Moving average natural gas

Harga Gas Alam Berada di High 19-Bulan: Apa Artinya Pada tanggal 21 September 2016, futures gas alam aktif mencapai level tertinggi 3,06 pada harga penutupan pada level tertinggi sejak Januari 2015. Mengapa harga gas alam naik Kenaikan alam Gas bisa dikaitkan dengan suhu tinggi. Hal ini menyebabkan tingginya permintaan gas alam pada pembangkit tenaga gas untuk memenuhi permintaan pendinginan. Aktivitas pengeboran alami yang mengalami hambatan lemah. Nah membahas gas alam dan rig minyak mentah di bagian selanjutnya. Pasar juga mengharapkan adanya kesenjangan antara tingkat persediaan saat ini dan rata-rata historis untuk ditutup. Nah bahas ini secara rinci di Bagian 3. Persediaan gas alam Musim dingin yang lalu, penggunaan gas alam untuk pemanasan lemah karena cuaca ringan. Akibatnya, harga lemah. Pada akhir Maret 2016, persediaan gas alam AS mencapai 2,5 triliun kaki kubik6767 lebih tinggi dari tingkat di tahun 2015 dan 53 di atas rata-rata lima tahun mereka. Kontrak berjangka gas alam mencapai titik terendah 2016 dan 17 tahun di 1,64 pada 3 Maret. EIA (Administrasi Informasi Energi AS) memproyeksikan bahwa persediaan gas alam akan menjadi 4.042,4 Bcf (miliar kaki kubik) pada akhir Oktober 2016. Ini akan menjadi Tingkat tertinggi yang tercatat pada akhir Oktober. Selama sepekan yang berakhir 2 September, persediaan gas alam berada di 3.437 Bcf10 lebih tinggi dari rata-rata lima tahun mereka dan 6 di atas tingkat tahun lalu. Rata-rata pergerakan kunci Pada tanggal 21 September, futures gas alam diperdagangkan 17,8 di atas rata-rata pergerakan 100 hari mereka dan 6,7 di atas rata-rata pergerakan 20 hari mereka. Hal ini mengindikasikan bullishness pada harga gas alam. Grafik di atas menunjukkan kinerja harga futures gas alam relatif terhadap moving average kunci. Sentimen gas alam juga mempengaruhi ETF seperti ProShares Ultra Oil amp Gas ETF (DIG), Portofolio Momentum Energi Diba PowerShares (PXI), Energi ETF Vanguard (VDE), iShares Energy ETF (IYE), dan Fidelity Indeks Energi MSCI ETF (FENY). Di bagian selanjutnya dari seri ini, bacalah jumlah rig minyak mentah. Nah, bagaimana dampaknya pada produksi dan harga gas alam. Yang Mengemudi Harga Gas Bumi Tinggi Pada tanggal 1 Juli, futures gas alam aktif mencapai level tertinggi 2016 di level tertinggi 2.99 pada tingkat tertinggi sejak Mei 2015, dengan harga penutupan. Saat ini, gas alam adalah 5 di bawah 2016 tinggi. Mengapa harga gas alam turun pada awal 2016 Musim dingin yang lalu, penggunaan gas alam untuk pemanasan lemah karena cuaca ringan. Akibatnya, harga lemah. Pada akhir Maret 2016, persediaan gas alam AS mencapai 2,5 triliun kaki kubik6767 lebih tinggi dari tingkat di tahun 2015 dan 53 di atas rata-rata lima tahun mereka. Kontrak berjangka gas alam mencapai titik terendah 2016 dan 17 tahun di 1,64 pada 3 Maret. Kunci bergerak rata-rata 8,3 di atas rata-rata pergerakan 100 hari mereka dan 3,3 di atas rata-rata pergerakan 20 hari mereka. Harga gas alam turun di atas rata-rata pergerakan 20 hari pada 23 Agustus. Ini mengindikasikan bullishness jangka pendek pada harga gas alam. Grafik di atas menunjukkan kinerja harga futures gas alam relatif terhadap moving average kunci. Sentimen gas alam juga mempengaruhi ETF seperti ProShares Ultra Oil amp Gas ETF (DIG), Portofolio Momentum Energi Diba PowerShares (PXI), Energi ETF Vanguard (VDE), iShares Energy ETF (IYE), dan Fidelity Indeks Energi MSCI ETF (FENY). Di bagian selanjutnya dari seri ini, bacalah jumlah rig minyak mentah. Lihat juga bagaimana dampak produksi dan harga gas alam. U.S. Administrasi Informasi Energi - EIA - Statistik dan Analisis Independen Prospek Energi Internasional 2016 Bab 3. Gas alam Konsumsi gas alam di seluruh dunia diproyeksikan meningkat dari 120 triliun kaki kubik (Tcf) pada tahun 2012 menjadi 203 Tcf pada tahun 2040 di International Energy Outlook 2016 ( IEO2016) Referensi kasus. Dengan sumber energi, gas alam menyumbang kenaikan terbesar konsumsi energi utama dunia. Sumber daya gas alam yang melimpah dan produksi yang kuat berkontribusi pada posisi persaingan yang kuat antara gas alam di antara sumber daya lainnya. Gas alam tetap menjadi bahan bakar utama di sektor tenaga listrik dan di sektor industri. Di sektor listrik, gas alam merupakan pilihan menarik bagi pembangkit baru karena efisiensi bahan bakarnya. Gas alam juga membakar lebih bersih daripada produk batubara atau minyak bumi, dan karena lebih banyak pemerintah mulai menerapkan rencana nasional atau regional untuk mengurangi emisi karbon dioksida (CO2), mereka dapat mendorong penggunaan gas alam untuk menggantikan lebih banyak batubara dan bahan bakar cair yang bersifat karbon. Konsumsi gas alam dunia untuk penggunaan industri meningkat rata-rata 1,7 tahun, dan konsumsi gas alam di sektor tenaga listrik meningkat pada tahun ke 2, mulai 2012 sampai 2040 dalam kasus Referensi IEO2016. Sektor industri dan listrik menyumbang 73 dari total kenaikan konsumsi gas alam dunia, dan mencakup sekitar 74 dari total konsumsi gas alam sampai tahun 2040. Konsumsi gas alam meningkat di setiap wilayah IEO, dengan permintaan di negara-negara di luar Organisasi untuk Kerjasama Ekonomi dan Pembangunan (non-OECD) meningkat lebih dari dua kali lebih cepat dari OECD (Gambar 3-1). Pertumbuhan terkuat konsumsi gas alam diproyeksikan untuk negara-negara non-OECD Asia, di mana pertumbuhan ekonomi menyebabkan meningkatnya permintaan. Konsumsi gas alam di wilayah non-OECD tumbuh rata-rata 2,5 tahun dari tahun 2012 sampai 2040, dibandingkan dengan tahun 1,1 tahun di negara-negara OECD. Akibatnya, negara-negara non-OECD menyumbang 76 dari total kenaikan konsumsi gas alam dunia, dan pangsa penggunaan gas alam dunia tumbuh dari 52 pada tahun 2012 menjadi 62 pada tahun 2040. data angka Untuk memenuhi permintaan gas alam yang meningkat yang diproyeksikan di Kasus Referensi IEO2016, produsen gas alam dunia mencapai persediaan hampir 69 dari tahun 2012 sampai 2040. Peningkatan produksi gas alam terbesar dari tahun 2012 sampai 2040 terjadi di Asia non-OECD (18,7 Tcf), Timur Tengah (16,6 Tcf), Dan Amerika OECD (15,5 Tcf) (Gambar 3-2). Di China sendiri, produksi meningkat sebesar 15,0 Tcf saat negara tersebut memperluas pengembangan sumber daya serpihnya. Amerika Serikat dan Rusia meningkatkan produksi gas alam masing-masing sebesar 11,3 Tcf dan 10.0 Tcf. Di Rusia, pertumbuhan produksi terutama didukung oleh peningkatan pengembangan sumber daya di negara Kutub Utara dan wilayah timur. Pertumbuhan produksi A. S. terutama berasal dari sumber daya serpih. Total produksi gas alam di China, Amerika Serikat, dan Rusia menyumbang hampir 44 dari keseluruhan kenaikan produksi gas alam dunia. Data angka Meskipun ada lebih banyak hal untuk dipelajari mengenai tingkat gas ketat, gas shale, dan sumber batubara metana, EPO2016 Reference case memproyeksikan peningkatan yang substansial pada persediaan tersebut terutama di China, Amerika Serikat, dan Kanada (Gambar 3- 3). Penerapan teknologi pengeboran horisontal dan teknologi reklamasi horisontal telah memungkinkan pengembangan sumber daya shale A. S., yang berkontribusi pada penggandaan perkiraan dua kali lipat untuk total sumber daya gas alam yang dapat dipulihkan secara internasional selama dekade terakhir. Shale gas menyumbang lebih dari separuh produksi gas alam A. S. dalam kasus Referensi IEO2016, dan gas ketat, shale gas, dan sumber batubara metana di Kanada dan China mencapai sekitar 80 dari total produksi pada tahun 2040 di negara-negara tersebut. Data angka Liquefied natural gas (LNG) menyumbang kenaikan pangsa perdagangan gas alam dunia dalam kasus Referensi. Perdagangan LNG dunia lebih dari dua kali lipat, dari sekitar 12 Tcf pada tahun 2012 menjadi 29 Tcf pada tahun 2040. Sebagian besar peningkatan kapasitas pencairan terjadi di Australia dan Amerika Utara, di mana banyak proyek pencairan baru direncanakan atau dalam pembangunan, yang banyak akan Menjadi operasional dalam dekade berikutnya. Pada saat yang sama, fasilitas yang ada di Afrika Utara dan Asia Tenggara kurang dimanfaatkan atau ditutup karena produksi menurun di banyak ladang tua yang terkait dengan fasilitas pencairan, dan karena konsumsi gas alam domestik lebih tinggi daripada ekspor. Konsumsi gas alam OECD OECD Americas Konsumsi gas alam tahunan di wilayah OECD Americas meningkat dengan stabil menjadi 40,1 Tcf pada tahun 2040 (Gambar 3-4), termasuk peningkatan 1,0 Tcf dari tahun 2012 sampai 2020 (0.4 tahun) dan 7,3 Tcf dari tahun 2020 sampai 2040 1,0 tahun). Wilayah OECD Amerika menyumbang 41 dari total kenaikan penggunaan gas alam oleh negara-negara OECD dan 13 dari kenaikan total konsumsi gas alam dunia selama periode proyeksi. Data angka Amerika Serikat8212 konsumen gas alam terbesar di dunia memperkuat wilayah OECD Americas dalam pertumbuhan konsumsi gas alam tahunan dengan peningkatan 4,2 Tcf dari tahun 2012 sampai 2040, atau 51 dari kenaikan total regionrsquos (Gambar 3-5). Sementara peraturan Clean Power Plan (CPP) baru-baru ini di Amerika Serikat tidak termasuk dalam kasus Referensi IEO2016, pengaruhnya dipertimbangkan dalam diskusi, tabel, dan angka sepanjang laporan, berdasarkan analisis Administrasi Informasi Energi AS (EIA) sebelumnya. Dari aturan yang diusulkan yang memiliki unsur serupa. Dengan penerapan CPP yang diusulkan, konsumsi gas alam A. S. akan menjadi 1,7 Tcf lebih tinggi pada tahun 2020 dibandingkan dengan kasus Referensi IEO2016. Sebagian besar kenaikan konsumsi gas alam akan terjadi di sektor tenaga listrik sebagai pengganti pembangkit berbahan bakar batu bara. Setelah 2020, efek CPP terhadap penggunaan gas alam di sektor listrik menurun seiring bertambahnya jumlah energi terbarukan. Pada tahun 2040, konsumsi gas alam A. S. yang diproyeksikan adalah 1,0 Tcf lebih rendah dengan CPP daripada pada kasus Referensi IEO2016. Efek CPP akhir pada pembangkit berbahan bakar gas alam akan bergantung pada harga gas alam, biaya teknologi terbarukan, dan keputusan implementasi tingkat negara bagian. Kenaikan penggunaan gas alam hingga tahun 2040 ini tentunya dimungkinkan dalam skenario dengan harga gas rendah dan strategi implementasi yang menguntungkan gas. Data angka Proyeksi untuk konsumsi gas alam tahunan gabungan di Meksiko dan Cile mencakup pertumbuhan mutlak di kedua negara dengan 2,2 Tcf (26 dari total kenaikan OECD Americas), diikuti oleh Kanada dengan 1,9 Tcf (23 dari total kenaikan OECD Americas). Semakin lama, Meksiko telah memenuhi permintaan listriknya yang terus meningkat dengan pembangkit dari unit gas alam, menggunakan gas alam yang diimpor melalui pipa dari Amerika Serikat, terutama sejak 2011 karena pertumbuhan konsumsi gas alam Mexicorsquos secara keseluruhan telah melampaui pertumbuhan produksi dalam negeri. Dalam kasus Referensi IEO2016, sektor tenaga listrik menyumbang 39 (3.2 Tcf) dari pertumbuhan konsumsi gas alam dari tahun 2012 sampai 2040 di wilayah OECD Americas, dengan 1,6 Tcf peningkatan yang terjadi di Meksiko dan Cile dan 1,3 Tcf di Kanada . Penggunaan gas alam di sektor industri OECD Americas tumbuh sebesar 1,4 Tcf dari tahun 2012 sampai 2020, dengan 1,3 Tcf (97) ditambahkan di Amerika Serikat, di mana konsumsi industri meningkat rata-rata 1,8 tahun. Pertumbuhan penggunaan gas alam di sektor industri A. S. melambat dari tahun 2020 sampai 2040 dengan rata-rata 0.5 tahun dan meningkat sebesar 1,0 Tcf selama periode tersebut. Di Kanada, konsumsi gas alam di sektor industri tumbuh rata-rata 0,19 tahun dari tahun 2012 sampai 2020 dan pada tahun 1.120 dari tahun 2020 sampai 2040. Di wilayah MexicoChile, penggunaan gas alam sektor industri tumbuh rata-rata dari tahun ke tahun dari tahun 2010 sampai 2020 Dan 1.2 tahun dari tahun 2020 sampai 2040. OECD Eropa Konsumsi gas alam di wilayah OECD Eropa tumbuh rata-rata 1,3 tahun, dari 17,8 Tcf pada tahun 2012 menjadi 25,3 Tcf pada tahun 2040 dalam kasus Referensi (Gambar 3-6), dengan tenaga listrik Sektor akuntansi selama lebih dari satu setengah (4,6 Tcf) dari total kenaikan. Kenaikan rata-rata 3,6 tahun dalam konsumsi gas alam untuk pembangkit listrik dari tahun 2020 sampai 2040 lebih tinggi daripada sumber energi lain yang digunakan di sektor ini. Pangsa gas alam dalam campuran pembangkit tenaga listrik diproyeksikan tumbuh, karena unit nuklir dan batu bara yang lebih tua akan secara bertahap dinonaktifkan dan diganti terutama oleh kapasitas pemuatan gas dan gas alam yang baru. Angka data Harga gas alam di Asia Di pasar Asia, tidak seperti di Amerika Serikat, harga gas alam biasanya mencerminkan kontrak yang diindeks terhadap harga minyak mentah atau produk minyak bumi. Penurunan harga minyak mentah antara Agustus 2014 dan Januari 2015 dan harga minyak yang rendah sejak saat itu (Gambar 3-7) memiliki pengaruh yang signifikan terhadap harga dan pasar gas alam Asia. Namun, negara-negara Asia sedang mengembangkan pusat perdagangan regional untuk menetapkan harga gas alam yang lebih mencerminkan dinamika pasar gas alam. Pada 2014, hampir 30 perdagangan global LNG terjadi pada jangka pendek 54 atau spot. Negara-negara Asia menyumbang tiga perempat dari total dan sepertiga dari perdagangan gas alam global 55. Dari 2011 hingga 2014, harga minyak mentah yang tinggi menghasilkan harga impor LNG yang lebih tinggi. Di Asia, sebagian besar gas alam diimpor sebagai LNG, dengan harga LNG diindeks secara tradisional ke minyak mentah secara jangka panjang dan kontraktual. Data angka Saat ini tidak ada pasar terintegrasi global untuk gas alam, dan mekanisme harga bervariasi oleh pasar regional. Dalam kebanyakan kasus, gas alam yang diperdagangkan secara internasional diindeks dengan harga minyak mentah, seperti minyak mentah Brent Laut Utara atau mentah Jepang-bersih (JCC), karena likuiditas dan transparansi harga minyak mentah dan substitusi produk gas alam dan minyak bumi di Beberapa pasar. Misalnya, beberapa negara Asia memiliki opsi untuk membakar gas alam atau minyak bumi untuk pembangkit listrik. Meskipun kontrak jangka panjang yang diindeks oleh harga minyak mentah tetap merupakan mekanisme penetapan harga mayoritas Asiarsquos, gas alam mulai diperdagangkan dalam transaksi satu kali di pasar spot, atau di bawah kontrak jangka pendek yang lebih dekat mencerminkan pasokan gas alam internasional dan saldo permintaan. . Perdagangan LNG jangka pendek dan spot di pasar Asia Pasifik hampir tiga kali lipat dari tahun 2010 sampai 2014 (Gambar 3-8), ketika mewakili 21 perdagangan LNG global dan 7 perdagangan gas alam. Data angka Beberapa negara Asia termasuk Jepang, China, dan Singapura yang mengembangkan pusat perdagangan regional dengan tujuan meningkatkan transparansi formasi harga: Pada bulan September 2014, Jepang meluncurkan kontrak berjangka LNG untuk pertukaran over-the-counter Jepang (JOE), diselesaikan terhadap Rim Intelligence Co. Daily Pricing Index. Namun, hanya satu perdagangan yang telah dilakukan di JOE sejak awal. Kurangnya konektivitas pipa negara dengan pasar lain, volume LNG fleksibel yang rendah, dan kurangnya transparansi dan likuiditas harga LNG memiliki aktivitas perdagangan LNG spot terbatas pada JOE. Pada bulan Juni 2015, Singapores Stock Exchange meluncurkan Singapore SGX LNG Index Group (SLInG). Indeks tersebut akan memberikan harga on-board gratis (tidak termasuk ongkos kirim) untuk kargo LNG dari Singapura ke berbagai tujuan yang mencerminkan harga spot regional. Hingga Juni 2015, 13 pelaku pasar telah mendaftar untuk berpartisipasi dalam indeks, dan 10 lagi diperkirakan akan bergabung, volume perdagangan sampai saat ini moderat. Pada tanggal 1 Juli 2015, China meluncurkan Shanghai Oil and Gas Exchange, yang akan memperdagangkan gas pipa dan LNG. Pasar gas alam diversifikasi Chinarsquos, dengan perluasan infrastruktur pipa dan persaingan gas-on-gas, mungkin menawarkan indeks harga gas alam yang lebih cair, namun peraturan pemerintah tingkat tinggi membuatnya kurang menarik sebagai patokan regional. Di Eropa, di mana gas alam diimpor baik melalui pipa dan sebagai LNG, harga gas alam diindeks dengan harga minyak mentah atau berdasarkan pasar spot. Meskipun sebagian besar perdagangan di Eropa didasarkan pada kontrak jangka panjang, perdagangan spot berbasis hub telah meningkat secara signifikan selama dekade terakhir. Harga patokan utama untuk spot trading adalah National Balancing Point (NBP) di Inggris dan Title Transfer Facility (TTF) di Belanda. Harga NBP dan TTF memiliki pengaruh yang kuat terhadap harga hub di pasar Eropa lainnya karena likuiditas dan interkonektivitasnya dengan benua Eropa. Hub perdagangan lainnya di benua Eropa tumbuh dalam hal volume yang diperdagangkan dan jumlah hub dan peserta. Dengan meningkatnya volume dan likuiditas di hub Eropa, harga hub mulai memainkan peran lebih besar. Beberapa kontrak pipa baru-baru ini di benua Eropa sekarang mencakup harga berbasis hub, bukan hubungan tradisional dengan sekeranjang produk minyak mentah. Harga di Henry Hub, tolok ukur gas alam A. S., juga dapat mempengaruhi harga global melalui perdagangan LNG. Pada tahun 2020, ketika semua proyek pencairan AS saat ini diharapkan selesai, Amerika Serikat akan memperhitungkan hampir seperlima kapasitas likuifaksi global dan akan memiliki kapasitas ekspor LNG terbesar ketiga di dunia (setelah Qatar dan Australia). Hampir 80 volume ekspor LNG A. S. untuk proyek yang saat ini sedang dibangun telah dikontrak dengan syarat harga yang terkait langsung dengan harga Henry Hub, atau di bawah mekanisme harga hibrida dengan hubungan dengan Henry Hub. Fleksibilitas klausa tujuan dalam kontrak ekspor LNG A. S. dan pengenalan indeks hub diharapkan dapat mendorong likuiditas yang lebih besar dalam perdagangan LNG global, mengalihkan harga dari indeks berbasis minyak, dan berkontribusi pada pengembangan hub perdagangan regional Asia dan indeks harga. Konsumsi gas alam di OECD Asia tumbuh rata-rata 1,6 tahun pada kasus Referensi IEO2016, dari 7,9 Tcf pada tahun 2012 menjadi 12,2 Tcf pada tahun 2040, dengan konsumsi Jepang meningkat rata-rata 0,9 tahun. Jepang terutama mengandalkan pengiriman kargo LNG jangka pendek dan spot untuk mengimbangi hilangnya kapasitas pembangkit nuklir ketika sebagian besar kapasitas pembangkit nuklirnya ditutup setelah reaktor daya Daiichi Fukushima mengalami kerusakan parah pada gempa dan tsunami bulan Maret 2011. . Semua kecuali 2 dari 50 reaktor negara masih offline pada Januari 2016 56, dan masalah lingkungan telah mendorong pemerintah untuk mendorong konsumsi gas alam, menjadikan LNG sebagai bahan bakar pilihan pembangkit listrik untuk menggantikan pembangkit nuklir yang hilang. Menurut International Gas Union, Jepang mengoperasikan 23 terminal impor LNG utama di tahun 2014, termasuk perluasan dan terminal satelit, dengan total kapasitas pengiriman gas 9 Tcfyear jauh melampaui permintaan 57. Dari tahun 2020 sampai 2040, GDP riil Jepangrsquo meningkat rata-rata 0,5 tahun, sejauh ini merupakan yang terendah di wilayah ini, akibat turunnya populasi dan angkatan kerja yang menua. Meskipun konsumsi gas alam Japanrsquos tidak melambat antara 2020 dan 2040, konsumsi energi dari cairan dan batubara menurun. Akibatnya, pangsa gas alam konsumsi energi Jepang mencapai 25 dari 2020 sampai hampir 30 pada 2040. Konsumsi gas alam Korea Selatan tumbuh rata-rata 2,3 tahun dari tahun 2012 sampai 2020 dan 1,7 tahun dari tahun 2020 sampai 2040 di IEO2016. Kasus referensi Pertumbuhan permintaan gas alam di sektor industri, permukiman, dan komersial Korea Selatan melambat, sementara di sektor tenaga listrik tetap di atas 2 tahun sepanjang periode 2012821140. Australia dan Selandia Baru memiliki pertumbuhan tahunan rata-rata OECD Asias terkuat dalam konsumsi gas alam sektor listrik dari 2012 sampai 2040 dalam kasus Referensi IEO2016, rata-rata 4,6 tahun dan lebih dari tiga kali lipat, dari 0,4 Tcf pada tahun 2012 menjadi 1,5 Tcf pada tahun 2040 (Gambar 3-9 ). Australia meningkatkan pangsa gas alam dalam campuran pembangkit listriknya untuk mengurangi pembangkit berbahan bakar batubara yang intensif karbon. Dua negara gabungan pangsa penggunaan gas alam OECD Asiarsquos untuk pembangkit listrik tumbuh dari 10 pada tahun 2012 menjadi 21 pada 2040 dalam kasus Referensi IEO2016. Data angka Konsumsi gas non-OECD Non-OECD Eropa dan Eurasia Negara-negara non-OECD Eropa dan Eurasia mengandalkan gas alam untuk 47 kebutuhan energi primer mereka pada tahun 2012mulai kelompok tertinggi kedua di antara negara-negara pengekspor di IEO2016, setelah Timur Tengah. Non-OECD Eropa dan Eurasia mengkonsumsi total 23,0 Tcf gas alam pada tahun 2012, yang paling luar OECD dan lebih banyak daripada wilayah lain di dunia kecuali Amerika OECD. Russiarsquos 15,7 Tcf konsumsi gas alam pada tahun 2012 menyumbang 68 dari total populasi non-OECD Eropa dan Eurasia (Gambar 3-10). Data angka Dalam kasus Referensi IEO2016, konsumsi gas alam secara keseluruhan di Eropa non-OECD dan Eurasia tumbuh rata-rata 0,4 tahun dari tahun 2012 sampai 2040, termasuk penurunan 0,3 tahun dari tahun 2012 sampai 2020 dan meningkat 0,7 tahun dari tahun 2020 menjadi 2040, untuk total kenaikan 2,9 Tcf selama periode 2012821140. Dengan Rusia hanya menghitung sekitar 10 dari total kenaikan regionrsquos, kenaikan rata-rata untuk wilayah non-OECD Eropa dan Eurasia lainnya adalah 1.1 tahun, dibandingkan dengan rata-rata Russias yang berusia 0.1 tahun. Di sektor tenaga listrik, konsumsi gas alam turun rata-rata 0.1year dari tahun 2012 sampai 2040 di Rusia karena pertumbuhan penggunaan energi secara keseluruhan melambat namun tumbuh rata-rata 1,4 tahun di wilayah negara-negara lain. Non-OECD Asia Di antara semua wilayah di dunia, pertumbuhan tercepat konsumsi gas alam dalam kasus Referensi IEO2016 terjadi di Asia non-OECD. Penggunaan gas alam di Asia non-OECD meningkat rata-rata 4,4 tahun, dari 15,1 Tcf pada tahun 2012 menjadi 50,8 Tcf pada tahun 2040 (Gambar 3-11). Selama periode tersebut, Asia non-OECD menyumbang lebih dari 40 dari total pertumbuhan inkremental penggunaan gas alam dunia, bergerak dari posisi saat ini sebagai daerah konsumsi gas alam terbesar keempat di dunia ke daerah konsumsi gas alam terbesar kedua di tahun 2030 Dan konsumen terbesar di tahun 2040. OECD Asiarsquos total konsumsi gas alam meningkat dari kurang dari setengah wilayah OECD Amerika pada tahun 2012 menjadi lebih dari 25 di atas total OECD Americas pada tahun 2040, dan pangsa total konsumsi gas alam dunia meningkat dari 13 Pada tahun 2012 menjadi 25 pada tahun 2040. Data angka China menyumbang hampir dua pertiga (63) pertumbuhan konsumsi gas alam non-OECD Asias dari tahun 2012 sampai 2040. Total konsumsi gas alam di China meningkat rata-rata 6,19 tahun Kasus Referensi IEO2016, dari 5.1 Tcf pada tahun 2012 menjadi 27,5 Tcf pada tahun 2040. Pemerintah pusat Chinarsquos mempromosikan gas alam sebagai sumber energi yang lebih disukai dan telah menetapkan target ambisius untuk meningkatkan pangsa alam. Gas dalam campuran energi keseluruhannya sampai 10 (atau sekitar 8,8 Tcf) pada tahun 2020 untuk mengurangi polusi dari penggunaan batubara beratnya 58. Dalam kasus Referensi IEO2016, konsumsi gas alam di China berjumlah 9,1 Tcf pada tahun 2020, atau sekitar 6 dari total konsumsi energi negara. Pada tahun 2040, pangsa gas alam konsumsi energi Chinarsquos adalah 158212 kurang dari jumlah batubara. Namun, tingkat pertumbuhan rata-rata tahunan 6,2 untuk konsumsi gas alam dari tahun 2012 sampai 2040 jauh di bawah tingkat pertumbuhan energi nuklir sebesar 9,7. Di India, gas alam menyumbang sekitar 8 dari total konsumsi energi pada tahun 2012, hampir dua kali lipat dalam campuran energi Chinas. Di negara-negara lain di Asia non-OECD, penggunaan gas alam menyumbang 23 dari keseluruhan konsumsi energi pada tahun 2012, dan pangsanya meningkat menjadi 25 pada tahun 2040 dalam kasus Referensi IEO2016, karena konsumsi gas alam meningkat rata-rata 2,8 tahun, dari 7,9 Tcf pada tahun 2012 menjadi 17,2 Tcf pada tahun 2040. Meskipun gas alam tetap merupakan sumber konsumsi energi terbesar kedua setelah cairan, tingkat pertumbuhan tahunannya kurang dari tarif energi terbarukan (3,4) dan energi nuklir (2,9). Timur Tengah Di kawasan Timur Tengah, gas alam menyumbang hampir setengah dari total konsumsi energi pada tahun 2012, lebih banyak daripada di wilayah lain. Dalam kasus Referensi IEO2016, konsumsi gas alam Timur Tengah meningkat rata-rata 2,5 tahun dari tahun 2012 sampai 2040, dan sektor industri menyumbang porsi terbesar konsumsi total gas alam wilayah (Gambar 3-12). Penggunaan gas alam di sektor industri tumbuh sebesar 7,7 Tcf dari tahun 2012 sampai 2040, mencakup lebih dari setengah dari 14,2 Tcf peningkatan total konsumsi gas alam. Di sektor tenaga listrik, penggunaan gas alam tumbuh 5,2 Tcf dari tahun 2012 sampai 2040, bila mencapai 9,8 Tcf. Pembangkit gas alam menghasilkan sebagian dari pasar karena penggunaan minyak mentah untuk penurunan pembangkit listrik. Data angka Konsumsi gas alam Afric sebesar 11,1 Tcf pada tahun 2040 dalam kasus Referensi IEO2016, atau 2,5 kali total tahun 2012 (Gambar 3-13). Penggunaan gas alam regionrsquos meningkat rata-rata 3,3 tahun dari tahun 2012 sampai 2040, tingkat yang kedua setelah kenaikan rata-rata 4,4 tahun untuk energi nuklir selama periode yang sama. Sektor tenaga listrik dan industri Afric mencakup 79 dari kenaikan kebutuhan gas alam dari tahun 2012 sampai 2040 dan untuk 84 dari total kebutuhan gas alam pada tahun 2040. Konsumsi gas alam di sektor tenaga listrik tumbuh dari 2,2 Tcf pada tahun 2012 menjadi 5.5 Tcf pada tahun 2040, terhitung 49 dari total kenaikan penggunaan gas alam Africarsquos selama periode tersebut. Lebih dari 85 kenaikan penggunaan gas alam untuk pembangkit listrik di Afrika terjadi dari tahun 2020 sampai 2040, bila rata-rata berusia 3,6 tahun, dibandingkan dengan rata-rata kurang dari 2,5 tahun dari tahun 2012 sampai 2020. data angka Non-OECD Americas Natural gas Konsumsi di wilayah non-OECD Amerika meningkat rata-rata 2,0 tahun dalam kasus Referensi IEO2016, dari 5,1 Tcf pada tahun 2012 menjadi 8,9 Tcf pada tahun 2040 (Gambar 3-14). Sektor industri menyumbang lebih dari sepertiga pertumbuhan konsumsi dari tahun 2012 sampai 2040, diikuti oleh sektor tenaga listrik sekitar seperempatnya. Konsumsi gas alam Brazilrsquos tumbuh rata-rata 2,6 tahun dari tahun 2012 sampai 2040, atau dengan total 1,1 Tcfmdashmore dari 25 dari keseluruhan kenaikan 3,9 Tcf untuk wilayah non-OECD Amerika. Kenaikan dari 0,7 Tcf pada tahun 2012 menjadi 1,4 Tcf pada tahun 2040 di konsumsi gas alam sektor industri Brazil mencapai lebih dari 60 dari total peningkatan penggunaan gas alam dari negara tersebut dari tahun 2012 sampai 2040. Konsumsi gas alam baik di sektor industri dan tenaga listrik Tumbuh sekitar 2.3 tahun dari tahun 2012 sampai 2040, ketika sektor industri menyumbang 64 dan sektor tenaga listrik menyumbang 22 dari total konsumsi gas alam Brazilrsquos. Data angka Produksi gas alam dunia Untuk memenuhi proyeksi pertumbuhan penggunaan gas bumi dalam kasus Referensi IEO2016, pasokan gas alam dunia meningkat hampir 83 Tcf (69) dari tahun 2012 sampai 2040. Sebagian besar kenaikan pasokan diproyeksikan berasal dari luar - OECD negara, yang dalam kasus Referensi menyumbang 73 dari total kenaikan produksi gas alam dunia dari tahun 2012 sampai 2040. Produksi gas alam non-OECD tumbuh rata-rata 2,1 tahun, dari 75 Tcf pada tahun 2012 menjadi 136 Tcf pada tahun 2040 (Tabel 3-1), sementara produksi OECD tumbuh sebesar 1,4 tahun, dari 44 Tcf sampai 66 Tcf. Produksi dari sumber daya yang terus menerus tumbuh dengan cepat dalam proyeksi, dengan gas ketat OECD, shale gas, dan produksi metana batu bara rata-rata 3,0 tahun, dari 20 triliun kubik pada tahun 2012 menjadi 47 Tcf pada tahun 2040. Selama periode yang sama, produksi gas ketat non-OECD , Shale gas, dan coalbed methane tumbuh dari hampir 2 Tcf sampai 34 Tcf. Namun, banyak ketidakpastian yang dapat mempengaruhi produksi sumber daya di masa depan. Masih ada variasi yang cukup besar di antara perkiraan sumber gas serpih yang dapat dipulihkan di Amerika Serikat dan Kanada, dan perkiraan gas ketat, gas shale, dan coalbed methane yang dapat dipulihkan untuk bagian dunia lainnya lebih tidak pasti, mengingat data yang jarang tersedia saat ini. Selain itu, proses rekahan hidrolik yang digunakan untuk menghasilkan sumber daya gas shale sering membutuhkan air dalam jumlah yang signifikan, dan pasokan air yang tersedia terbatas di banyak wilayah dunia yang telah diidentifikasi memiliki sumber daya shale gas. Masalah lingkungan lebih lanjut juga dapat menambah ketidakpastian seputar akses terhadap sumber gas shale. Produksi OECD OECD Produksi gas alam Amerika di OECD Americas tumbuh pada tahun 49 dari tahun 2012 sampai 2040. Amerika Serikat, yang merupakan produsen terbesar di OECD Americas dan OECD secara keseluruhan, menyumbang lebih dari dua pertiga wilayah Total pertumbuhan produksi dari 24 Tcf pada tahun 2012 menjadi 35 Tcf pada tahun 2040 (Gambar 3-15). Produksi gas serpih A. S. tumbuh dari 10 Tcf pada tahun 2012 menjadi 20 Tcf pada tahun 2040, lebih dari mengimbangi penurunan produksi gas alam dari sumber lain. Pada tahun 2040, gas shale menyumbang 55 dari total produksi gas alam AS dalam kasus Referensi IEO2016, rekening gas ketat untuk 20, dan produksi lepas pantai dari 48 negara bagian bagian atas menyumbang 8. Sisanya 17 berasal dari coalbed methane, Alaska, dan lainnya. Sumber daya lepas pantai yang terkait dan tidak terkait di Lower 48 negara bagian. Angka data Produksi gas alam di Kanada tumbuh rata-rata 1,2 tahun selama periode proyeksi, dari 6,1 Tcf pada tahun 2012 menjadi 8,6 Tcf pada tahun 2040. Di Kanada, seperti di Amerika Serikat, sebagian besar pertumbuhan produksi berasal dari meningkatnya volume gas ketat. Dan produksi gas shale. Produksi gas alam Mexicos relatif datar di tengah hari, namun lebih dari dua kali lipat di tahun-tahun berikutnya dari proyeksi tersebut, karena produksi dari sumber energi shale tumbuh, didukung oleh reformasi energi baru-baru ini di negara tersebut. Total produksi gas alam di Meksiko meningkat dari 1,7 Tcf pada tahun 2012 menjadi 3,3 Tcf pada tahun 2040. Seperti Kanada dan Amerika Serikat, Meksiko diperkirakan memiliki sumber gas shale yang substansial, yang paling prospektif adalah perpanjangan dari Eagle Ford Shale yang sukses di Amerika Serikat. Namun, karena sumber daya serpih di Meksiko belum dieksplorasi sepenuhnya seperti di wilayah Amerika Utara lainnya, ada lebih banyak ketidakpastian seputar perkiraan ukuran dan potensi produksi mereka. OECD Eropa Norwegia, Belanda, dan Inggris adalah tiga produsen gas alam terbesar di OECD Eropa, mencakup lebih dari 80 daerah total produksi gas alam pada tahun 2012. Dalam kasus Referensi IEO2016, produksi gas alam OECD Europersquos menurun. Pada pertengahan dan kemudian mulai tumbuh lagi di bagian akhir proyeksi, karena produksi dari gas ketat, shale gas, dan sumber daya metana batu bara menjadi lebih signifikan (Gambar 3-16). Secara keseluruhan, produksi gas alam di OECD Eropa pada tahun 2040 adalah 1,6 Tcf lebih tinggi dari tahun 2012. Berkontribusi pada produksi total OECD Europes adalah pertumbuhan produksi gas alam dari Israel, yang menjadi negara anggota OECD pada bulan September 2010 dan termasuk dalam OECD Europe for Tujuan pelaporan statistik Data angka Produksi gas alam di wilayah AustraliaNew Zealand meningkat dari 2,1 Tcf pada tahun 2012 menjadi 7,0 Tcf pada tahun 2040 dalam kasus Referensi IEO2016, pada tingkat rata-rata 4,4 tahun. Pada tahun 2012, lebih dari 90 produksi di wilayah AustraliaNew Zealand berasal dari Australia, dengan produksi di Western Australia (termasuk area Northwest Shelf of Australias Carnarvon Basin) terhitung sekitar 58 dari total produksi negara tersebut 59. Sebagian besar produksi Australias digunakan sebagai bahan baku di fasilitas pencairan LNG Northwest Shelf. Demikian pula, banyak perkembangan lapangan gas alam Australiarsquos yang baru terkait dengan proyek pencairan yang memiliki beberapa kontrak ekspor. 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