Peru deploys army to safeguard strategic gas line

Spanish Market: LPG, Natural gas
19/12/19

Peru's government has deployed army troops to safeguard a jungle stretch of the Camisea natural gas and gas liquids pipelines from potential attacks under a 60-day emergency declaration.

The lines are critical to Peru's LNG and LPG export businesses, which are operating normally.

The emergency measure covers an 80km stretch of the parallel lines running from the Camisea fractionating plant to Echarate province in the southeastern jungle.

The emergency decree, which puts the army in charge of security, extends for five kilometers on either side of the twin gas and gas liquids lines.

The decree states that the pipeline system is susceptible to terrorist attacks, but does not elaborate.

TGP, the pipeline operator controlled by Argentina's Tecgas, was unavailable for comment.

The twin pipelines pass through remote jungle areas that are home to remnants of a Maoist insurgency, Shining Path, which terrorized Peru in the 1980s and early 1990s. The group routinely targeted infrastructure. Its war on the state cost Peru more than 70,000 lives and $25bn in losses, according to a truth commission that reported on the violence in the previous decade.

Shining Path remnants targeted the gas line when it was under construction in mid-2003, staging a mass kidnapping of workers. Several more violent incidents near the line took place in subsequent years.

The 730km gas pipeline is critical to Peru's economy, providing gas for approximately 40pc of power generation in November, according to the energy ministry. It also supplies gas to Peru LNG, the only liquefaction plant along South America's Pacific coast. The ministry estimated that Peru would lose close to $500mn per day if the pipeline is knocked off line.

Peru produced 1.4bn cf/d of gas in November, with 1.1bn cf/d from Camisea's blocks 56 and 88, operated by Argentina's Pluspetrol, and 205mn cf/d from adjacent block 57, operated by Spain's Repsol.

Peru LNG, operated by US-based Hunt Oil, has dispatched 549 LNG cargoes since 2010, including three in December, two to China and one to South Korea.

By Lucien Chauvin

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27/12/24

Viewpoint: Mild weather may pressure gas prices in 2025

Houston, 27 December (Argus) — The US natural gas market has worked to lower inventories and bring prices up this year, but a warm 2024-25 winter may once again keep storage levels elevated in the new year. US natural gas inventories at the end of the 2023-24 winter season were well above average due to minimal heating demand caused by mild winter weather and robust US production. Storage levels ended the season on 29 March at 2.259 Tcf (64bn m³) — 39pc higher than the five-year average and 23pc higher than a year earlier. The higher inventories pushed down gas prices by minimizing concerns about supply shortfalls and disincentivized production this year, as large natural gas producers such as Chesapeake Energy and EQT reduced output on low prices and minimal expected demand. These interventions helped reduce the supply glut. Total US gas inventories for the week ending 1 November were 3.932 Tcf, entering the 2024-25 winter season only 6pc higher than the five-year average and 4pc higher than a year earlier. In addition, the US Energy Information Administration (EIA) predicted in its November Short Term Energy Outlook (STEO) that production in 2025 would be up 1pc from 2024 as lower inventories push up prices and once again incentivize production. EIA estimates that demand this winter will exceed last year's levels and keep inventories only just above average. According to December's STEO, inventories are expected to be 1.92 Tcf at the end of March 2025, only 2pc higher than the five-year average . However, the mild weather that has covered much of the country this November and December risks once again sharply cutting into heating demand, leaving inventories at the start of 2025's spring injection season high enough to again put downward pressure on gas prices. Heating demand in November was 12pc below the seasonal average, according to the National Weather Service (NWS). The mild weather caused prices at the Henry Hub, the US benchmark, to average roughly $2/mmBtu in November. However, EIA's December STEO predicted that prices at the Henry Hub would average just under $3/mmBtu for the rest of the winter heating season on expectations for cold weather. That cold weather has yet to fully materialize. While demand in the first week of December was 20pc higher than average on cold snap, temperatures since then have been above seasonal norms, with heating demand in the week ending 20 December landing at 22pc below average and demand in the week ending 28 December expected to be 26pc below average. If below-average demand continues into 2025, it is unlikely that inventories will drop as much as forecast. Prices this winter would be close to $3/mmBtu if withdrawals this season are close to 2.1 Tcf , East Daley Analytics senior director Jack Weixel said in September. US inventories had that level of withdrawal in winter from 2020-22. However, if temperatures this winter are once again well above average, Weixel said inventories could end the season more than 530 Bcf above average, cutting average prices to $2.50/mmBtu and undoing price from the smaller-than-average injection season. Prices may be especially pressured by rising production in the Permian basin of west Texas and southeastern New Mexico. Since most of the gas output from the Permian comes from oil wells, low gas prices may not affect production, as drilling decisions there are influenced by oil production rather than gas production. Prices may still rally this winter if temperatures dip low enough in January and February, offsetting the mild weather of November and December. In addition, the rise of LNG exports next year may boost demand and subsequently raise prices. Several LNG projects or expansions are currently underway in the US with the Golden Pass export terminal, the Plaquemines export terminal and the stage 3 expansion at Cheniere's Corpus Christi liquefaction terminal all expected to start up in 2025. By Anna Muthalaly Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US gas market poised for more volatility

26/12/24

Viewpoint: US gas market poised for more volatility

New York, 26 December (Argus) — US natural gas markets may be subjected to more dramatic price swings in 2025 as growing LNG exports and increasingly price-sensitive producers place greater pressure on the US' stagnant gas storage capacity. Those price swings could pose challenges for consumers without ample access to gas supplies, as well as producers interested in keeping some output unhedged to capture potentially higher prices without taking on excessive financial risk. But volatility may also present opportunities for traders looking to exploit unstable price spreads, and for producers that can adapt their operations to fit a more unpredictable pricing environment. Calm before the storm High storage levels and low spot prices this year — averaging $2.11/mmBtu through November this year at the US benchmark Henry Hub — triggered by an unusually warm 2023-24 winter, may have obscured some of the structural factors pushing the US gas market into a more volatile future. But those structural factors remain and loom increasingly large for prices. The US has moved from a roughly 60 Bcf/d (1.7bn m³/d) market eight years ago to a more than 100 Bcf/d market today, "and we haven't grown our storage capacity at all", Rich Brockmeyer, head of North American gas and power at commodity trading house Gunvor, said earlier this year. As supply and demand for US gas grow, the country's roughly 4.7-Tcf storage capacity becomes ever less effective in stemming demand shocks, such as extreme winter weather events, which can more rapidly draw down inventories than in years past. Additionally, a growing share of US gas is being consumed by LNG export terminals being built and expanded on the US Gulf coast. When those facilities encounter unexpected problems and cease operations — as has happened numerous times at the 2 Bcf/d Freeport LNG terminal in Texas in recent years — volumes that were previously being liquefied and sent overseas were instead backed up into the domestic market, crushing prices. More LNG exports may mean more opportunities for such supply shocks. US LNG exports are expected to increase by 15pc to almost 14 Bcf/d in 2025 as operations begin at Venture Global's planned 27.2mn t/yr Plaquemines facility in Louisiana and Cheniere's 11.5mn t/yr Corpus Christi, Texas, stage 3 expansion, US Energy Information Administration data show. Spot price volatility will be most acutely felt in regions like New England that lack underground gas storage. "In areas like the Gulf coast, where you have a lot of storage, it won't be a problem," Alan Armstrong, chief executive of Williams, the largest US gas pipeline company, told Argus in an interview. Producers' trade-off Volatile gas markets are a mixed bag for producers, many of whom profit from volatility while also struggling to plan and budget based on uncertain revenues for unhedged volumes. Though insufficient gas storage deprives the market of stability, "from the standpoint of a marketing and trading guy that's trying to manage my gas supply to customers and my trading book, I love volatility",said Dennis Price, vice president of marketing and trading at Expand Energy, the largest US gas producer by volume. BP chief financial officer Sinead Gorman in November 2023 specifically named Freeport LNG's eight-month-long shutdown in 2022-23 from a fire as a driver of volatility in the global gas market. The supermajor was able to exploit the "incredibly fragile" gas market, she said, which was a key factor driving the success of its integrated gas business. "Those opportunities are what we typically seek and enjoy," Gorman said. Increasingly, producers have also been adapting to a more volatile market by switching production on and off in response to prices, but often without revealing the price at which a supply response will occur. Expand Energy, for instance, told investors in October that it was amassing drilled but uncompleted wells and wells that had yet to be brought on line, which it could activate relatively quickly when prices rise. It declined to name the price at which that would occur. Market participants, attempting to price in this phenomenon by anticipating producers' next moves may respond more dramatically to supply signals than in the past, when production was steadier. Producers' increased responsiveness to prices could help to balance the market somewhat, though more aggressive intervention into operations could take a toll on well performance and pipelines, FactSet senior energy analyst Connor McLean said. Producers are "treating the reservoir itself like a storage facility", Price said. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: California dairy fight spills into 2025

24/12/24

Viewpoint: California dairy fight spills into 2025

Houston, 24 December (Argus) — California must begin crafting dairy methane limits next year as pressure grows for regulators to change course. The California Air Resources Board (CARB) has committed to begin crafting regulations that could mandate the reduction of dairy methane as it locked in incentives for harvesting gas to fuel vehicles in the state. The combination has frustrated environmental groups and other opponents of a methane capture strategy they accuse of collateral damage. Now, tough new targets pitched to help balance the program's incentives could become the fall-out in a new lawsuit. State regulators have repeatedly said that the Low Carbon Fuel Standard (LCFS) is ill-suited to consider mostly off-road emissions from a sector that could pack up and move to another state to escape regulation. California's LCFS requires yearly reductions of transportation fuel carbon intensity. Higher-carbon fuels that exceed the annual limits incur deficits that suppliers must offset with credits generated from the distribution to the state of approved, lower-carbon alternatives. Regulators extended participation in the program to dairy methane in 2017. Dairies may register to use manure digesters to capture methane that suppliers may process into pipeline-quality natural gas. This gas may then be attributed to compressed natural gas vehicles in California, so long as participants can show a path for approved supplies between the dairy and the customer. California only issues credits for methane cuts beyond other existing requirements. Regulators began mandating methane reductions from landfills more than a decade ago and in 2016 set similar requirements for wastewater treatment plants. But while lawmakers set a goal for in-state dairies to reduce methane emissions by 40pc from 2030 levels, regulators could not even consider rulemakings mandating such reductions until 2024. CARB made no move to directly regulate those emissions at their first opportunity, as staff grappled with amendments to the agency's LCFS and cap-and-trade programs. That has meant that dairies continue to receive credit for all of the methane they capture, generating deep, carbon-reducing scores under the LCFS and outsized credit production relative to the fuel they replace. Dairy methane harvesting generated 16pc of all new credits generated in 2023, compared with biodiesel's 6pc. Dairy methane replaced just 38pc of the diesel equivalent gallons that biodiesel did over the same period. The incentive has exasperated environmental and community groups, who see LCFS credits as encouraging larger operations with more consequences for local air and water quality. Dairies warn that costly methane capture systems could not be affordable otherwise. Adding to the expense of operating in California would cause more operations to leave the state. California dairies make up about two thirds of suppliers registered under the program. Dairy supporters successfully delayed proposed legislative requirements in 2023. CARB staff in May 2024 declined a petition seeking a faster approach to dairy regulation . Staff committed to take up a rulemaking considering the best way to address dairy methane reduction in 2025. Before that, final revisions to the LCFS approved in November included guarantees for dairy methane crediting. Projects that break ground by the end of this decade would remain eligible for up to 30 years of LCFS credit generation, compared with just 10 years for projects after 2029. Limits on the scope of book-and-claim participation for out-of-state projects would wait until well into the next decade. Staff said it was necessary to ensure continued investment in methane reduction. The inclusion immediately frustrated critics of the renewable natural gas policy, including board member Diane Tarkvarian, who sought to have the changes struck and was one of two votes ultimately against the LCFS revisions. Environmental groups have now sued , invoking violations that effectively froze the LCFS for years of court review. Regulators and lawmakers working to transition the state to cleaner air and lower-emissions vehicles will have to tread carefully in 2025. By Elliott Blackburn Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US ethane to be oversupplied for 2025

24/12/24

Viewpoint: US ethane to be oversupplied for 2025

Houston, 24 December (Argus) — US ethane production growth will likely continue to outpace exports and domestic demand into the first half of 2025, keeping US inventories of the natural gas liquid in record territory until export capacity expands late next year. Ethane, which is widely used for ethylene production at US steam crackers, has emerged as the lowest-cost petrochemical feedstock worldwide, spurring infrastructure investments in Asia, particularly China, to receive US ethane exports. Still, US ethane production from gas processing continues to outpace the country's ability to ship it into demand centers in Europe, India and China. Mont Belvieu, Texas, EPC ethane spot prices fell relative to natural gas in 2024 due to record ethane production, leaving ethane stocks oversupplied entering 2025. EPC ethane's premium to its fuel value in Nymex natural gas at the Henry Hub averaged 3.25¢/USG during 2024, 54pc lower than in 2023. It also averaged a 1.75¢/USG premium to its fuel content in the second half of 2024, 77.5pc lower than the same period last year, as spot ethane prices fell on ample supplies. Cheaper natural gas in the Permian basin spurred higher rates of ethane recovery from the natural gas stream and led to a disproportionate rise in ethane production. Spot prices for natural gas at the Waha hub in west Texas across the year averaged -$0.10/mmBtu, with prices remaining negative for eight of nine months from March-November. Prices were consistently positive in 2023, averaging $1.66/mmBtu across the year. Negative Permian gas prices allow ethane recovery from the gas stream at a much lower cost. US natural gas production in 2024 is poised to be steady to slightly down, having averaged 3.14tcf in monthly production from January to September, according to US Energy Information Administration (EIA) data. Meanwhile, ethane production is set to reach a record high for the 11th consecutive year, with monthly production averaging 2.78mn b/d over the same period, up from a 2.65mn b/d average over the whole of 2023. Waha gas prices turned positive in the second half of November and spiked to a multi-month high of $2.56/mmBtu on 2 December, pushing ethane prices to a 13-month high of 25.625¢/USG the following day as downstream buyers bid higher to fulfill contracts for the month . Ethane's rally was brief, however, with Mont Belvieu prices falling to 22.5¢/USG over the next week even as Waha climbed further. Record ethane inventories Ethane inventories hit record highs in 2024, according to EIA data, including a peak of 80.89mn bl in July, 79.5mn bl in August and 77.23mn bl in September. Mont Belvieu ethane has also been in backwardation in December, with January prices at a 2-4c discount to prompt December prices, encouraging selling interest. Sustained cold weather and additional surges in natural gas spot prices may further draw down ethane supplies as higher volumes are rejected into the gas stream, market participants suggest, but as it stands, ethane supplies are likely to remains at or near record highs for the first part of the new year. In the EIA's most recent Short Term Energy Outlook (STEO), the agency projects ethane inventories to end 2024 at 74.1mn bl , which would be a year-end record following a seasonal draw down, and 12.6pc higher than a year earlier. In that same report, including projections for the fourth quarter, domestic consumption of ethane is estimated to be 2.26mn b/d in 2024, up by about 98,000 b/d on the year, and net exports are estimated at 483,000 b/d, up by around 13,000 b/d, whereas production of ethane from natural gas processing is expected to be 113,000 b/d higher at 2.77mn b/d. Playing catch-up If projections are accurate, 2024's record end-of-year ethane supply will exceed the peak previously set in 2020 of 69.6mn bl, based on EIA data. The first VLEC loadings at Energy Transfer's 180,000 b/d Nederland, Texas, export terminal began in January of 2021, resulting in year-end inventories reaching a relative trough in 2022 at 53.55mn bl before rebounding by nearly 50pc in the last two years. Domestic ethane consumption growth has kept pace with or fallen behind growth in production since 2020. Conversely, ethane exports in 2021 jumped by 98,000 b/d to 369,000 b/d on the opening of the Nederland terminal and grew more slowly in 2022 and 2023. Exports of US ethane are limited by infrastructure at receiving terminals abroad and the specialized vessels required to ship the lighter feedstock. Overseas markets are gearing up to take ethane imports over the next few years , and US ethane inventories are likely to continue building ahead of of an expansion to domestic export infrastructure as US production grows further. Enterprise's Neches River export terminal in Beaumont, Texas, is the next scheduled US expansion and is set to complete its first phase in the third quarter of 2025 , adding 120,000 b/d of ethane export capacity. Completion of the second phase in the first half of 2026 would take this capacity to a total of 180,000 b/d. The project, if it remains on track, should curtail ethane inventory growth at the back end of 2025. Until then, abundant supply probably will continue to weigh on spot prices, and the first half of 2025 may see ethane prices fall further, both outright and relative to natural gas, especially since the EIA's outlook also forecasts gas prices to rise through the winter. By Joseph Barbour Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US LPG cargo premiums poised to fall

23/12/24

Viewpoint: US LPG cargo premiums poised to fall

Houston, 23 December (Argus) — The booming US LPG export market has fueled record spot fees this year for terminal operators that send those cargoes abroad, but those fees are poised to fall next year as additional export capacity comes online. US propane exports surged over the past two years, hitting an all-time high of 1.85mn b/d in the first quarter of this year, according to data from the US Energy Information Administration (EIA). Terminal fees for spot propane cargoes out of the US Gulf coast hit an all-time high of Mont Belvieu +32.5¢/USG (+$169.325/t) in mid-September. US propane production is expected to grow by another 80,000 b/d in 2025 to 2.22mn b/d while the outlook for domestic consumption is fairly steady, at 820,000 b/d next year — meaning even more propane will be pushed into the waterborne market. But that is dependent on US infrastructure keeping up with the pace of production. US export terminals in Houston, Nederland and Freeport, Texas, have run at or above capacity for the last two years given the thirst for cheaper US feedstock, largely from propane dehydrogenation (PDH) plant operators in China. This demand has created bottlenecks at US docks, and midstream operators like Enterprise, Energy Transfer, and Targa have rushed to ramp up spending on both pipelines and additional refrigeration to stay ahead of the wave of additional production. US gas output spurs LPG exports As upstream producers have ramped up natural gas production ahead of new LNG projects, most producers are counting on LPG demand from international outlets in Asia to offload the ethane and propane the US cannot consume. For the past four years, Asian buyers have been more than happy to oblige. US propane exports to China rose from zero in 2019, when China imposed tariffs on US imports, to an average of 1.36mn metric tonnes (t) per month in January-November 2024, according to data from analytics firm Kpler, making China the largest offtaker of US shipments. US exports to Japan averaged 480,000t per month throughout most of 2024, and exports to Korea averaged 460,000t per month in the first 11 months of 2024. China, Korea, and Japan received 52pc of US propane exports in 2024, up from 49pc in 2020, according to data from Vortexa. Strong demand in Asia has kept delivered prices in Japan high enough to sustain an open arbitrage between the US and the Argus Far East Index (AFEI). Forward-month in-well propane prices at Mont Belvieu, Texas, have remained well below delivered propane on the AFEI. In 2020, Mont Belvieu Enterprise (EPC) propane averaged a $143/t discount to delivered AFEI — a spread that has only widened as additional PDH units in Asia have come online. During the first 11 months of 2024, the Mont Belvieu to AFEI spread averaged a hefty $219/t, leaving plenty of room for wider netbacks in the form of higher terminal fees for US sellers, especially as a wave of new VLGCs entering the global market has left shipowners with less leverage to take advantage of the wider arbitrage. The resulting wider arbitrage to Asia has kept US export terminals running full for the last two years. So when a series of weather-related events and maintenance in May-September limited the number of spot cargoes operators could sell and delayed scheduled shipments, term buyers willing to resell any of their loadings could effectively name their price. This spurred the record-high premiums for spot propane cargoes in September. New projects may narrow premium An increase in US midstream firm investments in additional dock capacity and added refrigeration in the years ahead could narrow those terminal fees, however. Announced projects from Enterprise and Energy Transfer, in particular, will add a combined 550,000 b/d of LPG export capacity out of Houston and Nederland, Texas by the end of 2026. Enterprise's new Neches River terminal project near Beaumont, Texas, will add another 360,000 b/d of either ethane or propane export capacity in the same timeframe. These additions are poised to limit premiums for spot cargoes by the end of 2025. Already, it appears the spike in spot cargo premiums to Mont Belvieu has abated for the rest of 2024. Spot terminal fees for propane sank to Mont Belvieu +14¢/USG by the end of November. The lower premiums come not only as terminals resume a more normal loading schedule, but at the same time a surplus of tons into Asia ahead of winter heating demand has narrowed the arbitrage. The spread between in-well EPC propane at Mont Belvieu fell from $214.66/t to $194.45/t during November. A backwardated market for AFEI paper into the second quarter of 2025 means US prices are poised to fall more in order to keep the spread from narrowing further. By Amy Strahan Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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