German gas TSOs plan Polish, Russian capacity upgrades
Several gas transmission system operators (TSOs) plan to convert German interruptible entry capacity into firm capacity at the German-Polish border and on entry from Russian state-controlled Gazprom's Nord Stream and planned Nord Stream 2 pipelines.
German operators Gascade and Ontras Gastransport, as well as Poland's Gaz System, plan to build additional infrastructure that would boost firm entry capacity to Germany from Poland later this decade.
Gascade plans to turn 407 GWh/d of dynamically allocable capacity (DZK) into freely allocable capacity (FZK) in addition to 261 GWh/d of existing FZK at Mallnow — where Russian gas arrives through the Yamal Europe pipeline. Entry FZK is due to fall to 261 GWh/d from 932 GWh/d following the merger of Germany's two gas markets, NCG and Gaspool, planned for 1 October 2021.
The merger is expected to cut Germany's firm entry capacity by 78pc because of internal infrastructure congestion. Regulator Bnetza has finalised plans to prevent offered capacity from falling. It will introduce a capacity overbooking and buy-back system, as well as additional market-based measures, rather than developing additional infrastructure. But the regime will only be in force until the end of the 2023-24 gas year.
From the 2024-25 gas year onwards, the amount of firm FZK considered to have been sufficient up to that point will be offered to Trading Hub Europe, Bnetza has said. Market behaviour following the merger will help identify this required capacity, and it will be included in Germany's network development plan for 2024-34.
Gaz System would not need to complete any additional physical upgrade to accompany the Gascade works, as existing technical exit capacity from Poland of 932 GWh/d would already be sufficient to meet the requested demand. But the Polish operator is participating in the process in order to market the incremental capacity as a bundled product, the operators said.
The operators will offer 534 GWh/d bundled together for the gas years from 2027-28 to 2041-42 at the auction for annual capacity in July, with 134 GWh/d set aside for future shorter-term auctions. Gascade plans to proceed with the required infrastructure works if there is sufficient uptake at the auction.
Ontras and Gaz System also plan to expand Polish exit and German entry capacity at the neighbouring GCP Gaz-System/Ontras virtual interconnection point to 48.7 GWh/d from just 87 MWh/d following the merger. The operators will offer just under 39 GWh/d for the 2026-27 to 2040-41 gas years, with remaining capacity also set aside for shorter-term auctions (see table).
Firming up Russian entry capacity
German operators plan to upgrade booked DZK to FZK at both Greifswald — where Gazprom's 55bn m³/yr Nord Stream 1 pipeline connects to the German network — and Lubmin 2 — where the firm's 55bn m³/yr Nord Stream 2 pipeline is planned to connect to the German network.
There is a "permanent need" for a capacity upgrade to FZK from DZK on German entry, the operators said. Gascade, GUD, Ontras and Fluxys Deutschland have received a request to convert around 155 GWh/d of already booked DZK to FZK. Gascade would convert 78.5 GWh/d of DZK to FZK, while the other three operators would convert 25.6 GWh/d each.
Gascade plans to offer 72.4 GWh/d at the July auction for the 2027-28 to 2035-36 gas years, while the other three operators are to offer 25.6 GWh/d each. Offered capacity would fall in the 2036-37 to 2041-42 gas years.
And Nel Gastransport — which operates the Nel pipeline, one of Nord Stream 1's onshore continuations — plans to convert 209 GWh/d of previously booked DZK to FZK. The operator will offer all 209 GWh/d at the July auction for 2027-28 to 2031-32, falling to 194 GWh/d for 2032-33 and 2033-34 and to 167 GWh/d for 2034-35 to 2041-42.
The operators plan to use in their economic test the reference FZK price published in regulator Bnetza's draft for the merged market in 2023 of €3.78/kWh/h/yr, or €0.432/MWh.
Market participants can submit comments on the proposals to system operators association FNB until 10 September, including a proposal for new capacity at the Swiss border. The consultation for new German exit capacity to Switzerland had previously been scheduled to end on 20 August.
Plans for new German exit FZK to the Dutch TTF market tied to a separate request for entry FZK at Greifswald and Lubmin 2 will be published on FNB's website on 31 August. The association will accept comments on this proposal until 30 September.
The proposed capacity changes are based on non-binding demand indications received in the first stage of the incremental capacity procedure, as laid out by the EU's network code on the capacity allocation mechanism (NC CAM).
Requested demand at a number of other German border points was insufficient to proceed with the process, including capacity connecting Germany with the French, Austria VTP, Belgian, Norwegian, Czech and Austrian Voralberg networks.
European regulatory body Acer has questioned the value of the biannual procedure, noting that the scheme has not yet led to decisions to expand European grid capacity since its introduction in 2017.
Planned German entry capacity works | ||||||
Exit country | Point | Operators | Post-merger FZK (GWh/d) | Planned expanded FZK (GWh/d) | Highest offered capacity in period (GWh/d) | Period offered (gas years) |
Denmark | Ellund | GUD, OGE | 0.0 | 60.0 | 48.0 | 2027-28 to 2041-42 |
Poland | Mallnow | Gascade, Gaz System | 261.0 | 667.9 | 534.3 | 2027-28 to 2041-42 |
Poland | GCP Ontras VIP | Ontras, Gaz System | 0.1 | 48.7 | 39.0 | 2026-27 to 2040-41 |
Russia | Lubmin 2 | Gascade | 30.2 | 78.5 | 72.4 | 2027-28 to 2041-42 |
Russia | Lubmin 2 | GUD | 0.0 | 25.6 | 25.6 | 2027-28 to 2041-42 |
Russia | Lubmin 2 | Fluxys Deutschland | 0.0 | 25.6 | 25.6 | 2027-28 to 2041-42 |
Russia | Lubmin 2 | Ontras | 0.0 | 25.6 | 25.6 | 2027-28 to 2041-42 |
Russia | Greifswald | Nel | 0.0 | 208.6 | 208.6 | 2027-28 to 2041-42 |
— FNB |
Related news posts
New Zealand’s Genesis Energy to resume coal imports
New Zealand’s Genesis Energy to resume coal imports
Sydney, 8 May (Argus) — New Zealand's upstream firm and utility Genesis Energy plans to resume thermal coal imports later this year to feed its dual gas- and coal-fired Huntly power plant. The resumption was because of lower domestic gas production and rapidly declining coal stockpiles, and will mark the firm's first coal imports since 2022. Coal inventories at the 953MW Huntly plant, — New Zealand's largest power station by capacity and the country's only coal-fired facility — recently slipped below 500,000t, down from 624,000t at the end of March, and will fall below 350,000t by the end of the winter. This will trigger a need to purchase more coal to maintain a target operational stockpile of around 350,000t ahead of winters in 2025 and 2026, the company said on 8 May. Imports are currently the most efficient option for the quantity the company will need, with a delivery time of around three months, chief executive Malcolm Johns said. Genesis typically imports from Indonesia, the company told Argus . Gas production in New Zealand has dropped at a faster rate than expected, with major field production in April down by 33pc on the year, Genesis said. Lower gas availability typically leads to more coal burn, because the Huntly plant runs on gas and coal. This is in addition to an extended period of low hydropower inflows in recent months, which required higher thermal generation to ensure supply security. A prolonged outage at Huntly's unit 5 gas turbine between June 2023 and January 2024 also led to an even greater need for coal-fired generation, Genesis said. Biomass transition The company — which is 51pc owned by the state — is the second-largest power retailer in New Zealand, behind domestic utility Mercury, according to data from the Electricity Authority. It has a NZ$1.1bn ($659mn) programme for renewable power generation and grid-scale battery storage , which includes a potential replacement of coal with biomass at Huntly. But the transition to biomass "will take some years," Johns said. Genesis has successfully completed a biomass burn trial at Huntly last year and has collaboration agreements with potential New Zealand pellet suppliers, but there is currently no local source for the type of pellets needed for the plant. Genesis is hoping to move to formal agreements "as soon as counterparties are able". The company will not consider importing pellets, it told Argus . "We will only use biomass if we can secure a local New Zealand supply chain that is sustainable and cost-effective," it said. Domestic gas production New Zealand's three-party coalition government said separately on 8 May that the "material decline" in local gas production threatens energy security, blaming the previous Labour party-led government for "policy decisions which have disincentivised investment in gas production." The decisions — which were part of the former government's pledge to achieve a carbon-neutral economy by 2050 — led to a reduction in exploration for new gas resources since 2021, while suppressed maintenance drilling reduced production from existing gas fields, according to a joint release from energy minister Simeon Brown and resources minister Shane Jones. "Due to this significant reduction in gas production, the government has also been advised that some large gas consumers are expressing concern about their ability to secure gas contracts," the government said. Major industrial users such as Canada-based methanol producer Methanex have been forced to reduce production as a result, it noted. "We are working with the sector to increase production, and I will be introducing changes to the Crown Minerals Act to parliament this year that will revitalise the sector and increase production," Jones added. By Juan Weik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
EPA sets new oil and gas methane reporting rules
EPA sets new oil and gas methane reporting rules
Washington, 7 May (Argus) — Federal regulators have updated emissions reporting requirements for oil and gas facilities as they prepare to implement a methane "waste" fee for the industry. The US Environmental Protection Agency (EPA) on Monday finalized new rules it says will improve the accuracy of data from the oil and gas sector under the federal greenhouse gas emissions reporting program. Oil and gas facility owners and operators will be required to estimate emissions from additional types of equipment under the rule, and they can draw on newer technologies, like remote sensing, to help estimate emissions. "EPA is applying the latest tools, cutting edge technology, and expertise to track and measure methane emissions from the oil and gas industry," agency administrator Michael Regan said. "Together, a combination of strong standards, good monitoring and reporting, and historic investments to cut methane pollution will ensure the US leads in the global transition to a clean energy economy." Data to support new fee The revisions to the "Subpart W" reporting requirements will be used to determine the amount of methane that will be subject to a "waste emissions charge" created by the Inflation Reduction Act. Under the law, the charge will be calculated based on the annual data that about 8,000 oil and gas sources are now required to report. The charge will begin at $900/t for 2024 methane emissions above a minimum threshold using current measurement data. It will then rise to $1,200/t in 2025 and $1,500/t in subsequent years. Industry officials had raised "serious concerns" about several aspects of the original proposal , warning it could lead to inflated emissions data. "We are reviewing the final rule and will work with Congress and the administration as we continue to reduce GHG emissions while producing the energy the world needs," American Petroleum Institute vice president of corporate policy Aaron Padilla said. The industry group previously said it will ask Congress to repeal the fee, which is only likely to occur if Republicans win control of the White House. Data collected since 2010 Oil and gas facilities have reported emissions under Subpart W since 2010. To simplify reporting, operators often count the equipment they have deployed, and use industry-wide averages to estimate emissions, in addition to other direct and indirect measurements. The industry has argued the Subpart W data is not accurate enough to collect the methane charge, which is expected to cost operators more than $6bn over the next decade. Environmental groups have had their own criticisms of the data, which they say omits vast amounts of emissions such as those from "super-emitter" events and poorly maintained flares. The final rule seeks to respond to some of those concerns by relying on updated emission factors, incorporating additional empirical data on emission rates, collecting data at a more granular level and relying on remote sensing technologies to detect large emission events. EPA also revised Subpart W to include more types of sources, including produced water tanks, nitrogen removal units and crankcase venting. The final rule also sets a threshold of 100 kg/hr of methane for requiring the reporting of emissions from "other large release events." The new data rules will take effect on 1 January 2025 and will first apply to reports submitted in early 2026 for next year's emissions. EPA is allowing the use of the new methodologies for calculating 2024 emissions, but operators can still use the existing rules. By Michael Ball Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Australia’s Gorgon LNG train to be out for five weeks
Australia’s Gorgon LNG train to be out for five weeks
Singapore, 7 May (Argus) — One of three trains at Australia's 15.6mn t/yr Gorgon export terminal will be off line for five weeks, a source familiar with Gorgon operations told Argus on 7 May. The train has been off line since 30 April because of a mechanical fault in a turbine. The five-week shutdown expectation is slightly longer than the initially expected shutdown period of about 2-3 weeks, traders said. Each week of downtime on one train at Gorgon reduces the terminal's available liquefaction capacity by about 100,000t. The five-week shutdown is likely to reduce the terminal's production by about 5-8 cargoes, traders said. One standard-sized cargo is roughly equivalent to 60,000-70,000t of LNG. But overarching sentiment from market participants is that the impact on both prices and supply will be limited, as only one train is affected and there are ample cargoes for June and July. There will be a temporary spike in prices as affected buyers — if any — will have to secure prompt cargoes to replace lost LNG from Gorgon, keeping prices supported well above $10/mn Btu, traders said. The shutdown will have a greater impact on prices if repair works drag on for longer and affect summer deliveries, they added. The ANEA price, the Argus assessment for spot LNG deliveries to northeast Asia, for the first and second half June were assessed at $10.57/mn Btu and $10.58/mn Btu on 7 May, higher by 40¢/mn Btu from the previous day. First- and second-half July ANEA prices were assessed at $10.64/mn Btu and $10.66/mn Btu, up by 36¢/mn Btu/mn Btu from a day earlier. Chevron has rescheduled deliveries of some LNG cargoes for their Asian offtakers, according to some traders. Further details are unclear. Shell might have bought around 3-4 cargoes because of the shutdown at Gorgon, according to traders. It is not clear whether the cargoes are for June or July delivery. Some traders have offered both June- and July-delivery cargoes to Chevron but the firm has responded by saying that the shortfall can be managed by optimising its own portfolio, traders said. The Gorgon LNG joint venture is operated by Chevron with a 47pc stake, while ExxonMobil and Shell hold 25pc each. By Simone Tam Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
US majors widen output gap over European rivals
US majors widen output gap over European rivals
New York, 6 May (Argus) — ExxonMobil and Chevron are seeing investments in Guyana and the Permian shale basin pay off, widening a gap with their transatlantic counterparts that could get even bigger with the completion of recent mega-deals. ExxonMobil is championing a speedy ramp-up of a massive offshore oil discovery in Guyana, where production has surged to more than 600,000 b/d of oil equivalent (boe/d) in the space of just a few years. And Chevron recorded a 35pc jump in first-quarter US output from a year earlier, buoyed by better-than-expected performance from the Permian basin, as well as the $7.6bn acquisition of US independent PDC Energy that bolstered its footprint in Colorado's DJ basin. And after years of delays and cost overruns, its highly vaunted expansion project in Kazakhstan is finally close to seeing the light of day. Even though European rivals including Shell and BP are backtracking on previous plans to scale back their reliance on oil and gas production, the US majors are poised to extend their lead after dominating a recent round of industry consolidation. ExxonMobil will become the top producer in the Permian after wrapping up its $59bn takeover of shale giant Pioneer Natural Resources. Anti-trust regulators at the US Federal Trade Commission cleared the deal after barring Pioneer's former chief executive, Scott Sheffield, from gaining a seat on the board, following allegations that he sought to collude with Opec members. And Chevron is still optimistic that its pending $53bn purchase of independent producer Hess will close by the end of the year, even though ExxonMobil has thrown a spanner in the works by claiming its right of first refusal over Hess' 30pc stake in Guyana's prolific Stabroek block, where it is the operator. Chevron's attempt to muscle in on Guyana's oil riches would answer lingering concerns over its long-term growth profile. The dispute has now been referred to international arbitration in Paris and the company hopes the transaction can be completed this year. A failure of the deal to close would not "materially" hit Chevron's near-term valuation, according to bank HSBC. "However, the strategic gap between Chevron and ExxonMobil could widen over time if the Hess deal does not happen," the bank says. Advantage Exxon Excluding the Pioneer transaction, ExxonMobil forecasts its output will grow to 4.2mn boe/d by 2027 from about 3.8mn boe/d this year. Chief executive Darren Woods has doubled down on so-called "advantaged" projects including Guyana and the Permian, which offer the most profitable and low-cost barrels that will be key drivers of revenue growth. The company's share of overall production from such assets has increased to 44pc from 28pc in recent years. Woods sees the growing cash flow from those projects as vindication of his strategy to direct "counter-cyclical" investments before and during the pandemic, which were unpopular with some investors at the time. Spending discipline remains a key priority even as new projects start up. ExxonMobil has achieved $10.1bn of cost savings from 2019 levels, and is on course to hit $15bn by 2027. And Woods says there is scope for even more savings to be found. Meanwhile, Chevron says its output from the Permian is trending better than previous guidance for a 2-4pc decline in the first half of 2024, with more wells due to come on line later this year. The company is also preparing to start up its Anchor offshore platform in the Gulf of Mexico in the middle of the year, with more projects in the region to follow. "The outlook in the US is especially strong," chief executive Mike Wirth says. Chevron is guiding for 4-7pc overall output growth this year, after pumping a record 3.1mn boe/d last year. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Business intelligence reports
Get concise, trustworthy and unbiased analysis of the latest trends and developments in oil and energy markets. These reports are specially created for decision makers who don’t have time to track markets day-by-day, minute-by-minute.
Learn more