The U.S. Northeast natural gas market has had a volatile few weeks. Regional gas production has surged, averaging 30.4 Bcf/d in the second half of October (2018), up 800 MMcf/d from the first half of the month and up nearly 1 Bcf/d from the September average. Normally (for the past several years), those kinds of supply gains, particularly in a shoulder month and during maintenance season, would have one result: Marcellus/Utica prices taking a nosedive. But that’s not exactly the case this year. Instead, Appalachian spot prices have been on a wild ride the past few weeks, swinging from barely $1.00/MMBtu (or more than $2.00/MMBtu below Henry Hub) on October 8, to over $3.00 (just $0.12 under Henry) on October 24 — the highest levels seen at this time of year since 2013, both in terms of outright prices and basis differentials to Henry Hub. The catalyst is nearly 3 Bcf/d of new takeaway capacity from the growing producing region that has been added in recent weeks, including, most recently, partial service on a brand-new route on Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission. What does this latest round of expansions and the resulting basis strength mean for the Northeast and its downstream gas markets? In today’s blog, we discuss highlights from our new 26-page report on evolving Northeast gas takeaway capacity utilization and additions, and their effects on price relationships.
Phillips 66 loaded its first Panamax tanker for export to Mexico over the weekend. Late on Sunday night, the SCF Prime signaled that it was headed for Pajaritos, Mexico, after loading at Phillips' terminal in Beaumont, TX. Mexico is making history with this pivotal first purchase of Bakken crude from Phillips 66 at the U.S. Gulf Coast (USGC). Up until now, the crude oil trade between the U.S. and Mexico had been a one-way street, with oil moving from Mexico to the U.S. and not the other way around. But now, as Mexico’s state-run oil company Petróleos Mexicanos (Pemex) faces dwindling oil production and refinery outputs, importing light, sweet crude from the U.S. is a new avenue to revive Mexico’s refinery utilization. Today, we examine the new shift in the traditional flows of crude oil across the Gulf of Mexico.
Crude oil production in the Niobrara region in northeastern Colorado and eastern Wyoming has quadrupled since the start of the 2010s, and now tops 600 Mb/d. Fortunately for producers in the Niobrara’s Denver-Julesburg (D-J) Basin and Powder River Basin (PRB), midstream companies not only developed enough new pipeline takeaway capacity to transport all those incremental barrels, they overbuilt. As a result, the region — unlike the Permian and Western Canada — currently has no crude-oil pipeline constraints, something that makes the Niobrara even more attractive to producers. But part of a pipeline system now moving crude out of the D-J is being repurposed to carry NGLs instead, and with D-J and PRB crude production still rising, you’ve got to wonder, is a takeaway shortfall on the horizon? Today, we continue our series on the Rockies’ premier hydrocarbon production area and the infrastructure needed to serve it, this time focusing on crude oil.
LNG Canada, the newly sanctioned liquefaction/LNG export project in British Columbia, is an entirely different animal than its operational and under-construction counterparts in the U.S. The Shell-led LNG Canada project is being developed without any of the long-term offtake contracts that financed Sabine Pass, Cove Point and the projects now being built along the Louisiana and Texas coasts, and it requires the construction of a new, long-haul pipeline — Coastal GasLink. What’s also different is that the BC project’s co-owners have been developing their own gas reserves to supply the project, though they may also turn to the broader Montney and Duvernay markets for the gas they will need. Today, we conclude a two-part series with a look at how the project expects to undercut its U.S. competitors.
U.S. natural gas supply continues to set all-time records, and strong production growth is expected to continue. Most of these supply gains will come from the Northeast, where another round of pipeline capacity additions are being completed. But despite all this incremental gas output, a combination of cold weather last winter and hot weather this summer means that U.S. gas storage inventories are likely to end the fall season at their lowest levels since 2005. And even this comparison understates how low inventories are — gas consumption has grown dramatically in the past 10 years, and storage inventories are at all-time lows when considered in terms of the number of days of average consumption. Today, we begin a series on the implications of historically low gas storage inventories, including what the gas market might look like if this winter turns out to be colder than normal.
The discount for Bakken crude prices at Clearbrook to WTI at Cushing has been on a rollercoaster in recent weeks, widening from $1.30/bbl at the beginning of September 2018 to over $10/bbl in mid-October and narrowing again most recently. There are several factors at play here. Canadian production has overwhelmed area pipelines and prices are being heavily discounted. These cheap Canadian barrels are creating oversupply issues at markets that Bakken barrels also trade into. On the demand side, Midwestern refiners are in the middle of seasonal turnarounds, reducing the demand for both Bakken and Canadian grades. Meanwhile, Bakken production growth continues to steadily chug along, increasing by over 150 Mb/d since the beginning of the year. And while this recent Bakken price angst is cause for concern, there is a looming bottleneck for pipeline space that could really shake things up sometime next year. Today, we examine the recent price phenomenon, the relationship between Canadian crude differentials and Bakken prices, and why producers should be concerned about future pipeline shortages.
For 65 years, Enbridge’s Line 5 has been a critically important conduit for moving Western Canadian and Bakken crude oil and NGLs east across Michigan’s upper and lower peninsulas and into Ontario, where the now-540-Mb/d pipeline feeds Sarnia refineries and petrochemical plants. Some crude from Line 5 also can flow east from Sarnia to Montreal refineries on Line 9. But Enbridge has been under increasing pressure to shut down Line 5 over concern that a rupture under the Straits of Mackinac might cause major environmental damage. At long last, the state of Michigan and Enbridge have reached an agreement to replace the section of Line 5 under the straits by the mid-2020s, and to take steps in the interim to enhance the existing pipeline’s safety. In today’s blog, we consider the significance of the Enbridge pipeline and of the newly reached accord.
Time and again, the repurposing of existing assets like pipelines and marine terminals to meet changing market needs has proven to be a winning approach. After all, if a lot of what you need is “already there” — as we said in today’s song title — why build something entirely new? That use-what-you’ve-got tack is a key driver behind MPLX and Crimson Midstream’s recently unveiled Swordfish Pipeline project, which by early 2020 would enable large volumes of crude oil to flow south from the St. James, LA, market hub to the Clovelly storage hub — a key crude distributor to area refineries and the jumping-off point for crude exports on fully loaded Very Large Crude Carriers (VLCCs) via the Louisiana Offshore Oil Port (LOOP). The companies also envision using other existing pipelines — including a possibly reversed Capline — as well as the soon-to-be-finished Bayou Bridge Pipeline to feed crude into Swordfish. Today, we review the MPLX/Crimson plan and assess how it might boost the export cred of LOOP, which is currently the only Gulf Coast port that can fill a 2-MMbbl VLCC to the brim without reverse lightering.
Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission pipeline saw its first natural gas flows this week, as the Federal Energy Regulatory Commission (FERC) approved partial service on the project, opening another nearly 1 Bcf/d of capacity from Appalachia’s Marcellus/Utica producing region to the Midwest. NEXUS marks the last big westbound takeaway project from the Northeast, except for the remaining pieces of Energy Transfer’s (ETP) Rover Pipeline. It also marks the escalation of gas-on-gas competition in the Midwest market, where U.S. Midcontinent and Canadian gas supplies are also battling it out for market share. Today, we take a closer look at the NEXUS project and its potential implications for the Northeast and Midwest gas markets.
Permian oil and gas production may have slammed up against capacity constraints, but that does not mean production growth has ground to a halt. Far from it. In the past 10 weeks, Permian gas production is up another 8% — a gain of almost 700 MMcf/d. Crude production now tops 3.5 MMb/d, with incremental barrels finding their way to market via truck, rail and new pipeline capacity — soon including Plains All American’s new Sunrise project, which will move more Permian crude toward the hub in Cushing, OK. Record-setting volumes of NGLs are streaming their way out of the Permian to Mont Belvieu. This market is moving so fast that if you blink, you’ll miss something important. So to get caught up with all things Permian, last week RBN hosted PermiCon, an industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. We think PermiCon accomplished that goal, and in today’s blog, we summarize a few of the key points discussed during the conference proceedings.
Crude oil production in the Rockies’ Niobrara region is up by more than 50% since the beginning of last year, spurred on by higher oil prices, ample oil pipeline takeaway capacity, and other positive factors. Natural gas and NGL production in the Niobrara — which includes both the Denver-Julesburg (D-J) Basin and the Powder River Basin (PRB) — has been rising too, to the point that there’s a scramble on to develop new gathering systems, gas processing plants as well as gas and NGL pipeline capacity. A number of exploration and production companies are upbeat about the region’s prospects; so are some midstreamers. But there’s a dark cloud on the horizon — at least in Colorado, where voters will decide in a few weeks whether to significantly restrict where new wells can be drilled. Is the Niobrara poised for continued growth or not? Today, we kick off a new series on Rockies production, infrastructure and prospects.
The final investment decisions by Royal Dutch Shell and its partners in the LNG Canada liquefaction and export project in British Columbia are a long-term boon to Western Canadian natural gas producers and to TransCanada, which now can proceed with its planned Coastal GasLink pipeline across the full breadth of BC. But the LNG Canada facility in Kitimat and the new 420-mile, 2.1-Bcf/d pipe won’t come online until 2023 — an eternity for producers in the region’s Montney and Duvernay shale plays, who through much of 2018 have been enduring profit-crushing price discounts for their gas relative to Henry Hub. Today, we consider the largest North American liquefaction/LNG export project to be sanctioned in several years, and why BC and Alberta producers wish it were coming online much sooner.
With a staggering 3.8 MMb/d of inbound pipelines, 3.1 MMb/d of outbound pipes and 94 MMbbl of storage capacity in between, the crude oil hub in Cushing, OK, surely has earned its nickname, “Pipeline Crossroads of the World.” But Cushing is more than a mere collection of pipelines and tankage, and crude doesn’t simply flow through the hub like cars and trucks flowing through a Los Angeles freeway interchange. Instead, much of the crude coming into Cushing from Western Canada, the Bakken, the Rockies, the Permian and other plays is mixed and blended within the hub, primarily to meet the specific needs of U.S. refineries and the export market regarding API gravity, sulfur content and the like. In other words, what goes in can be materially different than what goes out. Today, we continue our look at the central Oklahoma hub with an examination of the characteristics of the crude flowing in and out, and how they differ.
While many are getting ready for the usual trappings of fall — Halloween, Thanksgiving turkey and Black Friday sales — Northeast natural gas market participants are gearing up for their own seasonal ritual — gas pipeline takeaway expansions. Two days ago, Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission pipeline received approval to start partial service for nearly 1 Bcf/d of capacity. That follows Williams/Transco’s Atlantic Sunrise natural gas project, which launched service for its full 1.7 Bcf/d of southbound capacity last week (on October 6). Also last week, TransCanada/Columbia Gas Transmission was given the nod for partial service on both its Mountaineer Xpress and WB Xpress projects. Then there’s Energy Transfer’s Rover Pipeline, which is awaiting approval for its final two laterals. Combined, these projects are poised to add more than 4.0 Bcf/d of Marcellus/Utica takeaway capacity before the coldest months of winter arrive. What does that mean for the Northeast gas market this winter? Today, we provide an update on Atlantic Sunrise’s early effects and other upcoming projects completions.
Anyone who’s shopped for a home is well-aware of the relationship between location and valuation. The same holds true for oil and gas producers accumulating a portfolio of real estate underlain by the most promising oil and gas formations. Recently, the most desirable neighborhood has been the Permian Basin, which has seen more than $70 billion in M&A transactions since mid-2016. While the entire U.S. E&P sector has returned to profitability, Permian players have generated the highest production growth, the best margins, and the most substantial profits and cash flows. There’s a catch, though: production growth in the Permian has led to serious takeaway constraints. Today, we discuss how the impact of these constraints is reflected in a company-by-company analysis of quarterly results.