Viewpoint: Mexico reliance on US gas to strengthen

: Electricity, Natural gas
22/01/03

Mexico's demand for US natural gas grew to a record high in 2021, with imports expected to grow in 2022 despite political uncertainty.

Even as President Andres Manuel Lopez Obrador calls for energy independence, Mexico remains heavily reliant on gas imports for power generation, most of which comes into the country via US pipeline interconnections. Gas imports from the US made up 76pc of Mexico's supplies by the middle of 2021, according to the US Energy Information Administration (EIA), a 36 percentage point increase from the same time in 2015.

US exports by pipeline to Mexico averaged around 6 Bcf/d (170mn m³) in January-August, according to EIA data, 12pc higher than the same eight months in 2020. Pipeline exports reached a peak of 7.4 Bcf/d on 17 June as cooling needs combined with recovering industrial demand from the Covid-19 pandemic.

Mexico's own gas production and LNG imports have fallen as pipelines between the two countries come on line. State-owned Pemex produced an average 4.6 Bcf/d of gas in October, down by 4.1pc from the same time in 2020.Pemex aims to boost production to 5.25 Bcf/d of natural gas by 2022, but it has frequently missed output targets.

Gas demand will likely increase over the next several years as Mexico's electricity needs grow with industrial activity returning to pre-pandemic levels. Though power reform remains a key 2022 concern among the country's business community, the question is whether Mexico's public sector can provide sufficient generation capacity, not whether demand will abate.

Lopez Obrador sent a constitutional electricity reform bill to congress in October that would cap private-sector participation at 46pc. The move would cancel private-sector permits for power generation totaling 40,924MW, or 48pc, of Mexico's installed capacity, essentially making Mexico's state-owned Federal Electricity Commission (CFE) dominant in the power sector.

CFE has announced plans for several power plants, indicating expected demand growth. Though little public information is available, CFE's combined projects would increase gas demand in Mexico by approximately 785mn cf/d, according to Eduardo Prud'homme, co-partner at energy consulting firm Gadex. More than half of the projects have estimated start dates of 2024.

Despite the anticipated demand growth for gas-fired power, private-sector investments for gas and power in Mexico are uncertain following Lopez Obrador's shift away from 2013 energy policy reforms. Lopez Obrador's regulatory and legislative moveshave led to postponements of power and manufacturing projects, potentially stunting growth through the remainder of his term, which is set to end in September 2024.

Increased gas interconnection projects within Mexico remain jammed by environmental grievances, negotiations with state agencies and other political issues. TC Energy has repeatedly postponed the completion of its 886mn cf/d Tula-Villa de Reyes natural gas pipeline to 2022. Delays first stemmed from issues related to the Covid-19 pandemic, followed by contract negotiations with CFE. Other lines have been delayed as indigenous groups opposed the pipeline routes.

But pipelines connecting to Mexico have continued to progress in the US, increasing potential US export capacity. The 2 Bcf/d Whistler pipeline — which came on line in July — added a new connection from the Permian basin of west Texas and New Mexico to the Agua Dulce Hub in southeast Texas. Agua Dulce is a supply point for several pipelines that cross the Texas-Mexico border.

TC Energy plans to expand its North Baja natural gas pipeline system — which serves power generators in southern California and Mexico's Baja Peninsula — with a potential startup in 2022, according to EIA data.

Mexico's gas market conditions have also started to more closely track US market conditions as the US-Mexico pipeline network has expanded, particularly between northern Mexico states and west US hubs. Prices at the Waha hub — the main indicator for the value of Permian gas — averaged $3.28/mmBtu for flow in December 2021, up by 36pc from December 2020. The El Encino index in Chihuahua state, which is supplied by the Permian basin, averaged $3.89/mmBtu for December 2021, a 61¢/mmBtu premium to Waha for the same period. El Encino prices averaged a slightly wider 68¢/mmBtu premium in November 2021.

By David Haydon

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25/06/12

Malaysia’s oil, gas projects to emit 4bn t GHG: CREA

Singapore, 12 June (Argus) — Malaysia's continued extraction and use of its oil and gas resources could emit around 4bn t of greenhouse gases (GHGs), according to a report by the Helsinki-based Centre for Research on Energy and Clean Air (CREA). Malaysia holds about 9.84bn bl of oil equivalent (boe) in committed fossil fuel reserves, of which 82pc is gas, stated the report, which was written in collaboration with environmental think-tank RimbaWatch. This figure only includes projects with proven reserves that are covered by a production commitment such as production sharing contracts. These committed reserves would also emit an estimated 4.15bn t of CO2 equivalent (CO2e), which is equivalent to 13 years of Malaysia's annual emissions. The emissions will also consist of 10.9mn t of methane, which is a much more potent GHG than CO2. Malaysia's remaining commercially recoverable reserves are estimated at over 17bn boe over more than 400 fields, with gas comprising about 75pc of this. Malaysia launched its national energy transition roadmap (NETR) in 2023, detailing initiatives to achieve its 2050 net zero carbon emissions target, such as renewable energy development, hydrogen and carbon capture, utilisation and storage (CCUS). The country aims to reduce its economy-wide carbon emissions by 45pc in 2030 compared with 2005 levels, under its nationally determined contribution — climate plan — to meet the goal of the Paris Agreement. But at the same time, the country is seeking to maximise its fossil fuel production to ensure energy security. State-owned Petronas raised its total oil and gas production in 2024 to 2.4mn b/d of oil equivalent (boe/d), up by 1pc on the year. Of this, oil production fell by 4.4pc on the year to 813,000 boe/d, while gas output rose by 3.6pc to 1.64mn boe/d. More than 80pc of Malaysia's power was generated from fossil fuels in 2024. The NETR plans to increase the share of gas in total primary energy supply by 16pc from 2023 to 57pc in 2050, with gas viewed as a transition fuel for decarbonisation. But "referring to gas as sustainable, and claiming that Malaysia can achieve net-zero emissions through growing gas, are oxymorons," stated the report. Petronas' Scope 1 and 2 greenhouse gas emissions totalled 46.04mn t of CO2e across its Malaysian operations in 2024, surpassing its target of 49.5mn t of CO2e for the year. In comparison, the firm recorded 45.6mn t of Scope 1 and 2 GHG emissions in 2023. But the firm's net zero pathway excludes its Scope 3 emissions, which make up about 80pc of a fossil fuel entity's emissions, according to the report. Additionally, its CCUS plans are aimed at enabling sour gas extraction, hence exacerbating fossil fuel production and emissions. Malaysia should instead set a sectoral carbon budget for the domestic energy sector in line with its net zero goals, taking into account both production and consumption, and cement this budget in the country's upcoming Climate Change bill, stated the report. By Prethika Nair Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Japan’s Jera signs LNG supply agreements with the US

25/06/12

Japan’s Jera signs LNG supply agreements with the US

Singapore, 12 June (Argus) — Japanese power producer Jera has signed multiple long-term LNG supply agreements with US partners over the past two months, to procure up to 5.5mn t/yr of LNG supply from the US over 20 years, the firm announced on 12 June. The agreements include a 2mn t/yr sales and purchase agreement (SPA) with US LNG firm NextDecade on 28 April, and a 1mn t/yr SPA with US developer Commonwealth LNG on 30 May. Jera has also signed non-binding interim agreements with Sempra Infrastructure — a subsidiary of US energy firm Sempra — for 1.5mn t/yr on 29 May, and with developer Cheniere for 1mn t/yr on 11 June. The deals offer competitive pricing and flexible contract terms. All supply will be delivered on a fob basis priced to the US' Henry Hub, allowing Jera to optimise shipping routes and respond flexibly to domestic demand and market conditions, the company said. If the four deals are considered as a single package of 5.5mn t/yr of supply, it is Jera's largest contract to date, senior managing executive officer Ryosuke Tsugaru said. The new agreements add to Jera's existing offtake contracts with the US, which include a combined 3.5mn t/yr of LNG from Texas' Freeport LNG and Louisiana's Cameron LNG, and approximately 1mn t/yr of LNG from developer Venture Global's CP2 project in Louisiana. US supplies could account for 30pc of Jera's long-term LNG portfolio in 2035, up from 10pc at present, a Jera spokesman told Argus . But Jera does not intend to increase its planned LNG handling volume of no less than 35mn t/yr up to the April 2035-March 2036 fiscal year, as some of its existing contracts are set expired in the middle of the 2030-31 fiscal year, Tsugaru said. The potential increase in Japan's US LNG procurement should help reduce the US' trade deficit with Japan, which could aid Tokyo's negotiations over import tariffs with the US administration. But Jera emphasised that neither Tokyo or Washington had requested or pressured it to sign the new supply contracts. The deals were Jera's decision to ensure stable supplies to Japan, Jera said. The Japanese government could use the US' proposed 20mn t/yr Alaska LNG export project as part of its tariff negotiations, as Alaska's proximity to Japan and its ample resources make it a promising import source for the east Asian country. Jera is waiting for more details to be announced about the project before it makes a decision on whether to step into an offtake deal, Tsugaru said. Jera dose not plan to invest in the development of the project, he added. Japan's LNG imports from the US rose by 15pc on the year to 6.34mn t in 2024. By Motoko Hasegawa and Joey Chan Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

EIA raises US 2026 renewables outlook

25/06/11

EIA raises US 2026 renewables outlook

Houston, 11 June (Argus) — The US renewable energy fleet remains on track to provide an increasing portion of the country's total electricity over the next two years, even with some changes in the US Energy Information Administration's (EIA) latest projections. Renewable energy is on track to supply almost 1.1bn MWh in 2025 and 1.2bn MWh in 2026, enough to account for roughly 25pc and 27pc of all US generation in those years, EIA said Tuesday in its monthly Short-Term Energy Outlook report. The 2025 estimate is less than 1pc lower than the agency's forecast in May, while the 2026 outlook is about 2pc higher. Renewables in 2024 generated almost 948mn MWh, about 23pc of all US generation. EIA attributes the higher share from renewables to projects coming on line through the end of 2026. The agency expects developers to add about 32,500MW of utility-scale solar to the grid this year, which would surpass the record high of 30,000MW in 2024. EIA anticipates about 7,700MW of new capacity from the wind sector this year. Wind capacity in 2024 expanded by about 5,100MW, its lowest showing since 2014. The month-over-month change in the larger renewables outlook corresponds with higher expectations for wind and solar generation next year. Wind farms are now on track to provide about 506mn MWh in 2026, while utility-scale solar farms will generate around 350mn MWh, each about 2pc higher from May's outlook. If the solar projection bears out, it would surpass hydropower in 2025 as the second most prevalent form of renewable generation in the US. In the Electric Reliability Council of Texas (ERCOT) territory, EIA expects non-hydropower renewable generators are on pace to supply nearly 179mn MWh in 2025, down by less than 1pc from last month's outlook. But the 216mn MWh now anticipated from the sector in 2026 marks an almost 10pc increase from May's predictions for the Texas grid. EIA's lowered its predictions for non-hydropower renewables in the New York Independent System Operator's footprint by less than 1pc for 2025 and by 4pc for 2026, to 11.5mn MWh and just under 13mn MWh, respectively. Revisions to other regional forecasts were minimal. EIA increased its expectations for non-hydropower renewables in the areas managed by the PJM Interconnection, ISO-New England and Midcontinent Independent System Operator by less than 1pc for both 2025 and 2026. Renewable energy resources for EIA's purposes include conventional hydropower, wind, solar projects larger than 1MW, geothermal and certain forms of biomass. By Patrick Zemanek Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

EQT signs 10-year gas deals with Duke, Southern

25/06/11

EQT signs 10-year gas deals with Duke, Southern

New York, 11 June (Argus) — US natural gas producer EQT has signed 10-year firm supply deals with US utilities Duke Energy and Southern Company for a combined 1.2 Bcf/d of gas beginning in 2027. EQT previously disclosed it struck deals to sell 800mn cf/d and 400mn cf/d of gas to "investment-grade utilities" in the southeastern US, but it has not disclosed the buyers. Those previously unnamed utilities are North Carolina-based Duke, which has contracted for 800mn cf/d from EQT, and Georgia-based Southern, which has contracted for 400mn cf/d, according to people with knowledge of the matter. EQT declined to comment for this story. Duke and Southern did not immediately respond to requests for comment. The deals represent about 20pc of EQT's production and allow EQT to take advantage of contracted capacity it holds on Mountain Valley Pipeline, which ferries gas from West Virginia to Virginia. EQT, the second-largest US gas producer by volume, has been the owner of Mountain Valley Pipeline since acquiring its previous owner Equitrans Midstream in July 2024. The gas supply deals are "two of the largest long-term physical supply deals ever executed in the North American natural gas market," EQT chief executive Toby Rice said in October 2023. The deals also underpin EQT's broader strategy of trying to sell more gas directly to large end users, including utilities, LNG export terminals and data centers, instead of selling into the volatile US spot gas market with the use of financial hedges. The deals also give EQT more exposure to pricing hubs in the southeastern US, where gas trades at a premium to gas sold within the Appalachian production region, where EQT operates. For Duke and Southern, the long-term agreements guarantee available gas supply as the utilities convert coal-fired power generation facilities to gas-fired generators while scrambling to meet surging power demand from planned data centers running artificial intelligence software. Those drivers of gas demand are also behind US pipeline companies Williams, Kinder Morgan and Boardwalk Pipeline Partners trying to build out more gas transportation capacity into the southeast, FactSet manager of natural gas research Connor McLean told Argus . Duke Energy plans to add 5GW of new gas-fired power generation through 2029 across its territory, the company said earlier this month. Duke Energy Carolinas and Southern Company hold most of the contracted capacity on Williams' planned 1.6 Bcf/d Southeast Supply Enhancement expansion of its Transcontinental (Transco) pipeline, which is expected to enter service in the fourth quarter of 2027, US Federal Energy Regulatory Commission filings show. That expansion project will make available new gas transportation capacity from the terminus of the Mountain Valley Pipeline in Virginia to end markets in Virginia, North Carolina, South Carolina, Georgia and Alabama. Duke Energy Carolinas, whose service territory includes North Carolina and South Carolina, holds 1 Bcf/d of contracted capacity on Southeast Supply Enhancement. Southern Company, whose service territory includes Georgia and Alabama, holds 400mn cf/d. By selling into those regions, EQT will be taking 1.2 Bcf/d of gas it was previously selling into the comparatively low-priced Tetco M-2 market and selling it instead into the higher priced Transco zone 4 and 5 South markets. The spot price for gas in the Transco zone 5 South region — which covers gas downstream from compressor station 165 near the terminus of Mountain Valley Pipeline in Virginia to the Georgia-South Carolina border — in 2024 averaged $2.69/mmBtu, and the Transco zone 4 index — spanning Georgia, Alabama and Mississippi — averaged $2.41/mmBtu. The Tetco M-2 receipts index over the period averaged $1.67/mmBtu. The supply deals with Duke and Southern are "the main driver" behind EQT's anticipated corporate gas price differential — or the average price at which it sells its gas relative to the US benchmark price — tightening to around 30¢/mmBtu in 2028 from an anticipated 60¢/mmBtu this year, EQT's Rice said in April. EQT is also in talks with a dozen proposed power projects in the Appalachian production region, he said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Trump brings momentum and uncertainty to US LNG

25/06/11

Trump brings momentum and uncertainty to US LNG

The current administration has been quick to roll out export licences, but the steel tariffs might throw a wrench in its plans, writes Tray Swanson London, 11 June (Argus) — US president Donald Trump's administration has swiftly shored up the country's LNG industry, most prominently by doling out export licences to proposed terminals. But while cutting regulatory hurdles signals policy stability and helps projects on the cusp of final investment decisions (FIDs) gain momentum in commercial negotiations, Trump's unwavering commitment to steel tariffs adds a layer of uncertainty for developers looking to spend billions on new projects. Political backing from the new administration and regulatory streamlining helped bring momentum to commercial talks. Since January, US LNG producers have signed or finalised offtake agreements totalling 10.7mn t/yr, including non-binding deals.Five LNG projects received a non-free trade agreement (FTA) permit or permit extension since January, which could make their projects more appealing in commercial talks with banks and potential offtakers. Four of them expect to reach FIDs this year. In February, Trump's Department of Energy (DOE) swiftly ended the Biden administration's year-long pause on issuing licences to export to non-FTA countries. Although the first two new licences were conditional, the DOE issued a final order for Sempra's 13.5mn t/yr Port Arthur phase 2 project on 29 May, shortly after the DOE concluded its 2024 LNG export study that was commissioned by the Biden administration to assess the impact of increased LNG exports on "the public interest". Trump's DOE found that higher exports indeed are in the public interest and hailed "a return to regular order on LNG exports". Alongside Port Arthur, Kimmeridge's 9.5mn t/yr Commonwealth LNG, Delfin's 13.2mn t/yr floating LNG terminal and Venture Global's 28mn t/yr CP2 plant have also received export approvals or extensions and are anticipated to reach FID later this year. Several other legislative measures being discussed in the Republican-dominated Congress seek to eliminate regulatory delays to LNG projects. The so-called "big, beautiful bill" includes an add-on that would automatically grant non-FTA export licences to developers that pay a $1mn fee, considering the payment to be in the public interest. One bill proposed in the Senate seeks to prevent federal courts from vacating permits that are already issued to LNG facilities, a measure that would safeguard projects from the judicial setbacks that NextDecade's Rio Grande LNG and Glenfarne's Texas LNG faced last year. And the House Energy Subcommittee on Energy will soon discuss the 1948 bill, which would eliminate altogether the requirement for DOE authorisation to export LNG, placing sole authority over LNG approvals with the Federal Energy Regulatory Commission. Steely determination But not all of Trump's policies have found a receptive audience in the LNG sector. His insistence on levying tariffs on steel and aluminium, key building materials for LNG projects, might force companies to adjust their spending plans. Unlike the reciprocal tariffs placed, revoked and still threatened on most countries, Trump has not dithered on the metals tariffs since enacting them in March. Instead, he doubled steel and aluminum duties to 50pc on 4 June — a move that, barring an exemption for industry, threatens to inflate project costs. The US Trade Representative has partly back-tracked on its proposal to require 1pc of US LNG exports be loaded on US-flagged, built and operated ships from 2028 — by shifting the duty to comply from plant operators, which under the original plan faced the threat of having their export licences revoked, to shippers. This came after the industry had criticised the measure for being hard to reconcile with the prevailing fob nature of US LNG contracts. Yet it remains difficult to envisage how even the amended proposal could work in practice. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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