Mexico’s power sector is one of three major demand centers U.S. natural gas producers and pipeline projects are targeting, the other two being the U.S. power sector and LNG exports. U.S. natural gas exports to Mexico are up 20% year-on-year in 2016 to date to nearly 3.5 Bcf/d––more than double the export volume five years ago––and are poised to soar past 6 Bcf/d by the end of the decade. Mexico’s energy operators are on a tear adding new natural gas-fired power generation capacity and building a sprawling network of natural gas transportation capacity. But delivering increasing volumes of U.S. natural gas to Mexico will require substantial changes on the U.S. side as well, particularly in Texas. Today, we continue our look at plans for adding pipeline export capacity along the Texas-Mexico border.
The increasing availability of LNG at low and relatively stable prices, combined with the ability to expedite the installation of LNG receiving/regasification infrastructure, has the potential to spur faster growth in global LNG demand than many have been expecting. If that happens, the current––and still growing––glut in worldwide liquefaction capacity could shrink in a few years’ time, and a “second wave” of U.S. liquefaction/LNG projects could start coming online by the mid-2020s. Today, we conclude our series on U.S. LNG exports with a look at how low, stable LNG prices may turn the market toward supply/demand balance.
After about four weeks offline for modifications and maintenance, Cheniere’s Sabine Pass liquefaction terminal in Cameron Parish, Louisiana began accepting nominal deliveries of feed gas starting last Friday, indicating the facility is due to ramp up to capacity any day now. Since the first export cargo in February, about 130 Bcf, or 0.6 Bcf/d, of natural gas has been delivered to the terminal. While those aren’t quite game-changing volumes yet, deliveries just prior to the outage were averaging more in the vicinity of 1.2 Bcf/d and indications are that deliveries could ramp up to more than 1.0 Bcf/d in short order with the restart and grow to more than 2.0 Bcf/d by the end of 2017. It’s clear that LNG exports are quickly becoming a prominent and inescapable feature of the U.S. natural gas market. Today, we wrap up our series on the growing impact of LNG exports on the U.S. supply/demand balance.
Handling the flood of Marcellus/Utica gas headed to Gulf Coast LNG export terminals and to Mexico will require pipeline reversals and expansions, new pipe and a coordination of interstate and intrastate pipeline capacity. That’s a tall order in itself, but there’s more: Texas’s intrastate pipelines operate under an entirely different set of regulations than their interstate counterparts––different rules on pipeline tariff rates, pipeline rules, permitting, eminent domain, you name it. In today’s blog we continue our look at developmental history of the Lone Star State’s two gas pipeline systems––one regulated in Washington, DC and the other in Austin––and how it may affect the transformation of the overall natural gas transportation grid.
There is a natural gas renaissance of sorts happening south of the U.S.-Mexico border. The state-owned Comisión Federal de Electricidad (CFE) is investing heavily in expanding and modernizing its power generation fleet with thousands of megawatts of new, natural gas-fired power plants, and the energy secretary also last October put forth an aggressive five-year plan to build out a pipeline system to supply growing gas-fired generation demand. Mexico’s power generation demand is increasingly a target for U.S. gas producers and pipeline projects. At the same time, as we discuss in Part 2 of RBN’s Miles and Miles of Texas Drill-Down Report published last week, a good portion of this new demand is relying on — and in large part has been driven by — availability of low-priced gas from the U.S. via Texas and the U.S. Southwest states. But there is a lot that needs to happen on both sides of the border over the next few years to facilitate this mutually beneficial relationship. Already since October, Mexico’s newly appointed independent pipeline operator, Centro Nacional de Control del Gas Natural (CENAGAS), has pulled back on the pipeline buildout. Today, we begin a two-part series on how plans to facilitate this new demand are progressing, starting on the Mexico side of things.
Texas’s vast natural gas pipeline network is undergoing a major transformation to enable gas from the Marcellus/Utica shale plays to flood south/southwest into and through Texas to LNG export terminals and to Mexico. To grasp the complexity of the task at hand, it is critically important to understand how Texas’s “spaghetti bowl” of interstate and intrastate pipeline systems evolved in parallel but under very different regulatory constructs, and with the intention of serving very different market needs. In today’s blog, we begin an examination of the state’s two pipeline systems––one regulated by the Feds in Washington, DC and the other by the Texas Railroad Commission in Austin, TX––and why the intrastate system has taken on a new significance for U.S. natural gas markets.
Developing a multibillion-dollar liquefaction/LNG export project takes perseverance and patience––and having good luck wouldn’t hurt. The “first wave” of U.S. projects is now cresting; the first two liquefaction “trains” at Cheniere Energy’s Sabine Pass LNG facility are essentially complete, and 12 other trains are under construction and scheduled to come online in the 2017-19 period. But what about the “second wave” of projects that was supposed to be arriving soon thereafter? Today we continue our series on the next round of U.S. LNG projects with a run-through of the projects themselves and a look at how (despite the current market gloom) there is at least some cause for optimism that a few may get built by the early 2020s.
Over the next three years, 16 pipeline projects are in the works to add more than 14 Bcf/d of new take-away capacity to move Marcellus/Utica natural gas to the south and west, relieving takeaway capacity constraints that have plagued the Northeast since 2012-13. Much of this gas will be moved to the Gulf Coast, primarily via reversals of pipes that traditionally transported gas north and east, and will target rapidly growing LNG and Mexico export markets. But few of these pipeline projects get the gas all the way to those export outlets. The new supplies must traverse “Miles and Miles of Texas” (and Louisiana) to reach the export gateways and along the way deal with shifting production trends within the state, pipeline systems that are "telescoped the wrong way" constraining capacity of the Texas pipeline grid, and unique regulatory considerations associated with Texas intrastate pipelines. These issues are addressed in RBN’s latest Drill Down Report, highlights of which we discuss in today’s blog.
The inventory of drilled-and-uncompleted wells (DUCs) in the U.S. Lower 48 grew by nearly 1,900 between the months just before oil prices and rig counts collapsed and early 2016—a 50% increase in a roughly two-year period, according to new DUCs data in the Energy Information Administration’s (EIA) September Drilling Productivity Report (DPR—See the DPR DUC report here.). Since January’s peak of nearly 5,600 DUCs, producers have been working down the national inventory of DUCs, with the DPR showing the overall count closer to 5,000 as of August (2016) ––but that is still up more than 1,300 from the December EIA’s 2013 baseline. This incremental growth in the number of “dormant” wells is key to understanding and predicting how long production can remain supported or grow in a low-rig count environment. Moreover, there are regional differences in the DUCs inventory counts and trends that provide critical insights on how various market factors are impacting drilling activity. Today, we walk through the EIA DUCs data for each of the producing regions.
The “first wave” of liquefaction/LNG export projects in the U.S. is cresting. Two new liquefaction trains in Louisiana are already producing liquefied natural gas, and a dozen other trains are under construction and scheduled to begin commercial operation in the Lower 48 over the next three years. The problem is, these multibillion-dollar facilities––planned when LNG market dynamics were much more favorable––are “rolling in” as the global market faces a supply glut, weak LNG demand growth, and low prices. Today, we begin a series on the next round of U.S. LNG projects and how soon market conditions might improve enough to justify building them.
For some time now, discussions about the possible development of Canadian liquefaction/LNG export terminals have focused on the Western Canadian coast in British Columbia––partly because most of Canada’s natural gas reserves are nearby in northeastern BC and in Alberta, and partly due to Asia being a primary LNG target market. . But it could be that liquefaction/LNG export projects in Eastern Canada may make more sense. In today’s blog, “So Far Away –Sending Western Canadian Natural Gas East for Export as LNG,” LNG Ltd.’s Greg M. Vesey considers the rationale for piping Western Canadian natural gas long distances to Quebec and the Canadian Maritimes for export as LNG.
At long last, the Energy Information Administration (EIA) has reported an “official” estimate of the U.S. drilled-and-uncompleted well (DUC) inventory as part of its monthly Drilling Productivity Report. DUCs are a critical factor in forecasting production trends, as many of these wells are likely to be some of the first to come online as soon as prices move higher and thus have the potential to boost production quicker and easier than would otherwise be the case. However, the number of DUCs has been a difficult thing to measure, though not for lack of trying. There are, in fact, widely varying counts from many different sources circulating in the industry. Today, we begin a short series on these latest DUC counts and their potential implications.
Natural gas production volumes in the Permian Basin are very near the all-time record of 6.9 Bcf/d set last September, and crude oil and gas producers alike see nothing but blue skies for the highly prolific West Texas/Southeast New Mexico play. The Permian already has a lot of gas processing capacity, but a good bit of it is older, and parts of the region—especially the super-hot Delaware Basin—need more of the big, efficient cryogenic plants that can process 100 to 200 MMcf/d. Today, we continue our review of gas production and processing in the biggest U.S. gas-producing region that is not named Marcellus.
Planned liquefaction/LNG export facilities along the South Texas coast and growing demand from Mexico’s electric power sector together will require several billion cubic feet/day of additional U.S. natural gas over the next three to five years. Gas producers from the Marcellus/Utica to the Permian are targeting these markets, but there are questions regarding whether the Lone Star State’s existing pipeline infrastructure is sufficient to deliver all that gas to these critically important export markets. Part of the solution will be optimizing the use of Texas’s impressive—but sometimes misunderstood intrastate pipeline networks, particularly the far-reaching systems operated by Enterprise, Energy Transfer and Kinder Morgan. Today, we discuss one part of the solution, an inexpensive but impactful Kinder Morgan project that will enable about 1 Bcf of natural gas from various sources to reach South Texas LNG exporters and Mexico on KM’s intrastate system.
Despite the doom and gloom that many see in the global LNG market –– too much supply, weak demand growth, and low LNG prices –– the possibility remains that the sector may offer the opportunity for low-cost, highly responsive market participants to do quite well, and even thrive. How can that be? After all, we’ve just seen another year of low crude oil prices resulting in very low oil/natural gas margins, and the expectation of high oil/gas margins were critical in supporting the development of many U.S. liquefaction/LNG export projects. But a combination of responsive demand, low cost infrastructure development and the possibility that number of exporting countries could run out of gas at or near the end of their existing contracts could change the outlook for ongoing LNG export development. Today, we look at the LNG market in the context of themes discussed at the North American Gas Forum (NAGF). Warning: this blog includes a plug for this year’s NAGF conference.