Turkmenistan Energy Sector — Infrastructure and Operations Brief, 2024–2026

The reserves question is settled, and has been for years. The Energy Institute Statistical Review of World Energy (2025 edition) puts country-level proven reserves at 13.6 tcm — the figure carried unchanged from the 2021 BP edition. Earlier BP editions (e.g. 2016) placed reserves as high as 17.5 tcm, so the 13.6 to 17.5 tcm range reflects historical revisions rather than current uncertainty. The Energy Institute methodology ranks Turkmenistan fourth globally behind Russia, Iran, and Qatar; the US EIA, on a different methodological basis, ranks it fifth.

Gaffney Cline's 2011 probabilistic audit assessed the Galkynysh field alone at recoverable resources of 13.1 tcm (low) / 16.4 tcm (best) / 21.2 tcm (high). The field covers roughly 2,700 sq km. What makes Galkynysh interesting is not the volume but the chemistry. The principal production zones lie in Upper Jurassic Callovian-Oxfordian carbonate platform reservoirs at 3,900 to 5,100 metres, beneath the Gaurdak Formation evaporite seal. The Lower Cretaceous Shatlyk sandstones — the dominant reservoir at the older Dauletabad field — are a secondary horizon at Galkynysh. Per GPA Europe, feed gas runs hydrogen sulfide up to 6% and carbon dioxide up to 7%. That places Galkynysh among the most aggressive sour-service environments in commercial production anywhere in the world.

The processing buildout came in two waves. Three desulfurisation trains were contracted in December 2009 and brought into service at Galkynysh in 2013, each rated at 10 bcm/yr, for 30 bcm/yr of total sour-gas capacity. The EPCs were distributed across three contractors: Petrofac at $3.4 billion, an LG International and Hyundai Engineering consortium at $1.48 billion, and CNPC's Chuanqing Drilling at $3.13 billion. Gulf Oil & Gas FZE took the parallel $1.15 billion EPC for production wells. Two older plants in the Bagtyyarlyk contract area — GPP-1 Samandepe and GPP-2 Hojambaz — handle additional volumes.

Petrofac extended its operations support contract at the Galkynysh CPF-1 and CPF-1A facilities on 8 March 2024 under a roughly three-year, $200 million agreement with Turkmengaz — a quiet vote of continuity from one of the original Phase 1 EPC counterparties.

The second wave is just starting. The Galkynysh Phase 4 turnkey contract was signed on 16 April 2026 between Turkmengaz and CNPC, with the groundbreaking held on 17 April 2026 in the presence of PRC Vice Premier Ding Xuexiang and former President Gurbanguly Berdimuhamedov, following the 20 March 2026 presidential authorising resolution. The $4.6 billion turnkey EPC — disclosed via the Shanghai Stock Exchange on 24 April 2026 — was signed by China Petroleum Engineering and Construction Corporation (CPECC), a wholly-owned subsidiary of the listed China Petroleum Engineering Corporation (CPE Corp., 600339.SH), itself affiliated with CNPC. Turkmengaz chairman Maksat Babaev put total project value at approximately $5.1 billion. Phase 4 will add roughly 10 bcm/yr of marketable gas processing capacity over a 48-month construction window following a 3-month basic-design phase.

The pipeline picture is three stories told at once: a working east-bound system, a dormant Soviet-era line going north, and a frozen southern corridor. Total nominal export capacity sits at approximately 125 bcm/yr.

The east-bound system is the one that earns. The Central Asia to China Gas Pipeline (CAGP A/B/C) provides 55 bcm/yr of nominal capacity to China and ran at roughly 32 to 35 bcm/yr through 2024 and 2025. Per CNPC technical disclosures, Lines A and B trunklines are 1,067 mm (42-inch) diameter and Line C is 1,219 mm (48-inch) X80 grade, with principal construction contractors on the Turkmen section including Stroytransgaz, China Petroleum Pipeline Bureau, CPECC, and Zeromax. Cumulative deliveries to China reached approximately 460 bcm by April 2026. Utilisation at roughly 60% of nominal capacity is not a sign of underperformance — it signals headroom in the existing trunklines before any new pipeline is needed. New pipelines are required only for diversification, not volume growth.

The CAGP Line D extension — designed for 30 bcm/yr via Uzbekistan, Tajikistan, and Kyrgyzstan — has been delayed for years pending finalisation of upstream supply and transit pricing. The 2 September 2025 Russia–China memorandum on Power of Siberia 2, adding 50 bcm/yr of Russian export capacity to China, did real damage to the near-term commercial case for Line D. Treat it as long-dated optionality, not a near-term construction programme.

The Central Asia Centre system provides approximately 50 bcm/yr of nominal capacity into the former Soviet network. Most of that capacity is parked. The Gazprom export contract expired on 30 June 2024 and was not renewed. It is in this report because it exists, not because it is moving meaningful volume.

The Iran corridor has been formally suspended since 1 January 2017. Korpeje to Kurt Kui (1997, 8 bcm/yr) and Dauletabad to Sarakhs to Khangiran (2010, 12.5 bcm/yr) together represent 20.5 bcm/yr of nominal capacity sitting idle. The infrastructure is in place. Reactivation is a sanctions and counterparty question, not an engineering one.

TAPI is designed at 1,814 km with 33 bcm/yr capacity. Turkmenistan completed its 214 km section in 2024. The Afghan section was ceremonially launched on 11 September 2024. As of October 2025, 14 km had been laid in Afghanistan with roughly 70 km of additional route prepared. Construction depends on security in Afghanistan, financing willingness, and offtake commitments from Pakistan and India that remain uncertain. The Trans-Caspian Pipeline, engineered at roughly 300 km with 30 bcm/yr design capacity, has held EU Project of Common Interest status since 2013. The engineering is settled. Construction has not begun.

The cumulative capex cycle is among the most sustained in the Eurasian energy sector outside Russia, and until Phase 4 it had a consistent shape: large EPCs paid for through Chinese policy bank lending, with a smaller multilateral component. The principal items since 2007 total more than $20 billion.

Phase 4 broke the pattern. The April 2026 EPC, valued at $4.6 billion within a $5.1 billion project total, is being financed entirely from Turkmen state resources. Earlier cycles leaned heavily on Chinese Development Bank credit and on EPC contractors carrying paper of their own. Phase 4 does neither. It is, regardless of the reason, the most distinctive feature of the current capex window — and the detail that most distinguishes the current cycle from everything that preceded it.

Four risk categories sit on top of the gas business: sour-service chemistry, seismic exposure, legacy infrastructure, and methane management. Three are well managed. The fourth is the open file.

One further constraint bears noting. Disaggregated production, flaring, and incident data are not publicly reported at the level Western technical analysts typically expect, though state actors have acknowledged the gap and initiated mitigation steps. Country-level reserve audits are published; field-level production reporting is not. That gap should be priced into any quantitative claim that depends on Turkmen-side disclosure rather than independent measurement.

The 2026 to 2030 window is shaped by Phase 4 and by what does not happen elsewhere. Phase 4 commissioning is the principal milestone. Vice Premier Ding Xuexiang's attendance at the April 2026 groundbreaking signalled high-level political backing, and the all-state financing structure removes one familiar source of delay. Once on stream, Phase 4 supports sustained 30 to 40 bcm/yr export volumes through the next decade, structured to service both domestic and export markets per Turkmengaz.

The pipeline side will likely look much the same in 2030 as it does today. CAGP A/B/C utilisation at roughly 60% of nominal leaves headroom in the existing trunkline system — which means new pipelines are not required to grow exports. They are required only for diversification. Latent capacity in the idle Iran corridor (20.5 bcm/yr nominal) and in the Iran–Iraq swap framework (10 bcm/yr design) represents physical infrastructure that could be reactivated if commercial and sanctions conditions allow, but neither is presently moving.

TAPI physical construction will track security and financing conditions in Afghanistan plus the readiness of Pakistan and India to commit to offtake. The Afghan-section work, while progressing, may end up serving a primarily Turkmenistan-to-Afghanistan corridor in the near term rather than the full four-country pipeline its design envisions. Trans-Caspian remains in pre-construction status with no financing or legal pathway initiated. CAGP Line D, while still on the planning agenda, faces materially weaker near-term commercial logic following the Power of Siberia 2 memorandum, which absorbs much of China's incremental pipeline-gas demand growth.