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.
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Daily energy Posts
California refiners are under siege. State regulators seem to view crude oil refining as a nasty habit that needs to be broken. There’s an important catch, though: car-happy California is not only the nation’s largest consumer of gasoline — and second to Texas in diesel use — it allows only special, superclean blends to be sold within its boundaries. And California’s 12 remaining refineries need to meet tougher emission standards, too, making it difficult for them to expand their business or even modernize their plants. Today we discuss the irony that sophisticated refineries producing the cleanest fuels in the U.S. are faced with a shrinking market and no real hope of expansion.
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.
Natural gas liquids production in the Permian Basin has doubled in the past four years, and may well double again by 2022. That rapid growth — driven by the pursuit of Permian crude oil and the resulting production of large volumes of NGL-rich associated gas — threatens to overwhelm the region’s existing gas processing and NGL-pipeline infrastructure. This is a big deal, because if there’s not enough gas processing and NGL takeaway capacity out of the Permian, exploration and production companies (E&Ps) in the U.S.’s hottest shale play would be forced to slow the pace of their development. Today we discuss highlights from our new Drill Down Report on Permian NGL production growth and the need for more NGL-related infrastructure.
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.
Last week Hurricane Harvey roiled the entire energy complex, with NGL markets suffering substantial disruption — curtailed natural gas liquids production from gas processing in the Eagle Ford and other basins, reduced operating rates at Mont Belvieu and other fractionation sites, shuttered LPG and ethane export docks, widespread refinery closures and a virtual shutdown of Gulf Coast petrochemical plants. While little major damage to facilities has been reported and several plants are now restarting, operating conditions continue to be extremely difficult for both the supply and demand sides of the market. Today we continue our look at how high winds and days of torrential rain affected the U.S. energy industry, this time focusing on NGLs.
Over the last year or so, Plains All American Pipeline — a large, crude oil-focused master limited partnership (MLP) — has twice made significant changes to its corporate structure and distribution process to free capital to fund organic growth, reduce debt, and strengthen distribution coverage. The changes are efforts to fix a problem: As oil prices plunged, PAA’s distribution coverage fell below 100% in 2015 and 2016, forcing the company to add debt and issue equity to raise cash. An initial restructuring that Plains undertook in mid-2016 included eliminating the incentive distribution rights (IDRs) payable to its general partner — the IDRs had been draining $620 million per year. (For more on IDRs, see Changing Horses in Midstream.) The change resulted in a 21% reduction in the distribution to limited partners as PAA set a minimum annual distribution coverage target of 115%. But plunging profits from the company’s Supply & Logistics segment eroded its coverage to 99% in 2017, triggering another comprehensive review of how it calculates its distribution. In late August, Plains announced a 45% reduction in the annual distribution, from $2.20 per unit to $1.20 per unit, and said it would base future distributions only on the results from its fee-based Transportation and Facilities segments. Today we preview our new Spotlight Report on Plains, which provides a detailed analysis of the likely future performance of all three segments of this major midstream MLP.
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.
The largest single expense associated with operating wells in a number of U.S. shale plays — including the Permian — is the cost of dealing with the large volume of produced water that emerges from wells along with crude oil, natural gas and NGLs. In many cases, produced-water disposal costs account for more than half of total well-operating costs, and every dime or dollar per barrel that an exploration and production company (E&P) needs to spend on produced water increases its break-even cost and saps its bottom line. To rein in trucking and other produced water-related expenses, more E&Ps and midstream companies are (1) developing produced-water treatment plants that allow the water to be reused in hydraulic fracturing and (2) building centralized systems that efficiently transport untreated produced water from multiple wells to treatment plants or to regional disposal wells. Today we continue our surfing-themed series on the effect of sand and water costs on producer economics with a look at how the old ways of dealing with produced water are being replaced by the new.
Hurricane Harvey and major flooding in Houston and other areas may affect energy markets and lead the 21 exploration and production companies in our Oil-Weighted Peer Group to readjust their 2017 investment programs. But in the weeks leading up to the Lone Star State’s most catastrophic weather event in decades, these E&Ps remained committed to their sharply accelerated 2017 capex plans. Their updated guidance issued with first-half 2017 earnings releases reveal a 44% increase in 2017 capital spending over 2016’s level to $26.5 billion, only a 2% reduction from the $27 billion initially budgeted for this year. The peer group also stayed confident in the long-term profitability of the major U.S. resource plays, which are receiving 80% of their 2017 capex, despite investor concern about lower prices that have triggered a 23% decline in the median enterprise value per barrel of oil equivalent for the Oil-Weighted peers since December 2016. Today we continue our review of updated capital spending plans by 43 U.S.-based E&Ps, this time with a look at companies that focus on oil.
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.