa inkluderer nå en navbasert pris, i stedet for en tradisjonell kobling til en kurv med råoljeprodukter. Prisene på Henry Hub, USAs naturgassmarkering, kan også påvirke global prising gjennom LNG-handel. I løpet av 2020, når alle dagens amerikanske flytforbedringsprosjekter forventes å bli fullført, vil USA utgjøre nesten en femtedel av global flytekapasitet og vil ha den tredje største LNG-eksportkapasiteten i verden (etter Qatar og Australia). Nesten 80 av amerikanske LNG-eksportvolumer for prosjekter som for tiden er under bygging, er blitt inngått på prisbetingelser direkte knyttet til Henry Hub-prisen, eller under en hybridprismekanisme med lenker til Henry Hub. Fleksibiliteten til bestemmelsesklausuler i amerikanske LNG-eksportkontrakter og innføring av navindekser forventes å fremme større likviditet i global LNG-handel, skifteprisering vekk fra oljebaserte indekser og bidra til utvikling av asiatiske regionale handelsnavne og prisindekser. Naturgassforbruket i OECD Asia vokser med i gjennomsnitt 1,6 år i IEO2016-referansesaken, fra 7,9 Tcf i 2012 til 12,2 Tcf i 2040, mens Japanrsquos forbruk øker med i gjennomsnitt 0,9 år. Japan har hovedsakelig støttet seg på kortsiktige og spotgodsforsendelser av LNG for å kompensere tapet av atomgenereringskapasitet da en stor del av sin kjernefysiske generasjonskapasitet ble stengt etter at Fukushima Daiichi kraftreaktorer var alvorlig skadet av jordskjelvet og tsunamien i mars 2011 . Alle sammen med 2 av countryrsquos 50-reaktorene forblir frakoblet fra januar 2016 56, og miljøhensyn har ført til at regjeringen oppfordrer naturgassforbruket, noe som gjør LNG til et valg av drivstoff for kraftproduksjon som erstatning for den tapt atomgenerering. I henhold til International Gas Union opererte Japan 23 store LNG-importterminaler i 2014, inkludert utvidelser og satellitterminaler, med en samlet gassutslippskapasitet på 9 Tcfyear som ligger langt over etterspørselen 57. Fra 2020 til 2040 øker Japanrsquos reall BNP med et gjennomsnitt på 0,5 år, langt den laveste i regionen, som et resultat av den fallende befolkningen og aldringsarbeidskraften. Selv om Japanrsquos naturgassforbruk ikke går sakte mellom 2020 og 2040, reduseres forbruket av energi fra væsker og kull. Som følge av dette øker naturgassandelen til Japanrsquos totale energiforbruk fra 25 i 2020 til nesten 30 i 2040. Sør-Koreas naturgassforbruk vokser med gjennomsnittlige priser på 2,3 år fra 2012 til 2020 og 1,7 år fra 2020 til 2040 i IEO2016 Referansesaker. Veksten i etterspørselen etter naturgass i Sør-Koreas industri-, bolig - og næringsliv senker, mens den er i elkraftsektoren, forblir over 2 år gjennom perioden 2012821140. Australia og New Zealand har OECD Asias sterkeste gjennomsnittlige årlige vekst i naturgassforbruket i elektrisitetssektoren fra 2012 til 2040 i IEO2016 Reference-saken, i gjennomsnitt 4,6 år og mer enn tredobling, fra 0,4 Tcf i 2012 til 1,5 Tcf i 2040 (Figur 3-9 ). Australia øker andelen naturgass i sin kraftproduksjonsblanding for å redusere sin mer karbonintensive kullfyrte generasjon. De to landenes samlede andel av OECD Asiarsquos totale naturgassbruk for kraftproduksjon vokser fra 10 i 2012 til 21 i 2040 i IEO2016-referansesaken. figurdata Ikke-OECD-naturgassforbruk Ikke-OECD-Europa og Eurasia Landene i OECD Europa og Eurasia var avhengig av naturgass for 47 av deres primære energibehov i 2012 som den nest høyeste i et hvilket som helst land som grupperer i IEO2016, etter Midtøsten. Ikke-OECD Europa og Eurasia forbruker totalt 23,0 Tcf naturgass i 2012, den mest utenfor OECD og mer enn noen annen region i verden unntatt OECD Americas. Russiarsquos 15,7 Tcf av naturgassforbruket i 2012 utgjorde 68 av ikke-OECD Europe og Eurasia regionrsquos totalt (figur 3-10). figurdata I IEO2016-referansesaken vokser det totale naturgassforbruket i ikke-OECD Europa og Eurasia i gjennomsnitt 0,4 år fra 2012 til 2040, inkludert en nedgang på 0,3 år fra 2012 til 2020 og en økning på 0,7 år fra 2020 til 2040, for en total økning på 2,9 Tcf i perioden 2012821140. Med Russland står kun om lag 10 av regionrsquos totale økning, er gjennomsnittlig økning for resten av ikke-OECD Europa og Eurasia-regionen 1,1 år, sammenlignet med Russias gjennomsnitt på 0,1 år. I elektrisitetssektoren faller naturgassforbruket med et gjennomsnitt på 0,1 år fra 2012 til 2040 i Russland, ettersom veksten i den totale energiforbruket avtar, men vokser med i gjennomsnitt 1,4 år i regionens andre land. Ikke-OECD Asia Blant alle verdens regioner er den raskeste veksten i naturgassforbruket i IEO2016-referansesaken i ikke-OECD Asia. Naturgassbruk i ikke-OECD Asia øker med i gjennomsnitt 4,4 år, fra 15,1 Tcf i 2012 til 50,8 Tcf i 2040 (Figur 3-11). I løpet av perioden utgjør ikke-OECD Asia mer enn 40 av den totale økningen i verdens naturgassbruk, som går fra sin nåværende posisjon som verdensrsquos fjerde største naturgasskrevende region til den nest største naturgasskrevende regionen i 2030 og den største forbrukeren i 2040. OECD Asiarsquos totale naturgassforbruk øker fra mindre enn halvparten av OECD Americas-regionen i 2012 til mer enn 25 over OECD Americas-summen i 2040, og dens andel av verdensomspennende naturgassforbruk øker fra 13 i 2012 til 25 i 2040. figurdata Kina står for nesten to tredjedeler (63) av veksten i ikke-OECD Asias naturgassforbruk fra 2012 til 2040. Det totale forbruket av naturgass i Kina øker med i gjennomsnitt 6,2 år i IEO2016-referansesaken, fra 5.1 tcf i 2012 til 27,5 tcf i 2040. Chinarsquos sentralregering fremmer naturgass som en foretrukket energikilde og har satt et ambisiøst mål om å øke andelen av naturlig gass i sin samlede energimiks til 10 (eller ca 8,8 tcf) innen 2020 for å lette forurensning fra bruk av tunge kull 58. I IEO2016-referansesaken er naturgassforbruket i Kina totalt 9,1 Tcf i 2020, eller om lag 6 av Countryrsquos totale energiforbruk. I 2040 er naturgassandelen av Chinarsquos energiforbruk 158212 lavere enn coalrsquos 44 andel. Den gjennomsnittlige årlige veksten på 6,2 prosent for naturgassforbruket fra 2012 til 2040 er imidlertid langt under den gjennomsnittlige veksten på 9,7 for kjernekraft. I India utgjorde naturgass ca 8 av totalt energiforbruk i 2012, nesten doblet andelen i Chinas energiblanding. I andre land i ikke-OECD Asia utgjør bruk av naturgass 23 av totalt energiforbruk i 2012, og andelen øker til 25 i 2040 i IEO2016-referansesaken, ettersom naturgassforbruket øker med i gjennomsnitt 2,8 år, fra 7,9 Tcf i 2012 til 17,2 Tcf i 2040. Selv om naturgass forblir den nest største energikilden etter væsker, er den årlige veksten mindre enn satsene på fornybar energi (3,4) og kjernekraft (2,9). Midt-Østen I Midtøsten-området utgjorde naturgass nesten halvparten av det totale energiforbruket i 2012, mer enn i noen annen region. I IEO2016-referansesaken øker naturgassforbruket i Midtøsten med i gjennomsnitt 2,5 år fra 2012 til 2040, og industrisektoren står for den største andelen av regionrsquos totale naturgassforbruk (figur 3-12). Naturgassbruk i industrisektoren vokser med 7,7 Tcf fra 2012 til 2040, og står for over halvparten av den totale økningen i naturgassforbruket på 14,2 Tcf. I elektrisitetssektoren vokser bruk av naturgass med 5,2 Tcf fra 2012 til 2040, når det tilsvarer 9,8 Tcf. Naturgassfyring genererer en del av markedet, ettersom bruken av råolje for kraftproduksjon avtar. figurdata Africas naturgassforbruk tilsvarer 11,1 Tcf i 2040 i IEO2016-referansesaken eller 2,5 ganger totalt 2012 (Figur 3-13). Regionrsquos naturgassbruk øker med gjennomsnittlig 3,3 år fra 2012 til 2040, en hastighet som er den andre kun til den 4.4 årige gjennomsnittlige økningen for kjernekraft i samme periode. Afrikas elkraft og industrisektorer utgjør 79 av økningen i regionene etterspørsel etter naturgass fra 2012 til 2040 og for 84 av total etterspørsel etter naturgass i 2040. Naturgassforbruket i elforsyningssektoren vokser fra 2,2 tcf i 2012 til 5,5 Tcf i 2040, som utgjorde 49 av den totale økningen i Africarsquos naturgassbruk i perioden. Over 85 av økningen i naturgassbruk for kraftproduksjon i Afrika skjer fra 2020 til 2040, når den er gjennomsnittlig 3,6 år sammenlignet med et gjennomsnitt på mindre enn 2,5 år fra 2012 til 2020. Figurdata Ikke-OECD Americas Naturgass Forbruket i OECD Americas-regionen øker med et gjennomsnitt på 2,0 år i IEO2016-referansesaken, fra 5.1 Tcf i 2012 til 8,9 Tcf i 2040 (figur 3-14). Industrisektoren står for mer enn en tredjedel av forbruksveksten fra 2012 til 2040, etterfulgt av elforsyningssektoren på omtrent en fjerdedel. Brazilrsquos naturgassforbruk vokser med gjennomsnittlig 2,6 år fra 2012 til 2040, eller med totalt 1,1 Tcfmdashmore enn 25 av den totale økningen på 3,9 Tcf for ikke-OECD Americas-regionen. Økningen fra 0,7 Tcf i 2012 til 1,4 Tcf i 2040 i Brazilrsquos industrisektorens naturgassforbruk står for over 60 av countryrsquos totale økning i naturgassbruk fra 2012 til 2040. Forbruk av naturgass i både industri og elkraft vokser med ca 2,3 år fra 2012 til 2040, når industrisektoren står for 64 og elsektoren står for 22 av Brazilrsquos totale naturgassforbruk. figurdata Verdens naturgassproduksjon For å møte forventet vekst i naturgassbruk i IEO2016 Reference-saken, øker verdens naturgassforsyninger med nesten 83 Tcf (69) fra 2012 til 2040. Mye av økningen i forsyningen forventes å komme fra ikke - - OECD-landene, som i Reference-saken står for 73 av den totale økningen i verdens naturgassproduksjon fra 2012 til 2040. Produksjonen av ikke-OECD naturgass vokser med gjennomsnittlig 2,1 år, fra 75 tcf i 2012 til 136 tcf i 2040 (Tabell 3-1), mens OECD-produksjonen vokser med 1,4 år, fra 44 Tcf til 66 Tcf. Produksjonen fra kontinuerlige ressurser vokser raskt i projeksjonen, med OECD tett gass-, skifergass - og kullsyre-metanproduksjon i gjennomsnitt på 3,0 år, fra 20 billioner kubikk i 2012 til 47 Tcf i 2040. I samme periode produserte ikke-OECD-produksjon av tett gass , skifergass og kullsyremetan vokser fra nesten 2 Tcf til 34 Tcf. Imidlertid kan mange usikkerheter påvirke fremtidig produksjon av disse ressursene. Det er fortsatt betydelig variasjon blant estimater av gjenvinnbar skifergasressurser i USA og Canada, og estimater av gjenvinnbar tett gass, skifergass og kullsyremetan for resten av verden er mer usikre, gitt de sparsomme dataene som er tilgjengelige for tiden. Videre krever den hydrauliske bruddprosessen som brukes til å produsere skifergasressurser, ofte betydelige mengder vann, og tilgjengelige vannforsyninger er begrenset i mange av verdensregioner som har blitt identifisert som besitter skifergasressurser. Ytterligere miljøhensyn kan også legge til usikkerheten rundt tilgangen til skifergasressurser. OECD-produksjon OECD Americas Naturgassproduksjon i OECD Americas vokser med 49 fra 2012 til 2040. USA, som er den største produsenten i OECD Americas og i OECD som helhet, står for mer enn to tredjedeler av regionene total produksjonsvekst fra 24 tcf i 2012 til 35 tcf i 2040 (figur 3-15). USAs skifergassproduksjon vokser fra 10 tcf i 2012 til 20 tcf i 2040, mer enn kompenserende nedgang i produksjon av naturgass fra andre kilder. I 2040 utgjør skifergass for 55 av den totale produksjonen av naturgass i USA i IEO2016 Reference-saken, stram gassregnskap for 20 og offshore produksjon fra de nedre 48 statene står for 8. De resterende 17 kommer fra kullsyremetan, Alaska og andre tilknyttede og ikke-tilknyttede landbaserte ressurser i de nedre 48 stater. figurdata Naturgassproduksjonen i Canada vokser med gjennomsnittlig 1,2 år i prognoseperioden, fra 6,1 Tcf i 2012 til 8,6 Tcf i 2040. I Canada, som i USA, kommer mye av produksjonsveksten fra voksende volumer av tett gass og skifer gassproduksjon. Mexicos naturgassproduksjon er relativt flatt i midtperioden, men det er mer enn dobler i de senere årene av projeksjonen, ettersom produksjonen fra skifergasressurser vokser, støttet av de seneste energireformene i landet. Total naturgassproduksjon i Mexico øker fra 1,7 Tcf i 2012 til 3,3 Tcf i 2040. I likhet med Canada og USA, antas Mexico å ha betydelige skifergasressurser, hvorav de fleste er utvidelser av den vellykkede Eagle Ford Shale i Forente stater. Men fordi skiferressursene i Mexico ikke har blitt utforsket så fullt som i resten av Nord-Amerika, er det mer usikkerhet rundt estimater av deres størrelse og potensial for produksjon. OECD Europe Norge, Nederland og Storbritannia er de tre største naturgassproducenter i OECD Europe, som tegner seg for mer enn 80 av regionens totale naturgassproduksjon i 2012. IEE2020-referansen faller OECD Europersquos naturgassproduksjon på mellomlang sikt og begynner deretter å vokse igjen i den senere delen av fremspringet, ettersom produksjonen fra tett gass, skifergass og kullsyre-metanressurser blir større (Figur 3-16). Samlet sett er naturgassproduksjonen i OECD Europe i 2040 1,6 Tcf høyere enn i 2012. Å bidra til OECD Europas samlede produksjon er veksten i naturgassproduksjonen fra Israel, som ble et OECD-medlemsland i september 2010 og inngår i OECD Europe for Statistisk rapporteringsformål. figurdata Naturgassproduksjonen i AustraliaNew Zealand-regionen øker fra 2,1 tcf i 2012 til 7,0 Tcf i 2040 i IEO2016-referansesaken, med en gjennomsnittlig hastighet på 4,4 år. I 2012 kom mer enn 90 av produksjonen i AustraliaNew Zealand-regionen fra Australia, med produksjon i Vest-Australia (inkludert Nordvest-hylleområdet i Australias Carnarvon-basseng) som utgjør ca. 58 av countryrsquos totale produksjon 59. Mye av Australias produksjon brukes som råstoff på Northwest Shelf LNG flytende anlegg. Tilsvarende er mange av Australiarsquos nye utviklinger av naturgassfelt knyttet til likriktningsprosjekter som har flere eksportkontrakter på plass. Both Japan and South Korea have limited natural gas resources. Consequently, they have limited current production and limited prospects for future production. Both countries receive most of their natural gas supplies in the form of imported LNG. In 2012, natural gas production in Japan accounted for only 3 of the countrys natural gas consumption, and in South Korea domestic natural gas production accounted for less than 1 of natural gas consumption. Although substantial deposits of methane hydrates in both Japan and South Korea have been confirmed, both countries are investigating how those resources could be safely and economically developed. The IEO2016 Reference case does not include methane hydrate resources in its estimates of natural gas resources, and widespread development of hydrates on a commercial scale is not anticipated during the projection period. Non-OECD production Middle East The three largest natural gas producers in the Middle EastmdashIran, Qatar, and Saudi Arabiamdashtogether accounted for 76 of the natural gas produced in the Middle East in 2012. With more than 40 of the worldrsquos proved natural gas reserves, the Middle East accounts for 20 of the total increase in world natural gas production in the IEO2016 Reference case, from 19.2 Tcf in 2012 to 35.8 Tcf in 2040 (Figure 3-17). figure data The strongest growth among Middle East producers from 2012 to 2040 in the IEO2016 Reference case comes from Iran, where natural gas production increases by 6.8 Tcf, followed by Saudi Arabia (3.4 Tcf of new production) and Qatar (2.9 Tcf). Although Iraq is the regionrsquos fastest-growing supplier of natural gas, with average increases of 15year over the projection period, it remains a relatively minor contributor to regional natural gas supplies. In 2040, Iraqrsquos natural gas production totals 1.0 Tcf, or about 3 of the Middle East total. Non-OECD Europe and Eurasia In the IEO2016 Reference case, 15 of the global increase in natural gas production comes from non-OECD Europe and Eurasia, which includes Russia, Central Asia, and non-OECD Europe. In the region as a whole, natural gas production increases from 28.5 Tcf in 2012 to 40.9 Tcf in 2040 (Figure 3-18). Russia remains the largest natural gas producer, accounting for more than 75 of the regionrsquos total production over the projection period. In the IEO2016 Reference case, Russiarsquos natural gas production grows on average by 1.4year from 2012 to 2040, supported primarily by growth in exports to both Europe and Asia. figure data Natural gas production in Central Asia, which includes the former Soviet Republics, grows by 0.9year on average, from 5.5 Tcf in 2012 to 7.1 Tcf in 2040. Much of the projected growth is in Turkmenistan, which already is a major natural gas producer, accounting for 44 of the regionrsquos total production in 2012. Also contributing to Central Asias production growth is Azerbaijan. Almost all of Azerbaijans natural gas is produced in two offshore fields8212the Azeri-Chirag-Deepwater Gunashli (ACG) complex and Shah Deniz. The second phase of Shah Deniz development is expected to start producing in 2018, with a peak capacity of 565 Bcf per year (in addition to the 315 Bcf in Phase I), according to BP, the development operator 60 . When it is completed, Shah Deniz will be one of the largest natural gas development projects in the world. Natural gas production in Africa grows in the IEO2016 Reference case from 7.6 Tcf in 2012 to 9.8 Tcf in 2020 and 16.5 Tcf in 2040 (Figure 3-19). In 2012, about three-quarters of Africarsquos natural gas was produced in North Africa, mainly in Algeria, Egypt, and Libya. West Africa (with Nigeria and Equatorial Guinea providing virtually all of West Africarsquos production) accounted for another 23 of the 2012 total, and the rest of Africa accounted for 3. Remaining resources in West Africa are more promising than those in North Africa, which has been producing large volumes of natural gas over a much longer period. Accordingly, in the IEO2016 Reference case, production growth in West Africa is higher than in North Africa, with annual increases over the projection period averaging 5.6year and 1.1year, respectively. figure data Nigeria is the largest natural gas producer in West Africa, although there also have been recent production increases in Equatorial Guinea, which brought an LNG liquefaction facility online in 2007. Angola was expected to add to West Africas production in the near term with the startup of its first LNG liquefaction facility in 2013. However, in April 2014, Angola LNG temporarily shut down the plant because of ongoing technical issues, which led to infrequent exports while it was open. Technical issues at the plant included electrical fires, pipeline leaks and ruptures, and a collapsed drilling rig. Recommissioning of the Angola LNG plant began in January 2016 and operator Chevron expects the first LNG shipment to occur in the second quarter of 2016 61 . In Nigeria, security concerns and uncertainty over terms of access have delayed proposed export projects and limited mid-term production growth. In the IEO2016 Reference case, export projects in Nigeria regain their former momentum later in the projection period, raising production for the West Africa region from 1.7 Tcf in 2012 to 7.9 Tcf in 2040. West Africas share of the continents total natural gas production more than doubles in the IEO2016 Reference case, from 23 in 2012 to 48 in 2040. Non-OECD Asia In the IEO2016 Reference case, natural gas production in non-OECD Asia more than doubles from 2012 to 2040, increasing by 18.7 Tcf (Figure 3-20). Growth from production in China accounts for 80 of this increase. From 2012 to 2040, China has the largest increase in natural gas production in non-OECD Asia, from 3.7 Tcf in 2012 to 18.7 Tcf in 2040, growing at an annual average rate of 6.0. Much of the increase in the latter years comes from tight gas, shale gas, and coalbed methane reservoirs. China already is producing small volumes of coalbed methane and significant volumes of tight gas (Figure 3-21) (see quotShale gas development in China: Government investment and decreasing well costsquot ). figure data figure data Other gas includes gas produced from structural and stratigraphic traps (e. g. reservoirs), historically called conventional. Shale gas development in China: Government investment and decreasing well costs As China continues to invest in domestic oil and gas production, and as the cost of drilling shale gas wells has fallen (Figures 3-22 and 3-23), Chinarsquos development of shale gas has increased. Although the Chinese energy market has increasingly relied on imported natural gas, future shale gas production could help to meet natural gas demand even as the country faces difficulties in developing other natural gas resources, including coalbed methane (CBM). figure data Note: Component costs are based on the EIAARI component-based cost model, which assumes average well depth of 11,500 feet with 4,000 feet of horizontal drilling. Cost data for 2013 are based on reports from Platts October 2013 reporting statements by Ma Yongshen, Sinopec chief geologist. Cost data for 2015 are based on statements from China National Petroleum Corporations Economics and Technology Research Institute at the Third IEA Unconventional Gas Forum in Chengdu, China, in April 2015. Over the past 25 years, China has worked to develop its substantial CBM resources, estimated by Chinas Ministry of Land and Resources (MLR) at more than 1,000 Tcf 62 . Commercialization began slowly in the 1990s, with CBM exploration programs operated by foreign companies, including BP, Chevron, and ConocoPhillips. However, the initial wells had low production rates, and by 2000 exploration activity had slowed. Although well performance has not improved much since 2000, the development of CBM supported by government loans and subsidies has accelerated. PetroChina, China United Coalbed Methane Corporation, Jincheng Coal Group, and other Chinese companies have reduced well costs and have benefited from higher natural gas prices. Currently, there are more than 20,000 CBM wells in China, producing a total of 0.36 Bcfd. However, CBM well productivity in China is significantly lower than in some other countries, including Australia and the United States. CBM development in China has focused on the Ordos and Qinshui basins in Shanxi Province, which are considered to have the countrys best geologic conditions, but significant geologic challenges8212including low permeability and undersaturation8212have constrained well productivity. The difficulty of increasing CBM output has led China to increase its efforts to develop shale gas resources, taking an approach similar to that used for CBM development. Chinarsquos technically recoverable shale gas resources are estimated at 1,115 Tcf 63 . The amount that becomes economically recoverable will depend on the market price of natural gas from foreign sources, including both pipeline gas and liquefied natural gas, as well as the capital and operating costs and productivity of shale gas production in China. More than 700 shale gas wells have been drilled in China over the past 4 years, and production has reached 0.38 Bcfd. As Chinese companies have gained experience in shale gas production, their drilling costs have declined. According to China National Petroleum Corporationrsquos Economics and Technology Research Institute, the cost of drilling in shale formations in the Sichuan Basin was between 11.3 million and 12.9 million per well in mid-2015 64 821223 lower than the cost cited in 2013 reports from Sinopec, another Chinese national oil company 65 . China has also invested heavily in joint ventures in U. S. shale plays, with its financial involvement representing 20 of total foreign investment in U. S. shale plays 66 . This investment likely has provided China with valuable expertise that can be applied to its own domestic production, helping to lower well development costs. Decreasing well costs and increasing experience in developing shale gas have been supplemented by continued government investment in the development of shale gas. In 2012, to encourage shale gas exploration, Chinarsquos government established a four-year subsidy program for any Chinese company achieving commercial production of shale gas, with subsidies of 1.80 per million British thermal units. The subsidies were extended in mid-2015, at a lower rate, through 2020 67 . Initially, shale gas development has been focused on the Longmaxi formation in the Sichuan Basin (Figure 3-24), which is estimated to hold 287 Tcf of technically recoverable volumes 68 . According to MLR, Sinopec and PetroChina are on schedule to reach 0.6 Bcfd of shale gas production by the end of 2015. Although it is still a small fraction of Chinarsquos overall production, which was estimated at 13.0 Bcfd in 2014 69 , shale gas eventually could help to meet growing demand for natural gas in China and limit growth in the countrys natural gas imports. Non-OECD Americas Natural gas production in the non-OECD Americas region nearly doubles in the IEO2016 Reference case, from 5.5 Tcf in 2012 to 9.4 Tcf in 2040 (Figure 3-25). Brazils natural production grows by an average of 4.0year and triples from 0.6 Tcf in 2012 to 1.8 Tcf in 2040. As a result, Brazilrsquos share of regional production increases from 11 in 2012 to nearly 19 in 2040. More than one-third of Brazilrsquos natural gas production growth from 2012 to 2040 comes from tight gas, shale gas, or coalbed methane production. Recent discoveries of oil and natural gas in the presalt Santos Basin are expected to increase the countryrsquos natural gas production, particularly in the Tupi field, which could contain between 5 Tcf and 7 Tcf of recoverable natural gas 70 . figure data Despite recent declines in natural gas production, countries in the Southern Cone (mainly, Argentina) become the regionrsquos leading natural gas producers by 2040 in the IEO2016 Reference case, with annual production in the Southern Cone growing by nearly 150, from 1.3 Tcf in 2012 to 3.1 Tcf in 2040. All of the production increase in the Southern Cone comes from tight gas, shale gas, or coalbed methane gas fields, as production from other resources 71 declines over the projection period. Currently, Argentina leads the non-OECD Americas region in its pursuit of tight gas and shale gas development. While the growth of natural gas production in Brazil and in the Southern Cone increases natural gas production in the non-OECD Americas region overall, production from the Northern Producers (primarily, Colombia, Venezuela, and Trinidad and Tobago) grows by an average of 1.1year, which is the regions second-lowest rate of production increase, after the Andean producers (Bolivia, Ecuador, and Peru). Venezuelas 198 Tcf of proved natural gas reserves are the Western Hemispherersquos second-largest reserves, after the United States. An estimated 90 of Venezuelas natural gas reserves are associated, meaning that they are co-located with oil reserves. Although Venezuela has plans to increase its production of nonassociated gas, largely through the development of its offshore reserves, those plans have been delayed by a lack of capital and foreign investment. World natural gas trade International trade in natural gas is undergoing rapid transformation. From 2000 to 2012, global LNG trade more than doubled, from less than 5 Tcfyear to more than 12 Tcfyear, and its growth continues in the IEO2016 Reference case through 2020 as new liquefaction capacity comes online. World LNG flows adjusted quickly in 2011 and 2012, to accommodate a surge in Japans demand for LNG in the wake of the Fukushima disaster and to account for the underutilization of LNG liquefaction capacity in North Africa and Southeast Asia. As nuclear capacity in Japan is restored, world LNG markets are expected to loosen in the near term because of growing supply and weakening demand. Although LNG trade has grown considerably in recent years, flows of natural gas by pipeline still account for most of the global natural gas trade in the IEO2016 Reference case, which includes several new long-distance pipelines and expansions of existing infrastructure through 2040. The largest volumes of natural gas traded internationally by pipeline currently are in North America (between Canada and the United States) and in Europe (among many OECD and non-OECD countries). By the end of the projection period, the IEO2016 Reference case includes large volumes of pipeline flows into China from both Russia and Central Asia ( see quotGlobal LNG trade and supply, quot ). Global LNG trade and supply In 2014, natural gas accounted for 25 of the energy used worldwide, with LNG accounting for 10 of global natural gas consumption and 31 of global natural gas trade. From 2005 to 2014, LNG trade increased by an average of 6year, nearly twice the growth rate (3.3year) of pipeline natural gas trade 72 . In 2015, LNG trade continued to expand, by about 3, with new liquefaction capacity additions in Australia and Indonesia 73 . In the IEO2016 Reference case, world LNG trade expands by nearly one-third from 2012 to 2020, as large volumes of new liquefaction capacity come online and as more countries opt for LNG as a flexible source of support for their energy systems, particularly where access to natural gas by pipeline may be limited by geographic or economic conditions. Strong growth in overall global LNG trade over the past 10 years has been accompanied by even stronger growth in LNG trade on spot 74 and short-term 75 markets. Short-term and spot trade in LNG, which in 2000 accounted for less than 5 of the natural gas traded worldwide, grew from 2.5 billion cubic feet per day (Bcfd) in 2005 to 9.3 Bcfd in 2014, and its share of total LNG trade increased from 13 to 29. The growth of short-term and spot LNG trade was aided by a number of developments, including LNG contracts with destination flexibility, decisions by importing countries to procure LNG without long-term contracts, large pricing differentials between the Atlantic and Pacific basins (which supports interbasin arbitrage), a proliferation of LNG marketers with flexible supply portfolios, and an increase in LNG carriers available for spot and short-term charter. The number of countries entering LNG trade has also increased considerably, contributing to the development of more flexible trading patterns between exporters and importers. The Asia Pacific region 76 , which accounted for almost one-third of world natural gas trade and three-fourths of LNG trade in 2014 77 , led the world growth in LNG demand over the past decade. From 2010 to 2014, as Japan, South Korea, China, and India experienced strong growth in demand for LNG, they sought to supplement contracted volumes with short-term and spot purchases. In addition, delays in the commissioning of new supply projects also contributed to the market tightness. Combined demand for short-term LNG from the four countries nearly tripled, from 2.1 Bcfd in 2010 to 6.1 Bcfd in 2014. In Japan alone, short-term market demand increased by 2.5 Bcfd, while demand for long-term contracts increased by only 1.2 Bcfd (Figure 3-26). figure data Note: LNG imports to Europe are shown as net of re-exports. Source: The International Group of Liquefied Natural Gas Importers, The LNG Industry 2010 and The LNG Industry 2014 . giignl. orgpublications . While demand for LNG in the Asia Pacific region has grown over the past 5 years, demand in Europe has declined. European nations imported a total of 8.7 Bcfd of LNG in 2010, with short-term demand accounting for 21 of the total in 2014, their imports totaled 4.3 Bcfd. European LNG trade was characterized by strong growth in re-exports, primarily to Asia. Of the total volume of short-term LNG purchases imported to Europe in 2014 (1.2 Bcfd), three-quarters was re-exported to countries in Asia, the Middle East, and South America. From 2008 to 2014, 12 countries became LNG importers: 4 in Asia (Thailand, Singapore, Malaysia, and Indonesia), 3 in South America (Argentina, Brazil, and Chile), 3 in the Middle East (Dubai, Kuwait, and Israel), and 2 in Europe (the Netherlands and Lithuania). Together they accounted for 9 (3 Bcfd) of the worldrsquos total LNG imports in 2014. Most of those 12 countries are relatively small markets that opted for floating regasification units (FSRU) as a fast and cost-effective way to meet growing demand for natural gas. Most of the 12 countries have flexible seasonal demand and procure LNG primarily in the spot market. In 2014, spot and short-term imports accounted for three-quarters of their combined total LNG imports. In 2015, four additional countries became LNG importers 78 , and three of them8212Egypt, Pakistan, and Jordan8212opted for floating regasification. In 2016, Colombia and Uruguay are expected to begin LNG imports using FSRU as receiving terminals. Qatar maintained its position as the worldrsquos leading supplier of both spot and long-term LNG volumes in 2015, and it is expected to hold that spot until the end of the decade, when both the United States and Australia are expected to close the gap. However, although Qatar holds abundant reserves of natural gas, its government has chosen to continue a self-imposed moratorium on development of its North Field and construction of new LNG export facilities. No new projects are expected in Qatar until 2020 or later. Although Malaysia was the worlds second-largest exporter of LNG in 2014, both Australia and the United States are on track to surpass Malaysia in the near future, with liquefaction projects already under construction and expected to enter service by 2020. In the IEO2016 Reference case, global liquefaction capacity in 2019 reaches 57 Bcfd, a 32 increase from 2015, led by capacity additions in Australia and the United States that together account for 93 of the new liquefaction capacity coming online over the 2015821119 period (Figure 3-27). figure data Australia, already a significant player in the LNG industry, exported 3.2 Bcfd of LNG in 2014 and brought the first of its seven new projects8212Queensland Curtis LNG Train 1 79 8212online in late 2014 and Train 2 in mid-2015. Six additional projects are under construction and are scheduled to come online by 2018. With this growth, Australia is expected to overtake Qatar as the worldrsquos leading LNG exporter with 11.5 Bcfd of liquefaction capacity by 2019. In the United States, five liquefaction facilities are currently under construction, and the first export cargo from the Lower 48 states was shipped in February 2016. Several additional projects in the United States are well into the planning and application process. The short-term outlook for LNG trade points to a potential oversupply, as it will take some time for the market to absorb the large volumes of new LNG supply coming online. In the midterm, new liquefaction projects on the east coast of Africa (Mozambique, Tanzania) and in western Canada, and offshore floating liquefaction projects in Malaysia and Australia will be considered as the LNG market moves beyond its traditional supply sources. In the long term, the number of LNG exporters and importers is expected to continue growing as projects move to more remote areas. OECD natural gas trade In 2012, 23 of the natural gas demand in OECD nations was met by net imports from non-OECD countries. That share falls to 16 in 2040 in the IEO2016 Reference case, with both imports and exports from different OECD regions shifting substantially over the projection period. As exports of LNG from the United States and Australia increase in the first decade of the projection period, total net imports to the OECD8212predominantly to Europe, Japan, and South Korea8212begin to decline after 2016. Over the entire period from 2012 to 2040, net imports of LNG to the OECD fall in the IEO2016 Reference case by 0.4year, and net imports in 2040 are 13 lower than they were in 2012. Liquefied natural gas: Growing use of floating storage and regasification units Floating regasification is a flexible, cost-effective way for smaller markets to receive and process LNG shipments. Several countries have turned to floating regasification as a short-term solution to meet growing demand for natural gas. Three of the four countries that began importing LNG in 20158212Pakistan, Jordan, and Egypt8212are using floating regasification rather than building full-scale onshore regasification facilities. In addition, the technology is being used in other countries as a temporary solution while onshore facilities are being built. Floating regasification involves the use of a specialized vessel8212a floating storage and regasification unit (FSRU), which is capable of transporting, storing, and regasifying LNG onboard8212and either an offshore terminal, which typically includes a buoy and connecting undersea pipelines to transport regasified LNG to shore, or an onshore dockside receiving terminal. An FSRU can be either purpose-built or converted from a conventional LNG vessel. The technology can be developed in less time than an onshore facility of comparable size. As of 2015, 18 FSRUs were functioning as both transportation and regasification vessels, and 5 permanently moored regasification units had been converted from conventional LNG vessels to FSRUs. The use of floating regasification has grown rapidly in recent years (Figures 3-28 and 3-29), particularly in emerging markets facing short-term supply shortages. The technology was first deployed in the U. S. Gulf of Mexico in 2005. Floating regasification capacity totaled 7.8 billion cubic feet per day (Bcfd) at the end of 2014, representing 8 of global installed regasification capacity, according to data from the International Gas Union. figure data figure data In the spring and fall of 2015, four more floating terminals came online8212one each in Pakistan and Jordan and two in Egypt8212adding 1.9 Bcfd of new capacity 80 . Seven more floating regasification terminals, totaling 3.1 Bcfd capacity, are being developed in Uruguay, Chile, Ghana, India, the Dominican Republic, Puerto Rico, and Colombia, with expected online dates in 2016ndash17. When those terminals are completed, global regasification capacity will total 12.7 Bcfd. Floating regasification is likely to remain a preferred technology option for emerging markets because of its flexible deployment capabilities, smaller capacities, quick startup, and relatively low costs as compared with the costs of onshore terminals. OECD Americas With the exception of Mexico, regional net imports among the nations of the OECD Americas trend downward through 2040 in the IEO2016 Reference case (Figure 3-30). In the United States, rising domestic production reduces the need for imports, primarily as a result of robust growth in regional production of shale gas. The United States becomes a net exporter of natural gas in 2017, with net exports growing to 5.6 Tcf in 2040. Most of the growth in U. S. net exports can be attributed to exports of LNG globally, although U. S. pipeline exports to Mexico also grow steadily as increasing volumes of natural gas for Mexico imported from the United States fill the growing gap between production and consumption in Mexico. In 2012, U. S. exports to Mexico totaled 620 billion cubic feet. In the IEO2016 Reference case, Mexicorsquos net natural gas imports more than double, to 1.3 Tcf in 2040, after reaching their highest level in the mid-2020s. Beyond 2025, increases in Mexicorsquos natural gas production slow the countrys demand for imports ( see quotU. S. natural gas exports to Mexico, quot ). U. S. domestically sourced exports of LNG (excluding exports from the existing Kenai facility in Alaska) begin in 2016 and grow to 3.4 Tcf in 2030, with more than three-quarters originating in the Lower 48 states and the remainder in Alaska. figure data U. S. natural gas exports to Mexico With new U. S. pipeline export capacity being brought online, and connecting pipelines in Mexico ramping up to full capacity, exports of natural gas by pipeline from the United States are beginning to gradually displace Mexicorsquos imports of LNG. According to EIA data, U. S. pipeline exports to Mexico set a monthly record high average of 3.3 billion cubic feet per day (Bcfd) in July 2015, and over the first seven months of 2015 they averaged 2.7 Bcfd821235 higher than the total for the first seven months of 2014. Mexicorsquos LNG imports declined in the first seven months of 2015, according to data from the Secretara de Economa. Before the boom in U. S. shale gas production, Mexico had expected only limited growth in pipeline imports from the United States. However, with the rise of U. S. shale production and the decline in natural gas prices, Mexicorsquos need for LNG imports has fallen, and its LNG regasification terminals have been operating below capacity. Currently, Mexico has three regasification terminals: Altamira, on the east coast, commissioned in 2006, with 0.7 Bcfd capacity Ensenada (also called Energia Costa Azul) on the west coast in operation since 2008 with 1.0 Bcfd capacity and Manzanillo on the west coast commissioned in 2012 with 0.5 Bcfd capacity. While use at the Manzanillo terminal has been relatively high, averaging 85 in 2013ndash14, utilization at the Altamira terminal averaged around 50, and the Costa Azul terminal in the Baja Peninsula was virtually unused. LNG imports at the Manzanillo terminal provide natural gas for the gas-fired power plants in Mexicos Central West region. The location of the Manzanillo terminal provides a unique point of entry and serves to relieve pipeline bottlenecks in the region. As a result, LNG imports to the terminal are expected to remain high over the next few years, until additional pipeline capacity is developed to provide alternative sources. Imports at the Energia Costa Azul terminal, on the other hand, have averaged only 4 of the terminals nameplate capacity since 2011, despite a long-term contract with the Tangguh liquefaction project in Indonesia. Originally, the terminal was constructed to supply the Southern California market and new power plants in Mexicos state of Baja California. However, those plants also could be supplied via U. S. pipelines, and the terminal depended mostly on natural gas demand in California, which was limited by the availability of less costly U. S. supplies. Because the Costa Azul contract allowed for diversion of supply volumes to other markets, most of contracted supply from Indonesia has gone instead to higher priced Asian markets over the past several years. Sempra Energy, the terminals operator, is considering a conversion of the terminal to a liquefaction facility. At the Altamira terminal, LNG imports in 2008821115 have consistently averaged about 50 of the terminals capacity. Terminal operators Shell and Total have a supply contract with Mexicos Comisioacuten Federal de Electricidad (CFE), which allows them to supply CFE with either pipeline natural gas or LNG. However, the contract stipulates that at least 50 of the supply must be LNG. In the first six months of 2015, imports to the Altamira terminal declined by 14 from the same period a year earlier, as increasing availability of pipeline gas from the United States at lower prices displaced some of the LNG imports. In September 2015, CFE canceled a tender for several spot cargos into Altamira between September and December, noting the increased availability of less-expensive pipeline natural gas from the United States. The Manzanillo terminal may follow suit in the coming years as additional pipeline infrastructure becomes available in the region to alleviate the existing bottlenecks. In the IEO2016 Reference case, pipeline exports of natural gas from Canada to the United States continue declining as U. S. shale gas production grows. However, Canada remains a net exporter of natural gas, with LNG export volumes replacing some of the lost pipeline export volumes. Canadarsquos net exports of natural gas in 2040 in the IEO2016 Reference case are 22 higher than they were in 2012. OECD Europe In OECD Europe, total natural gas imports continue to grow by an average of 2.1year from 2012 to 2040 as local production sources decline, especially in the United Kingdom. The pipeline share of OECD Europes natural gas imports grows in the IEO2016 Reference case to between 40 and 50 of the regionrsquos total natural gas supply, and its LNG imports grow to about 20 of the regionrsquos total natural gas supply in 2040. The worlds two largest importers of LNG are Japan and South Korea in the OECD Asia region. The AustraliaNew Zealand country grouping, also in OECD Asia, is becoming the worldrsquos second-largest exporter of LNG (after Qatar). Supported by a fivefold increase in Australiarsquos exports from 2012 to 2040, OECD Asiarsquos net demand for imports falls from 5.3 Tcf in 2012 to 5.0 Tcf in 2040 (Figure 3-31). figure data Japan and South Korea continue to be major players in world LNG trade, even though their total consumption of natural gas is relatively small on a global scale. Although their combined natural gas consumption represented slightly more than 5 of world consumption in 2012, it represented almost 50 of world LNG imports. Because the two countries are almost entirely dependent on LNG imports for natural gas supplies, their overall consumption patterns translate directly to import requirements. South Korearsquos imports grow moderately in the IEO2016 Reference case, in line with the countryrsquos growth in natural gas demand. Japan has experienced dramatic growth in LNG imports since the Fukushima nuclear disaster in early 2011, with total LNG imports in 2012 approximately 25 higher than in 2010. Beginning in 2015, there has been a gradual restart of Japanrsquos nuclear capacity, and in the IEO2016 Reference case, those gradual restarts are assumed to continue and to lessen the countryrsquos need for LNG imports. When nuclear power generators are able to provide about 15 of Japanrsquos total generation, the countryrsquos natural gas import demand is expected to return to the slow growth trend anticipated before the Fukushima event, based on relatively slow economic growth and declining population. Non-OECD natural gas trade Net exports of natural gas from non-OECD countries decline by less than 1.0year on average in the IEO2016 Reference case. As with the OECD countries, the relatively small decline for the region in aggregate obscures changes in the trading patterns of the separate non-OECD regions and countries. Non-OECD Europe and Eurasia Net exports of natural gas from Russia, the largest exporter in the world, represent the most significant factor in exports from non-OECD Europe and Eurasia, which grow in the IEO2016 Reference case by an average of 3.7year, from 5.4 Tcf in 2012 to 6.5 Tcf in 2020 and 15.0 Tcf in 2040 (Figure 3-32). With Russia providing the largest incremental volume of exports to meet the increase in demand for supplies from non-OECD Europe and Eurasia, its net exports grow by an average of 3.4year, from 6.1 Tcf in 2012 to 15.6 Tcf in 2040. LNG and pipeline exports from Russia to customers in both Europe and Asia increase throughout the projection, while exports from Central Asia increase by an average of 0.3year. figure data Middle East Net exports of natural gas from the Middle East grow by an average of 1.7year, as flows from the region increase from 4.4 Tcf in 2012 to 7.2 Tcf in 2040 (Figure 3-33). An important factor in the increase is the growth of LNG supplies from Qatar after 2025. Qatars natural gas exports grow by an average of 1.2year from 2010 to 2040 in the IEO2016 Reference case. With the current moratorium on further development of Qatars North Field, no new LNG projects are being initiated. Qatar enacted the moratorium in 2005 to assess the effect of ongoing increases in production on the North Field before committing to further increases. figure data Iran is another Middle Eastern country that is expected to increase its natural gas exports over the projection period. Net natural gas exports from Iran grow from 0.1 Tcf in 2012 to 2.0 Tcf in 2040 according to the IEO2016 Reference case. International sanctions against Irans oil and natural gas sectors have been eased as a result of the Joint Comprehensive Plan of Action (JCPOA) agreement reached between Iran, the P51 (the five permanent members of the United Nations Security Council and Germany), and the European Union (EU). The JCPOA agreement has the potential to increase Irans natural gas exports (both by pipeline and, in the longer term, LNG) beyond the amount projected in the IEO2016 Reference case ( see also quotPotential for increased natural gas exports from Iran following the end of international sanctions, quot ). Potential for increased natural gas exports from Iran following the end of international sanctions After Russia, Iran has the second-largest proved reserves of natural gas in the world 81 , and it has a strong potential to develop those resources at a faster pace after the recent lifting of nuclear-related sanctions. Iran is targeting a substantial increase in natural gas production in the coming years, not only to meet rapidly growing domestic demand, but also to boost its export capacity, primarily by pipeline. In the longer term, Iran plans to build LNG export facilities for global shipments of natural gas. Additional production of natural gas for export markets will compete with Irans domestic demand for natural gas, which is used both for reinjection in the production of oil and as a feedstock in the countrys rapidly growing domestic petrochemical industry. According to estimates by the National Iranian Gas Company (NIGC), more than 100 billion in investment capital will be needed to rebuild Iranrsquos natural gas industry. Iran is currently the fourth-largest natural gas consumer in the world after the United States, Russia, and China, with total consumption of 15.4 Bcfd in 2014 82 and 16.6 Bcfd in the first 6 months of 2015. From 2005 to 2014, Irans domestic consumption of natural gas grew by 66, second only to the rate of increase in China 83.In 2014, Iranrsquos natural gas production and consumption were closely matched, with net exports of 0.1 Bcfd. In 2014, the residential, commercial, and public sectors and small industries accounted for 55 (8.4 Bcfd) of Iranrsquos total natural gas consumption. Power plants and large industries accounted for 45 (7.0 Bcfd) of Iranrsquos total natural gas consumption in 2014. According to NIGCrsquos Strategic Objectives document, Iran plans to increase the natural gas share of its domestic energy mix and more than double its natural gas processing capacity, from approximately 20 Bcfd in 2014 to 42 Bcfd by 2025 84 , while reducing its consumption of fuel oil in power generation and replacing its aging oil-fired plants with new natural gas-fired plants. NIGC estimates that to meet the rapidly growing domestic demand for natural gas, Iran will need more than 20 billion in investment to upgrade and expand its domestic pipeline infrastructure. Iran plans to expand the domestic pipeline network to more than 35 Bcfd by 2017, adding 1,709 miles (2,750 km) of new pipelines at a cost of 6.3 billion and investing more than 15 billion in expansion and upgrades of the existing domestic pipeline network. Those expansions are likely to require foreign capital, and to attract foreign investors Iran has proposed various investment schemes, including build-operate-own-transfer . Some foreign investors may be reluctant to proceed at this point because of concerns about corruption, red tape, and state influence over the economy. Consequently, it may take some time for the expansion plans to materialize. Iran has increased its domestic natural gas production fivefold over the past 20 years. Most of its natural gas production comes from the South Pars field, the largest natural gas field in the world, which Iran shares with Qatar. On Qatarrsquos side, the field is called the North Field . Iran is developing 28 phases in South Pars, 10 of which are operational 85 . Phase 12 began production in early 2015 (3 Bcfd of natural gas and 120,000 bd of condensate). Production from phases 15 and 16 began at the end of 2015 86 . Between 2015 and 2020, Iran has the potential to add between 8 Bcfd and 9 Bcfd of new natural gas production, primarily from South Pars. The Kish field, the largest nonshared natural gas field in the country, is being developed. Kish has a production target of 0.9 Bcfd of natural gas and 4 million barrels of gas condensate 87 per year, and 1.4 billion has been allocated for its development. In addition, after 2020, Iran plans to develop its North Pars, Golshan, and Ferdowsi natural gas fields. In 2014, 93 of Iranrsquos pipeline exports (0.9 Bcfd) went to Turkey, and 0.03 Bcfd went to Armenia and Azerbaijan (net of imports from Azerbaijan). Iran imported 0.7 Bcfd from Turkmenistan in 2014, or half of its contractual volumes, as Iranrsquos growing production allowed it to become more self-sufficient in delivering natural gas to its major consumption centers in the northern part of the country. The price of Iranrsquos natural gas exports to Turkey is one of the highest in the region, and it has been used as a benchmark for Irans other proposed pipeline export projects. However, the reluctance of Persian Gulf countries to sign contracts at those prices has been the main obstacle to Irans development of new pipeline export projects. Future contracts for exports to Gulf countries are likely to require some reduction in the prices of Iranian natural gas exports. Irans Sixth Development Plan, which outlines its economic development goals for the next five years, sets a target to increase natural gas exports to more than 6 Bcfd by March 2021. The target is based on expanding production primarily from the South Pars field, which can be exported by pipeline to Irans neighboring countries. In the plan, Iran has prioritized pipeline exports over LNG exports, with a potential total of 3 Bcfd to 4 Bcfd in the next several years coming from projects that are close to completion. The focus of Iranrsquos export pipelines is on neighboring Persian Gulf countries, Pakistan, potentially India, and in the longer term, exports to European countries via Turkey. Exports of natural gas from Iran to the Persian Gulf countries8212particularly, Iraq, Oman, Kuwait, and the United Arab Emirates (UAE)8212are likely to begin by 201718 88.There also are plans for Iran to increase exports to Iraq by 0.9 Bcfd, to a total of 1.6 Bcfd, but the duration of that export contract is expected to be short, because Iraqrsquos domestic production increases in the mid-2020s. Iran is also planning pipeline exports to Oman (0.7 Bcfd to 1.0 Bcfd via a proposed 109-mile subsea pipeline) to Kuwait (0.3 Bcfd to 0.5 Bcfd) and to the UAE (0.6 Bcfd to 1.5 Bcfd). The existing pipeline network connecting Iranrsquos Salman field to the Sharjah Emirate of the UAE can deliver 0.6 Bcfd, but a dispute over the contract price has delayed gas shipments and is currently in international arbitration. If the pricing issue is resolved between parties, Iran can start exports to the UAE quickly. Proposed projects to export natural gas by pipeline from Iran to countries outside the Persian Gulf involve considerable risk for a variety of reasons. The proposed projects include: Pakistan plans to link the Iranian pipeline with a proposed 45 billion China-Pakistan Economic Corridor. Iran has built all but the final 155 miles on its side, and China is building a 435-mile stretch inside Pakistan that would move natural gas from Gwadar port in the West to Nawabshah in the South. The project requires building a short 50-mile leg to Gwadar from the border with Iran, which is likely to be financed by China. Risks include terrorist threats in Pakistanrsquos Balochistan province, an enclave of Pakistani insurgents, and contract pricing that has not been finalized. Iran is in discussions to revive the Iran-Pakistan-India Peace Pipeline project, which may be a longer-term development. India has proposed to develop Irans 12.8 Tcf Farzad-B natural gas field and is considering construction of subsea pipeline to link Iran directly with India. However, at an estimated cost of about 5 billion, the project is both expensive and technologically challenging. Iran also is considering exports to Europe via Turkey. An estimated 5.1 billion investment would be required to expand a 1,120-mile, 56-inch-diameter pipeline that would connect Assaluyeh with Bazargan near the Turkish border. LNG exports from Iran may be a longer-term development. Iran will face strong competition, and its projects may not be economically viable in the current environment of low oil prices. Among the projects that have been proposed, the Iran LNG project (capacity 1.4 Bcfd) may be the most likely to materialize after 2020. Iran has already spent 2.5 billion to build LNG port facilities, tank storage, and other infrastructure for the project and can now gain access to liquefaction technology not available when sanctions were in place. NIGCs announced target of increasing its natural gas liquefaction capacity to 10 of the world total by 2025 is not likely to be met 89 . However, some smaller projects8212including delivering natural gas via pipeline to Oman to use spare capacity in the Qalhat LNG liquefaction project, and use of Das Island liquefaction facility in Abu Dhabi8212are more likely to be developed in the next few years. Elsewhere in the Middle East, Yemen, Oman, and Abu Dhabi of the United Arab Emirates (UAE) also are current exporters of LNG. However, the potential for growth in their exports and exports from other countries in the Middle East appears to be limited by their need to meet increases in their own domestic demand. The IEO2016 Reference case shows a similar trend for smaller producers in the Arabian Peninsula as a whole, including Kuwait, Oman, the UAE, and Yemen. As a group, they exported about 0.2 Tcf of natural gas on a net basis in 2012, and the volume of their net imports rises to a total of 1.2 Tcf in 2040. Net exports of natural gas from Africa increase in the IEO2016 Reference case by an average of 1.7year (Figure 3-34). In 2012, the regionrsquos net exports totaled about 3.4 Tcf, with 2.3 Tcf coming from North Africa. Net exports from West Africa grow at a robust average annual rate of 6.5 from 2012 to 2040, with much of the growth coming in the later part of the projection. Security concerns and uncertainty over terms of access in Nigeria have significantly delayed any progress on currently proposed LNG export projects. figure data Persistent, significant above-ground challenges in East Africa hamper export growth in that region. This is primarily owing to production and export proposals representing a large change in scale of operations for the oil and natural gas industries in Mozambique and Tanzania, where physical and regulatory infrastructures are not yet in place to support large-scale production and export of natural gas ( see quotPotential for increased natural gas exports from Iran following the end of international sanctions, rdquo and ldquoLiquefied natural gas: Growing use of floating storage and regasification units, quot ). Non-OECD Asia Non-OECD Asia has the highest regional growth rate in net imports of natural gas in the IEO2016 Reference case. With net imports of 17.5 Tcf in 2040, non-OECD Asia becomes the worldrsquos largest importing region, surpassing OECD Europe by 2040. China has the largest increase in import demand, to 8.9 Tcfyear in 2040, when nearly one-third of its annual natural gas consumption is supplied by imports (Figure 3-35). figure data To meet future demand, China is actively pursuing multiple potential sources for natural gas imports. Chinese companies have signed long-term agreements to deliver at least 6.6 Bcfd through 2030 90.Most of those contracts are with Asian firms sourcing LNG from Australia, Indonesia, Malaysia, Qatar, and Papua New Guinea. Moreover, there are additional contracts tied to new liquefaction projects located in Australia, Russia, and the United States that are scheduled to come online by 2020. China is also pursuing multiple sources for pipeline natural gas imports, which have increased as production from Central Asia and Myanmar has grown and the non-OECD regions natural gas infrastructure has improved. Chinarsquos total pipeline imports of natural gas exceeded its LNG imports in 2012, and in 2014 its LNG imports totaled 1.1 Tcf, up by 20 from 2013 LNG imports 91 . Chinas first natural gas import pipeline, which was completed in late 2009, now transports supplies from Turkmenistan and Uzbekistan. Another pipeline from Myanmar was completed in 2013, with the capacity to carry 0.4 Tcfyear of natural gas from Myanmars offshore fields in the Bay of Bengal to Kunming in Chinas Yunnan province 92 . China also began importing natural gas from Kazakhstan in July 2013, but the quantities have been very small, constituting about 1 of the total pipeline imports into China in 2015. In addition, Russia and China signed a significant natural gas agreement in May 2014. The deal was signed after a decade of negotiations over the import price and the supply route 93 , with China agreeing to purchase 1.3 Tcf of natural gas per year from Gazproms East Siberian fields at a total cost of 400 billion over a 30-year period. The proposed Power of Siberia pipeline will connect Russias eastern Siberian natural gas fields and Sakhalin Island to northeastern China. Chinas National Development and Reform Commission, which approved construction of the pipeline on the Chinese side in late 2014, anticipates that it will come online in 2018. In November 2014, Gazprom and the China National Petroleum Commission also signed a memorandum of understanding for China to import 1.1 Tcfyear from Russias western Siberian natural gas fields, although many key details, including pricing details and required infrastructure expansion plans, have not yet been addressed 94 . India has also increased its natural gas imports. Since 2013, unexpected production declines in Indiarsquos Krishna Godavari basin have meant that the country must rely more heavily on LNG imports. As a result, Indian companies have invested in increasing the countryrsquos LNG regasification capacity in recent years to meet rising demand. In early 2013, GAIL (Indiarsquos largest state-owned natural gas processing and distribution company), NTPC (Indiarsquos largest power utility), and several other smaller players restarted the Dabhol project (originally proposed by the now-defunct Enron Corporation), which includes a regasification terminal to fuel three natural gas-fired power stations 95 . Dabhol LNG also ships natural gas to southern India through the new pipeline to Bengaluru. GAIL is installing a breakwater facility to double Dabholrsquos capacity by 2017. Petronetrsquos LNG terminal at Kochi, commissioned in late 2013, is experiencing low utilization as a result of delays in the approval and construction of a proposed pipeline to Mangalore and other parts of southern India, according to IHS. Indiarsquos natural gas imports grow in the IEO2016 Reference case by an average of 6.7year, to a total of 3.9 Tcf in 2040. Non-OECD Americas Natural gas trade in the non-OECD Americas region has become increasingly globalized as several countries have become involved in the LNG trade. In the IEO2016 Reference case, new LNG regasification capacity facilitates growth in the regionrsquos gross imports of natural gas through 2040, but the discovery of large new natural gas reserves throughout the region increases its gross exports by a larger amount. As a result, the regionrsquos overall trade balance remains relatively flat, with net exports increasing from 0.6 Tcf in 2012 to 0.7 Tcf in 2040 (Figure 3-36), after declining in the middle years of the projection. figure data Although LNG regasification facilities in Brazil and in the Southern Cone (excluding Chile, an OECD member state since 2010) have received LNG supplies fairly consistently over the past three years, the Southern Cone becomes a net exporter of natural gas by 2030 in the IEO2016 Reference case, largely as a result of the discovery of substantial shale gas reserves in Argentinarsquos northwestern Neuqueacuten province 96 . Net imports to Brazil remain essentially flat from 2012 through 2040. Overall net exports from the Andean region end in 2030 and net exports from the Northern Producers increase by an average of 0.5year from 2012 to 2040. World natural gas reserves As reported by Oil amp Gas Journal 97 , the worldrsquos proved natural gas reserves have grown by about 40 over the past 20 years, to a total of 6,950 Tcf as of January 1, 2016 (Figure 3-37). Estimated proved reserves in the non-OECD region as a whole have grown by 43 (1,912 Tcf) since 1996, while proved reserves in the OECD region have grown by 21 (104 Tcf) since 1996. As a result, the share of world proved natural gas reserves located in OECD countries has declined from 10 in 1996 to 9 in 2016. figure data The annual rate of growth in world proved natural gas reserves from 1980 to 1995 was notably higher than it has been in more recent years. Since 1995, the annual growth rate, while variable, has slowed to a reasonably steady rate of about 1.6year. Over the past 10 years, estimates of proved world natural gas reserves rose by 838 Tcf, or an average of 1.3year, as compared with 1,179 Tcf, or 2.2year on average over the previous 10 years (from 1996 to 2006). Estimated proved reserves in the non-OECD countries rose by 723 Tcf, or an average of 1.2 annually, over the past 10 years, compared with 2.4 annually from 1996 to 2006. The most rapid annual increase in non-OECD proved reserves in this period, at 12year, occurred from 2003 to 2004, supported by an increase in Qatar from 509 Tcf to 910 Tcf. In comparison, proved reserves in the OECD countries declined by 0.2year from 1996 to 2006 and increased by 115 Tcf, or an average of 2.1year, over the past 10 years. World proved natural gas reserves generally have grown in each year since 1980, but declines have been reported for four years (1995, 1996, 2005, and 2015). Although world reserves increased by a modest 0.4 from 2015 to 2016, that increase follows a decrease of 1.5 (105 Tcf) from 2014 to 2015, and the estimate for 2016 still is lower than the 2014 level. Estimates of proved reserves in both the OECD and non-OECD regions show a similar trajectory however, the absolute decrease in 2015 and the increase in 2016 were greater in the OECD countries, even though their reserve levels are less than one-tenth the levels in the non-OECD countries. Accordingly, the percentage decrease from 2014 to 2015 was 9.0 for the OECD countries, compared to 0.7 for the non-OECD countries, and the increase from 2015 to 2016 was 2.9 for the OECD countries, compared to 0.2 for the non-OECD countries. Estimates of world proved reserves increased by 31 Tcf from 2015 to 2016, with more than one-half of the increase (17 Tcf) coming from OECD countries. From 2015 to 2016, proved reserves in the OECD Americas rose by 29 Tcf, proved reserves in OECD Europe fell by 11 Tcf, and proved reserves in the countries of OECD Asia were nearly flat. Estimated proved reserves in the non-OECD countries increased by 13 Tcf from 2015 to 2016, with a combined 17 Tcf of additional proved reserves in China, Malaysia, India, and Angola partially offset by a decrease of 2 Tcf in Indonesiarsquos proved reserves. The largest change in proved natural gas reserve estimates was for the United States, where estimated proved natural gas reserves increased by 30 Tcf (9), from 338 Tcf in 2015 to 369 Tcf in 2016. The second-largest change was for China, where estimated proved reserves increased by 11 Tcf (7), from 164 Tcf in 2015 to 175 Tcf in 2016. As a result, Chinarsquos estimated proved reserves are now the worldrsquos 10th largest, up from the 11th largest in 2015. The third-largest change in estimated proved reserves was for Saudi Arabia, with estimated reserve additions of 6 Tcf (2), from 294 Tcf in 2015 to 300 Tcf in 2016. Although there were no changes in proved reserves for Russia and Iran, their proved reserves are ranked first and second in the world at 1,688 Tcf and 1,201 Tcf, respectively. Qatar and the United States are ranked third and fourth, at 866 Tcf (down 1) and 369 Tcf (up 9), respectively. Current estimates of proved natural gas reserves worldwide indicate a large resource base to support growth in markets through 2040 and beyond. Like reserves for other fossil fuels, natural gas reserves are spread unevenly around the world. Natural gas proved reserves are concentrated in Eurasia and in the Middle East, where ratios of proved reserves to production suggest decades of resource availability. However, in the OECD countries, including many in which there are relatively high levels of consumption, current ratios of proved reserves to production are significantly lower. The impact of that disparity is reflected in the IEO2016 projections of increased international trade in natural gas. Almost three-quarters of the worldrsquos proved natural gas reserves are located in the Middle East and Eurasia (Figure 3-38), with Russia, Iran, and Qatar together accounting for about 54 of world proved natural gas reserves as of January 1, 2016 (Table 3-2 ). Proved reserves in the rest of the worlds regions are distributed fairly evenly. Despite high rates of increase in natural gas consumption, particularly over the past decade, most regional reserves-to-production ratios have remained high. Worldwide, the reserves-to-production ratio is estimated at 54 years. Central and South America has a reserves-to-production ratio of 44 years, Russia 56 years, and Africa 70 years. In contrast, the Middle Eastrsquos reserves-to-production ratio exceeds 100 years 98.The United States has a reserves-to-production (RP) ratio of 13 years 99 . figure data Proved reserves include only estimated quantities of natural gas that can be produced economically from known reservoirs, and therefore they are only a subset of the entire potential natural gas resource base. Resource base estimates include estimated quantities of both discovered and undiscovered natural gas that have the potential to be classified as reserves at some time in the future. In the IEO2016 Reference case, the resource base does not pose a constraint on global natural gas supply. By basing long-term production assessments on resources rather than reserves, EIA is able to present projections that are physically achievable and can be supported beyond the 2040 projection horizon. The realization of such production levels depends on future growth in world demand, taking into consideration such above-ground limitations on production as profitability and specific national regulations, among others. IEO Sections Press Conference
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