Three weeks ago, Hurricane Harvey threw a wrench in — well in a lot of things — but also into the natural gas market, curbing gas demand for power generation, curtailing pipeline exports to Mexico and stymying LNG exports. The market is still digesting the full impact of these disruptions and their potential effects on the gas market balance and storage. Adding to recent market shifts is the start-up of Energy Transfer Partners’ (ETP) Northeast-to-Midwest Rover Pipeline Phase 1A on September 1, which already is flowing 0.7 Bcf/d and lifting gas production out of Ohio. The market is hurtling towards winter, with just five weeks or so left until heating demand typically starts showing up and storage facilities officially begin to flip into withdrawal mode. What can recent supply and demand volumes tell us about what to expect from the gas market this winter? Today, we wrap up our most recent gas market update series with a forward look at potential scenarios for supply, demand and storage in the coming withdrawal season.
In another key milestone for Northeast pipeline takeaway capacity expansions, Energy Transfer Partners’ beleaguered Rover Pipeline project began partial service on its Phase 1A portion on gas day September 1. The 3.25-Bcf/d project, which is due for completion in early 2018, is expected to provide relief for constrained Northeast producers while exacerbating oversupply conditions and gas-on-gas competition in the Dawn, Ontario, storage and demand market area and surrounding region. Within days of initial start-up, flows on Rover ramped up to 700 MMcf/d, and both Ohio and overall Northeast production already have posted record highs since then as a result. Today, we take a look at the project, including initial flows and the expected timing of full completion.
Today’s energy markets are being rocked by new technologies, massive flow shifts to exports, and a myriad of new midstream infrastructure projects — to say nothing of the continuing onslaught of Mother Nature. It is more important than ever to understand how the markets for crude oil, natural gas and NGLs are tied together, and that is why it is time again for RBN’s School of Energy. But … this is not the best time for our Houston conference venue. So we’ve made the decision to GO VIRTUAL! We will webcast the entire School in real-time, with the same content, the same faculty and the same models. And since an understanding of the new realities of today’s energy markets is so essential, we have renewed, restructured and rebuilt our curriculum to CONNECT THE DOTS across our content, data and models. That’s the theme for our upcoming School of Energy 2017 – Virtual Edition, which we summarize in today’s advertorial blog.
Even with a double-digit percentage decline in crude oil prices since their initial capital spending budgets for 2017 were set, the 13 diversified U.S. exploration and production companies (E&Ps) we’ve been tracking are trimming their spending plans for the year by only $300 million, largely keeping in place $19 billion in drilling and completion investment. The Diversified Peer Group’s apparent confidence flies in the face of eroding investor sentiment as the median enterprise value per barrel of oil equivalent (boe) of reserves has declined 23% since year-end 2016 to $13.72/boe. Today, we review the changes in the outlook for the Diversified Peer Group’s upstream capital spending plans and update their expectations for 2017 oil and natural gas production.
A federal appellate court decision has set back the approval of a newly completed set of natural gas pipelines in the U.S. Southeast, and raised the possibility that all gas pipeline projects will need to clear a new — and potentially challenging — hurdle before they can secure a final OK from the Federal Energy Regulatory Commission (FERC). In its late-August ruling in Sierra Club, et al vs. FERC, the U.S. Court of Appeals for the District of Columbia Circuit said FERC’s environmental impact statement for the Southeast Market Pipelines Project, which includes the 1.1-Bcf/d Sabal Trail pipeline from west-central Alabama to central Florida, should have considered greenhouse gas emissions from gas-fired power plants the new pipelines will serve. Today, we explore the potentially far-reaching effect of the decision on midstream companies and the utilities that depend on them.
With the start-up of new capacity on Energy Transfer Partners’ Rover Pipeline out of the Southwest Marcellus and Utica now a reality and the service on several other pipeline expansions out of the Northeast expected to begin soon, some of the questions that have been vexing the market for years are about to be answered. Principal among these: How much will natural gas production in the region grow and how fast? How will Northeast supply growth affect the larger U.S. market? And how will supply growth across the country compare with increasing demand? (Hint: the numbers could be staggering, the impact will be too, and there could be a big supply/demand disconnect.) Today we examine how a prospectively huge supply/demand imbalance in the U.S. natural gas market might be rectified.
Hurricane Harvey has dissipated, but the affected areas, including energy infrastructure and operations, are still in recovery mode and will be for some time to come. In the natural gas market, production fell as low as 71.3 Bcf/d this past week, and has now rebounded to pre-storm levels near 72 Bcf/d. But exports to Mexico, which were averaging near 4.4 Bcf/d in the 30 days prior to Harvey, were at 3.6 Bcf/d last Friday, still lagging 0.8 Bcf/d (18%) behind their pre-storm level, after dropping to as low as 2.85 Bcf/d last week. Deliveries for LNG export are also down nearly 1.0 Bcf/d (47%) from the 30-day average to just under 1.0 Bcf/d last Friday and dropped to about 475 MMcf/d over the weekend. Meanwhile, U.S. consumption — in the power, industrial and residential and commercial sectors — this past week averaged 62.8 Bcf/d, down 6.0 Bcf/d (9%) versus last year and also 1.6 Bcf/d (3%) lower than the five-year average for this time. In another important market development, Energy Transfer Partners’ new Rover Pipeline began partial service on Friday and deliveries rose to more than 500 MMcf/d over the weekend. What will these shifts mean for the gas market balance and storage inventory? Today, we continue our analysis of the gas market balance, this time with a forward look at potential storage scenarios for the balance of injection season.
It has been a tragic week for the Gulf Coast, with months if not years of cleanup and rebuilding ahead of the region. But already, Houston, Corpus Christi, Port Arthur/Beaumont, Lake Charles and other affected areas are coming back online through the hard work of resilient Texans and Louisianans as well as aid coming in from across the country. And even though the energy industry is also moving quickly to put Hurricane Harvey in the rearview mirror, the damage and disruption have been extensive. It is still much too early to fully understand what has happened and how long the recovery is going to take. But with information that we can piece together from public statements, data analysis and conversations with knowledgeable market participants, it is possible to start developing an assessment of Harvey’s effects. That’s what we will tackle in today’s blog.
In the short term, Permian natural gas will be dealing with the aftermath of Harvey and what it might do to associated gas production from crude oil wells being curtailed due to refinery downtime and storage capacity issues. But that will soon be behind us, and at that point Permian natural gas production will resume its steep upward trajectory. Just a few months ago, the gas market was still sharpening pencils on potential gas takeaway constraints in West Texas, but congestion in the Waha gas market now appears as likely as another winning season for Alabama football. Where will this tide of natural gas end up? Until a few days ago, the Agua Dulce Hub in South Texas was Number 1 on the list, but a new project has thrown the Katy Hub into the mix as a potential destination. Today we analyze an interesting approach to relieving Permian natural gas market constraints.
Ahead of Hurricane Harvey, the CME/NYMEX Henry Hub September natural gas futures contract this past Friday settled at $2.892/MMBtu, down 5.7 cents on the day, as the market awaited the impact of the storm. Since then, preliminary gas pipeline flow data show major shifts in supply and demand (more on that in the blog). As of Sunday evening, the September contract was complacent, up little more than a penny in after-hours trading. We’ll know more about the effects of Harvey and the market’s reaction today and in the coming days and weeks. But prior to Harvey, the gas market has been sluggish in recent months. Last Friday’s settlement is down 34 cents from the summer peak expiration settlement in June of $3.236. The U.S. natural gas inventory deficit to last year has come down from more than 400 Bcf at the start of injection season in April to about 220 Bcf as of the latest storage data. What’s behind the higher injections and lower prices up to this point? Today, we continue our analysis of the gas market balance, including the latest on Harvey.
The surge in crude oil, natural gas and natural gas liquids (NGL) production in the Permian is driving a massive buildout of midstream infrastructure designed to move the hydrocarbons to end-use markets. On the gas processing front, there are literally dozens of projects announced or in the planning phase that are scheduled to start up over the next two years. Some are small projects aimed at a few producers, while others are set to significantly expand processing capacity and affect large areas of the basin’s gas gathering and transmission network. Today, we discuss Vaquero Midstream’s ambitious Delaware Basin gathering and processing projects.
Despite a 12% decline in crude oil prices from their December 2016 highs, the 43 top U.S. exploration and production companies (E&Ps) we’ve been tracking are largely maintaining their aggressive 2017 drilling and completion capital spending plans, announcing a mere $1.0 billion — or 1.5% — decline in total investment since the plans were unveiled. The industry’s apparent confidence in the long-term profitability of its aggressive development of the major U.S. resource plays is in sharp contrast with eroding investor sentiment that has driven Standard & Poor’s (S&P) E&P Index 29% lower than its late-2016 peak. The companies that announced modest investment reductions — about one-third of our universe of 43 E&Ps — cited cost savings from increased drilling efficiency and divestments as well as the lower short-term price outlook as reasons for the cuts. Today we review the changes in the overall outlook for 2017 upstream capital spending and oil and natural gas production, and take a quick peek into our three peer groups: those that focus on oil, those that focus on gas, and diversified E&Ps.
On August 4, the U.S. Senate confirmed two new commissioners for the Federal Energy Regulatory Commission (FERC), restoring the three-member quorum legally required for FERC to vote. The Senate action ended a six-month dry spell during which FERC could not issue any orders, and thus could not approve any of the many pipeline projects pending there. What does it mean that FERC can act again to approve new projects? And does that mean the industry can move forward at the pace it needs? Today we explore these questions and assess what it will take to get some key gas infrastructure projects back on track.
Despite starting the 2017 injection season on April 1 with much less gas in storage than last year, U.S. natural gas prices in recent months have struggled to return to $3.00 levels. The market has been dealing with a mixed bag of factors, with demand down significantly, mostly due to milder-than-normal weather and the rise of competing generation sources. On the supply side, even though production has been flat and imports from Canada down, those developments combined with higher exports of LNG have not been enough to prevent larger injections into storage. Now, prospects for a price rally are waning as summer gives way to the more temperate shoulder season. Where does that leave the gas market heading into winter? Today, we begin a series looking at how gas market fundamentals have shaped up this summer as well as prospects for the winter.
Natural gas deliveries for export via Cheniere Energy’s Sabine Pass LNG terminal in Louisiana reached a record in late July, topping 2.5 Bcf/d. In the first seven months of 2017, exports have added an average of 1.5 Bcf/d — or more than 300 Bcf total — of baseload gas demand year on year. Thus far, the terminal has been operating with three liquefaction trains. Now the fourth train, which would bring on another 650-MMcf/d of potential export demand, is nearing completion. The incremental gas deliveries are scheduled to come just as winter heating season is kicking off and likely will tighten the gas market. Today, we look at the latest developments at the terminal.