Dive Brief: Maryland public electric utilities must disclose how they vote at PJM Interconnection stakeholder meetings under a law signed May 13 by Democratic Gov. Wes Moore. On or before February 1 each year, electric companies covered by the bill, or their local affiliates, must file a comprehensive report with the Maryland Public Service Commission that include both public and nonpublic votes on matters before PJM. The first filing deadline comes next year. Similar bills are under consideration in Delaware, Pennsylvania and Illinois, all of which are partially or wholly within PJM territory. PJM is responsible for North America’s largest transmission grid. Dive Insight: Maryland HB 121 passed both houses of the state legislature with overwhelming bipartisan support.  A similar transparency requirement appeared last year in broader utility legislation that would have required all Maryland utilities to seek PJM membership and refrain from ratebasing lobbying expenses.  The 2024 bill did not make it to Moore’s desk, but the prohibition on lobbying-expense ratebasing appeared in a comprehensive package this year that also requires separate rate structures for large-load customers, imposes new restrictions on gas infrastructure investments and authorizes solicitations for nearly 5 GW of dispatchable generation and energy storage resources. The 2025 bill now awaits the governor’s signature. HB 121 is a “common-sense bill” that prevents utilities from operating “in the dark” while “Maryland families struggle with soaring electric bills,” sponsor Lorig Charkoudian, a Democratic state lawmaker who represents parts of Maryland’s Washington, D.C. suburbs, said in a May 14 op-ed in the Baltimore Sun. “Until now, there was no requirement that utilities tell the public — or even state regulators — how they’re voting on transmission policies or market rules that can add hundreds of millions of dollars to our monthly bills,” Charkoudian said. A PJM representative indicated the new

South Bow Corp. has reported rising figures for the first quarter of 2025, including a record throughput. The company said in its quarterly report that its net income was $88 million, up from $55 million for the previous quarter, but well below the $112 million reported for the corresponding quarter a year prior. The company recorded normalized earnings before interest, taxes, depreciation and amortization (EBITDA) of $266 million. A decline in demand for uncommitted capacity on South Bow’s pipeline systems led to an 8 percent reduction in normalized EBITDA compared to the fourth quarter of 2024. South Bow said its throughput in the first quarter reached 613,000 barrels per day (bbl/d) on the Keystone pipeline, with a System Operating Factor (SOF) of 98 percent, and approximately 726,000 bbl/d on the U.S. Gulf Coast segment of the Keystone pipeline system. In April, the company activated emergency response protocols due to an oil release at MP-171 of the Keystone pipeline near Fort Ransom, North Dakota. The company was able to restart the pipeline within days. South Bow’s Q1 revenue was $498 million, $10 million above that of the fourth quarter of 2024. However, the figure was below the $544 million reported for the corresponding quarter a year prior. In the Western Canadian Sedimentary Basin, pipeline capacity for crude oil remains greater than the supply, South Bow said. Looking ahead, the uncommitted capacity demand on South Bow’s Keystone Pipeline is anticipated to stay low in the short term. Moreover, swiftly evolving global trade policies and tariffs have created economic and geopolitical instability, resulting in considerable fluctuations in commodity prices and pricing differentials, the company said. To contact the author, email [email protected] WHAT DO YOU THINK? Generated by readers, the comments included herein do not reflect the views and opinions of Rigzone. All comments

North America added five rigs week on week, according to Baker Hughes’ latest North America rotary rig count, which was released on May 16. Although the U.S. dropped a total of two rigs week on week, Canada added a total of seven rigs during the same period, taking the total North America rig count up to 697, comprising 576 rigs from the U.S. and 121 from Canada, the count outlined. Of the total U.S. rig count of 576, 563 rigs are categorized as land rigs, 11 are categorized as offshore rigs, and two are categorized as inland water rigs. The total U.S. rig count is made up of 473 oil rigs, 100 gas rigs, and three miscellaneous rigs, according to Baker Hughes’ count, which revealed that the U.S. total comprises 520 horizontal rigs, 41 directional rigs, and 15 vertical rigs. Week on week, the U.S. land and inland water rig counts each dropped by one, and the country’s offshore rig count remained unchanged, the count highlighted. The U.S. oil and gas rig counts each decreased by one week on week, and its miscellaneous rig count remained unchanged, the count showed. Baker Hughes revealed that the U.S. horizontal rig count dropped by two week on week, while its directional and vertical rig counts remained unchanged during the period. A major state variances subcategory included in the rig count showed that, week on week, New Mexico and Texas each dropped two rigs, and Wyoming and Ohio each added one rig. A major basin variances subcategory included in Baker Hughes’ rig count showed that, week on week, the Permian basin dropped three rigs and the Utica basin added one rig. Canada’s total rig count of 121 is made up of 74 oil rigs and 47 gas rigs, Baker Hughes pointed out. The country’s

The UK and the European Union (EU) are set to forge closer ties on energy trading and emerging technologies such as carbon capture and storage (CCS) following a landmark summit in London. UK Prime Minister Sir Keir Starmer hosted EU leaders as the two sides reached a post-Brexit deal which also covered fishing rights and defence. According to a joint UK-EU statement, policymakers will explore UK participation in the EU’s internal electricity market, including participating in EU trading platforms. The statement also outlined continued regulatory cooperation on emerging energy transition sectors such as hydrogen, CCS and biomethane. The deal could have implications for the future of interconnector projects between the UK and EU countries, as well as offshore carbon storage projects in the North Sea. UK and EU cooperation on carbon capture and storage Many of the UK’s CCS developments, including the track-2 Acorn and Viking projects, are aiming to eventually import captured CO2 from mainland European nations such as Germany. © Supplied by Viking CCSA map showing major industrial emitters in the UK in relation to the proposed Viking CCS project from Harbour Energy. However, since the UK left the EU in 2016, the country has so far failed to secure any bilateral agreements with EU nations on cross-border CO2 transport and storage. Meanwhile, North Sea neighbour Norway has secured CO2 deals with EU members Denmark, Sweden, Belgium and the Netherlands, despite not being part of the EU. As a result, Norway’s Northern Lights CCS project is set to begin receiving international CO2 shipments later this year. © Supplied by Northern LightsThe Northern Lights carbon capture and storage project in Norway. Similarly, Denmark’s Greensand CCS project has already signed deals with a Swedish firm covering imported CO2 volumes. If the UK and the EU can align their regulatory schemes

Many UK oil and gas companies are underestimating the financial risks posed by the energy transition and are potentially exposing investors to significant losses, according to a study. Led by academics from the UK and France, the study explored how well transition risks were being accounted for by offshore firms. The study found the net zero shift was likely to reduce access to capital for fossil fuel companies, push up borrowing costs, and trigger large-scale write-downs – leading to some assets being stranded. Loughborough University lecturer Dr Freeman Owusu said these pressures “could have put the future viability of some companies in question”. “Our findings show that the transition to net zero presents significant risks for oil and gas companies in the UK,” Dr Owusu said. “These risks include rising operational costs, reduced access to finance, and increased financial pressure. “Together, these risks threaten the going concern of some oil and gas companies, lower market value, and have knock-on effects on the wider energy supply chain and government revenues.” Smaller firms ‘most exposed’ to net zero risks According to the study, smaller firms with higher emissions and fewer alternative business streams were seen as “most exposed” to these risks. The research identified issues surrounding the financial risks tied to the energy transition, as well as the need for clearer, more tailored company disclosures. The study found existing reporting frameworks do not fully capture the unique financial and accounting risks facing oil and gas firms during the energy transition. © Supplied by ShutterstockAn oil rig in the North Sea. Participants in the study called for greater transparency around environmental, social and governance (ESG) performance, alongside remaining reserves, plans for asset write-downs and evolving business models. Without these changes, oil and gas firms risked losing stakeholder trust and weakening their long-term prospects,

Venture Global Inc. exported 233.6 trillion British thermal units (TBtu) of liquefied natural gas (LNG) in the first quarter (Q1), increasing 62 percent from the same three-month period last year and setting a new quarterly record for the company. Meanwhile LNG volumes sold totaled 228.3 TBtu, also up 62 percent from Q1 2024. Revenue grew 105 percent year-on-year to $2.89 billion. However, net profit fell 39 percent year-over-year to $396 million. “This decrease was largely driven by non-cash factors such as unfavorable changes in the fair value of our interest rate swaps”, the Arlington, Virginia-based LNG developer said in an online statement. Income from operations increased 75 percent year-on-year to $1.08 billion primarily due to higher sales volumes and prices. Consolidated adjusted earnings before interest, taxes, depreciation and amortization grew 94 percent year-on-year to $1.35 billion. The positive impact from higher sales volumes and prices were partially offset by an increase in operating costs “in support of the ramp-up of LNG production at the Plaquemines Project and operating our LNG tankers, as well as remediation and rectification costs associated with the preparation of the Calcasieu Project for COD”, Venture Global said. Plaquemines LNG shipped its first cargo, from phase 1, last December. Phase 2, which the company approved 2023, is expected to start operation this year. Phases 1 and 2 have a total permitted capacity of 27.2 million metric tons per annum, though phase 2 has yet to obtain a permit to export to countries with no free trade agreement (FTA) with the United States. The quarterly report said, “Eighteen of the Phase 1 liquefaction trains at the Plaquemines Project demonstrated production levels of approximately 140 percent of nameplate capacity”. Venture Global confirmed that in April, subsequent to the quarter, Calcasieu Pass LNG started “commercial operations”. The Cameron Parish facility