Daily Energy Blog

Enterprise Products Partners, already a leading provider of “well-to-water” or “well-to-market” midstream services out of the Permian, recently announced a deal to acquire private-equity-backed Piñon Midstream for $950 million in cash. But this isn’t just another bolt-on. Over the past few years, Piñon has been building out its one-of-a-kind Dark Horse system, which gathers and treats “sour” associated gas in a highly prolific, crude-oil-saturated part of the northern Delaware Basin and permanently sequesters the resulting hydrogen sulfide (H₂S) and carbon dioxide (CO₂) deep underground. In today’s RBN blog, we’ll discuss the impending Enterprise/Piñon acquisition, what Dark Horse does and how it gives Enterprise access to what may be the next hot production area in the Permian. 

The Permian needs more gas gathering and processing capacity pronto to support the expansion of crude-oil-focused drilling, and one of the Permian’s last privately held midstream companies is stepping up in a big way with the buildout of an entirely new — and very expandable — network in the Midland Basin. In today’s RBN blog, we discuss the impending startup of a new Brazos Midstream processing plant in Martin County, its plans for another Midland-area plant and the company’s already expansive midstream holdings in the Delaware Basin. As you’ll see, Brazos’s strategy echoes that of a well-known predecessor. 

The 1,413-MW Mystic Generating Station, a longtime workhorse for New England, shut its doors for good May 31. Located in Charlestown, MA, on the north side of Boston, Mystic is adjacent to the Everett LNG terminal, which supplied 100% of Mystic’s natural gas for several decades. The power plant’s closure meant the Everett terminal might also be history. However, the Massachusetts Department of Public Utilities (DPU) recently approved new contracts that will keep Everett LNG open for at least six more years. In today’s RBN blog, we’ll discuss the combined impact of Mystic’s demise and Everett’s stay of execution, how the region has handled this summer’s heat wave, and what could be in store for next winter. 

Data center power demand is soaring as AI — artificial intelligence — rapidly expands across all sorts of applications. That statement is certainly the top buzz factor in today’s energy markets. These facilities need 24x7, super-reliable power, and there’s only one power generation fuel that has any hope of keeping up with the demand surge: natural gas. While most data center developers would prefer green energy to cover their power requirements, the intermittent nature of wind and solar means that for many facilities, it can't happen, at least for the short-to-medium term hyped-up market we are seeing right now. But how much incremental power are we talking about? And how much natural gas will be needed? That’s what we’ll explore in today’s RBN blog. 

Every day, more than 7.5 Bcf of natural gas flows through the Agua Dulce Hub region in South Texas — 1.7 times the volume five years ago. And the hub’s growth is just beginning. By 2030, flows may well top 11.5 Bcf/d as gas production ramps up in the Permian and the Eagle Ford, pipeline exports to Mexico increase, and new LNG export capacity comes online along the South Texas coast. In today’s RBN blog, we begin a detailed look at the Agua Dulce Hub — its origins, its development during the Shale Era, its major players and its potential to become a major gas trading hub.

Power generation is one of the leading consumers of natural gas in Texas — every month last year, generators in the state used between 4 Bcf/d and 8 Bcf/d, on average, with the volumes peaking (as you would expect) in August, when air conditioning and a friend with a pool are must-haves. But as we’ve seen, the Texas power grid is often stressed to its limit, and the state has been taking steps to significantly increase the gas-fired generating capacity available for peak-demand periods in both the hottest and coldest months. In today’s RBN blog, we discuss one of the state’s boldest steps yet: the creation of a multibillion-dollar fund to support the development of thousands of megawatts of new gas-fired generation. 

Three phenomena — the European Union’s laser focus on reducing greenhouse gas (GHG) emissions, the EU’s now-significant reliance on LNG from the U.S., and the impending startup of new LNG export terminals along the Gulf Coast — are converging, with potentially significant implications for gas producers and LNG exporters alike. Starting next year, U.S. and other suppliers that ship LNG to EU member countries will need to begin complying with the EU’s methane emissions reporting requirements — full compliance is mandatory by 2027, and in 2030 and beyond the gas exported to the EU will be expected to meet a to-be-determined methane intensity (MI) target. As we discuss in today’s RBN blog, the EU methane regulations are still a work in progress, but they provide another reason why U.S. gas producers have been increasing their monitoring of methane emissions and their efforts to reduce them.