David Lapp is people’s counsel at the Maryland Office of People’s Counsel, an agency that advocates for Maryland’s residential utility consumers. The current openings for a new chief executive officer and two board seats present an opportunity for a much-needed paradigm shift at the PJM Interconnection. PJM is supposed to be independent under federal law, but in practice PJM has proven much more interested in advancing policies responsive to big corporate interests than the welfare of consumers. PJM’s ongoing public relations campaign illustrates the need for leadership change. Rather than responding with objective facts and reform to address root causes, PJM is resorting to blaming states for supply and infrastructure shortages, often defending the very policies that are driving up customer costs. PJM’s messaging in Maryland is illustrative. Consider four examples. First, with no qualification or quantification, PJM says it is “undeniable” that Maryland’s electric demand for power is growing and that it has a “supply” issue. According to PJM’s own forecasts, however, Maryland’s projected growth is quite modest. Twenty years from now, in 2045, PJM projects that the peak demand of Maryland’s largest utility, Baltimore Gas and Electric, will still be less than what its peak was in 2011, 14 years ago. Other areas of Maryland also show very modest increases in peak demand. The only real “supply” issue Maryland faces is really a PJM-wide issue: the massive growth and projected demand growth of data centers — about 30,000 MW by 2030, almost all of which is outside of Maryland. Second, PJM claims it is “undeniable” that power plants are shutting down without adequate replacements. But Maryland has few if any power plants likely to retire that have not already retired or announced plans to retire. PJM’s own data shows that despite some retirements, Maryland has more generation capacity

In an EBW Analytics Group report sent to Rigzone by the EBW team today, Eli Rubin, an energy analyst at the company, offered an explanation for the August natural gas contract price drop on Monday, which the report highlighted came in at 6.7 percent. “The August contract dropped 24.0 cents yesterday to $3.325 [per million British thermal units/MMBtu] – returning nearly the entirety of last week’s gains and up just 1.1 cents vs. the Friday, July 11th close,” Rubin said in the report. “Higher weekend production prints, inconsistent LNG, and milder weather sparked the move lower,” he added. In the report, Rubin noted that “the 7.4 CDD [cooling degree day] retreat in Week 3 cooling demand over the past 24 hours added to bearish momentum, with a seasonal to cool eastern U.S. shedding 15 CDDs week over week hampering the sustainability of bullish chances”. “Production readings may also show renewed strength next week, offering further downside risks,” Rubin warned. Rubin also highlighted in the report that Henry Hub spot prices averaged $3.47 per MMBtu yesterday and added that “the next week will see the three hottest days of the summer”. “A mid-teens Bcf (billion cubic foot) injection may help breathe life into bulls,” Rubin went on to state. “Still, while volatility is probable over the next 7-10 days, the combination of overarching storage surpluses, strong production, and tropical risks may limit durable medium-term upside,” he added. In a separate EBW Analytics Group report sent to Rigzone by the EBW team on Monday, Rubin highlighted that Friday’s $3.565 per MMBtu close “was a month to date high for the August natural gas contract”. Rubin went on to outline in that report that, on Monday, the contract was “returning most of last week’s gains amid strong weekend supply readings and milder weather forecasts

Tullow Oil PLC said Monday it had signed an agreement to divest its Kenyan portfolio to Gulf Energy Ltd. for at least $120 million in cash. The assets to be sold hold about 463 million barrels of 2C resources, London-based Tullow said in a statement online. The transaction involves the sale of the shares of Tullow Kenya BV by Tullow Overseas Holdings BV to Gulf Energy’s Auron Energy E&P Ltd. The sale and purchase agreement announced Monday builds on a heads of terms agreement announced April. “Tullow retains a back-in right for a 30 percent participation in potential future development phases at no historic cost”, Tullow said. “This right can be exercised if a third-party investor participates in future development phases, whether through a sale or farm-down of the purchaser’s interest in the assets”. The parties expect to complete the transaction this year, subject to approval by the Eastern African country’s Competition Authority, approval of a development plan and the fulfillment of payments. “The consideration will be split into a $40 million payment due on completion, $40 million payable at the earlier of field development plan approval or 30 June 2026, and $40 million payable over five years from the third quarter of 2028 onwards”, Tullow said. “In addition, Tullow will be entitled to royalty payments subject to certain conditions”. Tullow added, “All past and future decommissioning liabilities and all material past and future environmental liabilities will be transferred to the purchaser”. Tullow chief executive Richard Miller said, “For a total consideration of at least $120 million, the Transaction supports our strategic priority to strengthen the balance sheet, with the first two payments totaling $80 million expected before the end of the year”. “We continue to advance plans to optimize our capital structure during 2025”, Miller added. “Coupled with the

Equinor said it entered into a long-term strategic agreement to supply up to 23 terawatt-hours of natural gas, or around 2 billion cubic meters, annually to BASF SE over a 10-year period. The contract secures a substantial share of BASF’s natural gas needs in Europe, Equinor said in a news release. The gas will be sold on market terms, and deliveries will start on October 1. BASF uses natural gas both as an energy source and as a raw material in the production of basic chemicals, according to the release. The partnership will support BASF’s strategy to diversify its energy and raw materials portfolio, Equinor said. “This agreement further strengthens our partnership with BASF. Natural gas not only provides energy security to Europe but also critical feedstock to European industries. I am very happy that our gas also supports BASF’s efforts to reduce their carbon footprint. Gas from Norway comes with the lowest emissions from production and transportation,” Equinor President and CEO Anders Opedal said. “We are very happy to enter into this long-term partnership with Equinor for the reliable supply of low-carbon natural gas for BASF’s operations in Europe. Equinor is a trusted and valued partner. The supply agreement not only comes with competitive terms but also supports our sustainability targets,” BASF CFO and Chief Digital Officer Dirk Elvermann said. For the past several years, Equinor has been supplying gas and liquids to BASF, which develops a broad portfolio of solutions that are components in the manufacturing of everyday consumer goods, such as car interiors, sportswear, personal care items, and agricultural solutions, according to the release. Development Plans for Johan Sverdup Meanwhile, Equinor and its partners plan to invest $1.27 billion (NOK 13 billion) in the third phase of Johan Sverdrup oil field in the North Sea, approximately 87

In its latest short term energy outlook (STEO), which was released earlier this month, the U.S. Energy Information Administration (EIA) projected that total U.S. electricity generation from the electric power sector will come in at 4,244.2 billion kilowatt-hours (BK) in 2025. The EIA projected in its latest STEO that 1,696.9 BK of that total will come from natural gas, which represents around 40 percent, and 1,046.7 BK will come from renewable energy sources, which represents around 25 percent. Renewable energy sources included in the STEO comprised conventional hydropower, wind, biomass, geothermal, and solar. The solar category included generation from utility-scale (larger than one megawatt) solar photovoltaic and solar thermal power plants and excluded generation from small-scale solar photovoltaic systems, the STEO highlighted. The EIA expects wind to contribute the largest figure to the renewable energy sources category this year, at 472.8 BK, the STEO showed. Solar is expected to come second in this category, with 291.5 BK, and biomass third, with 20.5 BK, the STEO highlighted. Nuclear is projected in the STEO to be the third largest source of total U.S. electricity generation from the electric power sector, at 783.8 BK, and coal is forecast to be the fourth largest source, at 702.6 BK. Petroleum – comprising residual fuel oil, distillate fuel oil, petroleum coke, and other petroleum liquids – is expected to contribute 17.4 BK to the total, according to the STEO, which projected that other fossil gases will make up 3.0 BK and other non-renewable fuels will make up 1.4 BK. These comprise batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, nonrenewable waste, and miscellaneous technologies, the STEO pointed out. The EIA highlighted in its July STEO that total U.S. electricity generation from the electric power sector came in at 4,150.9 BK in 2024. That STEO pointed out that

Buru Energy Ltd. has adjusted the timeline for the development of the Rafael natural gas project in Western Australia’s Canning Basin but still aims for a startup late 2027. The Rafael gas and condensate field is in Exploration Permit 428, about 150 kilometers (93.21 miles) east of Broome and around 85 kilometers south of Derby in the Shire of Derby-West Kimberley, according to Buru. Rafael is the only confirmed source of conventional gas and liquids onshore Western Australia north of the North West Shelf Project, according to Buru. First drilled in 2021 and confirmed as a discovery the same year, Rafael has been assessed to hold contingent and unrisked gross recoverable volumes of 85-523 Bscf of gas and 1.8-10.6 MMstb of condensate, according to Buru. Buru eyes a 20-year production life. It expects the project to supply trucked liquefied natural gas and liquids to Pilbara and the Northern Territory. Buru plans to drill two wells, including the 2021 discovery. Under the new timeline, instead of recompleting the discovery well as a producer before drilling a second well called Rafael B, Buru will now drill and test Rafael B first. Drilling is planned to start June 2026. The change aims “to reduce risk and increase the probability of higher reserves”, West Perth-based Buru said in a regulatory filing. Chief executive Thomas Nador said, “The Rafael technical assurance process has delivered valuable information to underpin decision making on the risks and opportunities of our planned Rafael appraisal and production flow test program”. “Drilling and testing the Rafael B appraisal well next is the optimum pathway to proving up the resource and underpinning a robust Final Investment Decision, whilst maintaining our first cashflow target of late 2027”, Nador added. Earlier this month Buru said it had received government approval for a two-year extension