The Mountain Valley Pipeline (MVP) and planned expansions to it and the Transcontinental Gas Pipe Line (Transco) system are providing utilities, data centers and others in Virginia and the Carolinas with enhanced access to Marcellus/Utica-sourced natural gas — and man, will they need it! Plans for new generating capacity between Washington, DC and the South Carolina/Georgia state line are proliferating, and the increasing ability to move large volumes of gas south on MVP and Transco will give producers in Pennsylvania, West Virginia and Ohio an important incremental outlet for their gas well into the 2030s. In today’s RBN blog, we’ll discuss the boom in power demand in Virginia, North Carolina and South Carolina and the very timely expansion of gas-pipeline access to three states.
Daily Energy Blog
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.
Even as many countries and companies around the world continue to ramp up their use of wind and solar power and explore the potential for a variety of renewable, low-carbon and no-carbon fuels, there’s a growing acknowledgment that natural gas — imperfect as it may be from a climate perspective — will remain a significant part of the global energy mix for decades to come. So why not make natural gas as clean as it can be by reducing emissions of methane — gas’s primary component and a particularly potent greenhouse gas? That’s the driver behind the certified gas movement, the focus of a new Drill Down Report that we discuss in today’s RBN blog.
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.
There are two primary drivers for consuming more natural gas close to where it emerges from production wells. One is to eliminate routine gas flaring, which is wasteful and environmentally detrimental, and the other — especially true in takeaway-constrained plays like the Permian — is to add value to gas that otherwise would be sold downstream at steeply discounted prices. In today’s RBN blog, we discuss some innovative approaches to maximizing gas value by consuming it “in-basin” — and the potential for a lot more gas to be used in West Texas and southeastern New Mexico.
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.
Shipping large volumes of LNG from Canada’s West Coast across the Pacific Ocean to gas-hungry markets in Asia has been a dream nearly two decades in the making. After a great deal of work and patience, three projects have moved into the construction phase, with the most advanced — LNG Canada — on the cusp of accepting its first test-gas volumes, with exports possible by the end of the year. Even with all this progress, three additional projects are vying for the opportunity to join Canada’s LNG export party, as we discuss in today’s RBN blog.
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.
U.S. LNG export capacity is poised to grow tremendously over the next few years, mostly near the Texas/Louisiana border. The gas-focused Haynesville Shale in northwestern Louisiana and northeastern Texas is a prime source of additional supply for those new and expanded terminals. But plans for new north-to-south pipelines to deliver incremental gas out of the Haynesville have been clouded by legal challenges. In today’s RBN blog, we’ll discuss the reasons for the disputes, what’s been going on recently, and the potential fallout.
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.
Developers have been kicking around plans for LNG exports from British Columbia (BC), Canada’s westernmost province, for more than a decade, with more than 20 projects on the drawing board at one point. That long list has been whittled down to just three that have reached the point of final investment decision (FID) — a hard plan to proceed to construction and startup. One of those projects, LNG Canada, should be sending out LNG as soon as the end of this year, placing Canada firmly on the map of LNG-exporting nations. In today’s RBN blog, we take a closer look at the three projects and hint at plans by a handful of contenders vying to join the LNG export party.
The U.S. Gulf Coast is poised to experience another big wave of new LNG export capacity, and this time it will be joined by new capacity coming online in both Mexico and Canada. The more than 13 Bcf/d of incremental natural gas demand from North American LNG projects starting up over the next five years will have significant effects on U.S. and Canadian gas producers, gas flows and (quite likely) gas prices, which have been deeply depressed for more than a year now. In today’s RBN blog, we provide updates on the 10 LNG export projects in very advanced stages of development in the U.S., Mexico and Canada, detail the expected ramp-up in LNG-related gas demand and discuss the potential impact of rising LNG exports on gas prices.
The Panama Canal expansion completed in June 2016 was expected to allow much larger LNG tankers to move product from Sabine Pass LNG and other Gulf Coast export terminals through the canal to Asian and Latin American customers. But water levels at Gatun Lake, which provides the fresh water needed to operate the canal’s locks, have been well below normal in recent years, limiting opportunities to use the canal and complicating plans to ramp up LNG flows through it. In today’s RBN blog, we look at the challenges of moving LNG through the Panama Canal, how access to the waterway has been affected by drought and climate conditions over the past decade, and the impact on the LNG market.
Some of the most prolific, crude-oil-saturated rock in the Permian’s Delaware Basin and Central Platform comes with a nasty complication — namely, associated gas with very high levels of hydrogen sulfide (H2S) and carbon dioxide (CO2). But rather than walking away from all those potential barrels, one midstream company saw the treatment of high-H2S, high-CO2 gas as a market niche worth pursuing. Backed by commitments from Black Bay Energy Capital and an area E&P, Piñon Midstream has been expanding a system in southeastern New Mexico that not only gathers the super-corrosive gas and removes almost all the H2S and CO2, it also permanently sequesters the stuff deep underground through a pair of 18,000-foot-deep, Class II injection wells. In today’s RBN blog, we will provide an update on Piñon’s Dark Horse Treating Facility and the company’s plan for a further build-out of its sour gas system.
To closely analyze the natural gas market is to be constantly bombarded with vast amounts of information — weather forecasts, pipeline flows, LNG feedgas, power demand and storage — that is frequently updated, impacting both spot and future prices. But before you can get into the deeper analysis, you’ve got to understand the natural gas value chain and its terminology. In today’s RBN blog, we’ll explain the various terms used to describe natural gas as it moves from wellhead to consumer.
