You may not know it by the look of the S&P E&P stock index, which has been flirting with record lows in recent weeks, but exploration and production companies are continuing to defy the industry’s legendary boom-and-bust cycles by pumping out increasing volumes of crude oil and natural gas while slashing spending. Some types of E&P companies have fared better than others in this lower-price environment. How are they continuing to generate substantial production growth under sharply lower capital investment programs? Today, we update our analysis of capital expenditures and production growth based on the second-quarter results of the 43 U.S. oil-focused, gas-focused, and diversified producers we track.
Recently Published Reports
|Crude Voyager||Crude Voyager Report September 17, 2019||4 days 10 hours ago|
|LNG Voyager||LNG Voyager Weekly | European regulatory news, price rally bullish for US LNG Exports | September 17, 2019||4 days 15 hours ago|
|NATGAS Billboard||Market consolidating recent gains with lower than average expected injection this week||4 days 16 hours ago|
|Crude Oil Permian||Crude Oil Permian - September 17, 2019||4 days 23 hours ago|
Daily energy Posts
As exports of crude oil, natural gas and NGLs have surged, U.S. markets for these energy commodities have undergone radical transformations. Exports now dominate the supply/demand equilibrium. These markets simply would not clear at today’s production levels, much less at the volumes coming on over the next few years, if not for access to global markets. It is more important than ever to understand how the markets for crude, gas and NGLs are tied together, and how the interdependencies among the commodities will impact the future of energy supply, demand, exports and, ultimately, prices. Making sense of these energy market fundamentals is what RBN’s School of Energy is about. Warning! Today’s blog is a blatant commercial for our upcoming Houston conference. But we hope you will read on, because this time around, our curriculum includes all the topics we have always covered at School of Energy, PLUS five all-new sessions dedicated to export markets.
Energy markets are constantly changing, but pipelines can take years to complete, and once they’re in the ground, that’s where they stay. Therefore, it’s critical for midstream companies to build as much flexibility as possible into their plans for new pipelines and other infrastructure, because you never know what the markets for crude oil, natural gas, NGLs and refined products might have in store. Energy Transfer apparently has that flexibility in mind as it’s been building out its Mariner East pipeline system across Pennsylvania to the Marcus Hook Industrial Complex (MHIC) near Philadelphia. Today, we consider recent developments regarding these key midstream assets in the Northeast and their still-evolving uses.
Crude oil pipeline shippers across the U.S., and especially in the Permian, are about to experience something they haven’t seen in a few years: a bunch of new crude takeaway capacity with lower-cost tariffs coming online, and the sudden need among committed shippers to fill their pipe space. This also affects some folks committed to space on older pipelines, whose higher-cost tariffs could leave them out of the money. The start-up of pipelines like Plains All American’s Cactus II, with a super-low $1.05/bbl tariff — and several pipelines in other basins lowering tariffs — has traders with pipeline commitments old and new re-running their economics and trying to determine their best strategy moving forward. Some may be forced to move volume at a loss. Today, we analyze the recent trend in tariff compression and how traders deal with uneconomical take-or-pay contracts.
The rise in unconventional natural gas supplies in Western Canada has forced the region to again confront a dilemma that it faced in the 1990s and early 2000s: not enough export pipeline capacity to move all that gas to market. Although demand for natural gas has been growing in Alberta’s oil sands and power generation markets, it has not kept pace with provincial gas supply growth, leading to oversupply conditions and historically low gas prices. The need to export more of the gas to other parts of Canada and the U.S. is driving some pipeline expansions in the region. The question is, will they be enough? Today, we provide an update on the utilization of existing export routes, as well as the prospects (or lack thereof) for takeaway expansions, starting with Westcoast Energy Pipeline.
In May 2019, the first-ever propane unit train from the Bakken to Mexico reached its destination, and since then, three more of these 100-car, single-commodity “bulk” trains have made the same trip. Facilitating these shipments by Twin Eagle Liquids Marketing is Marathon Petroleum Corp.’s (MPC) unit train-loading terminal in Fryburg, ND, which was initially set up to load crude oil but was recently expanded to handle propane too. And soon, the terminal in Torreón, Mexico, that has been receiving these unit trains will have a new loop track too, enabling producers and marketers to take full advantage of the bulk transport option. Today, we look at the economics and challenges of this relatively new propane export route.
Finally, after what seemed like a long period of crude oil pipeline takeaway constraints out of the Permian, significant new takeaway capacity is coming online this month. Just last week, Plains All American’s Cactus II pipeline from the Permian’s Midland Basin to the Corpus Christi area entered service. And on Monday, EPIC Midstream announced that it has begun interim crude service on its EPIC NGL Pipeline, which will move crude from the Permian’s Delaware and Midland basins — also to Corpus — until the company’s EPIC Crude Pipeline starts up in January 2020. With takeaway constraints alleviated, the focus on the crude-oil front now shifts to gathering system capacity, and it’s being added in spades. So much so that we’re writing two full Drill Down Reports (one on the Midland and one on the Delaware) to cover them in detail. Today, we discuss highlights from the first of our new Drill Down Reports, which focuses on crude oil gathering systems in the fast-growing Midland Basin.
Natural gas production in the U.S. Northeast has been increasing steadily through the 2010s and now averages about 32 Bcf/d — 12% higher than last August and nearly double where it stood five years ago — despite the lowest regional spot gas prices since early 2016. This run-up in production volumes wouldn’t have been possible without the new gas-processing and fractionation capacity that MPLX and other midstream companies have been bringing online at a steady pace in the “wet” or NGLs-rich parts of the Marcellus and Utica shales. Today, we begin a short blog series on recently completed and planned gas-processing and fractionation projects in the nation’s largest gas-producing region, and the gas production growth they will help enable.
In May 2019, Twin Eagle Liquids Marketing shipped a 100-car train filled with propane from North Dakota to Mexico, marking the first-ever single-commodity train — i.e. “unit train” — between the Bakken and the U.S.’s southern neighbor. As it turns out, it was also the first of what appears to be a regularly scheduled run to Mexico. Since May, three more unit trains have made the journey south from the Bakken’s first unit train terminal for propane. Rail shipments of propane to Mexico as part of mixed-goods trains aren’t new, but figuring out how to economically ship large quantities of propane via unit trains has long evaded NGL marketers and producers — that is, until now. What are the economics and other factors that finally made it possible, and what are the prospects and challenges ahead for unit-train exports to Mexico? Today, we look at how the first all-propane train to Mexico came to pass and what the outlook might be for these shipments to continue.
Well, it’s finally going to happen! Without major fanfare, Plains All American and Marathon Petroleum announced earlier this month that they have sanctioned the reversal of the 40-inch-diameter Capline crude oil pipeline, a move that will enable light crude to flow south on that pipe from the Memphis area to St. James, LA, starting late next year and light and heavy crude to do the same from Patoka, IL, by early 2022. Also, Plains said it has committed to expanding the existing Diamond Pipeline between Cushing, OK, and Memphis, and extending that eastbound crude pipe from Memphis to a new interconnection with Capline. Light-crude service on the expanded, extended Diamond will commence in late 2020. Today, we review the newly sanctioned projects and their significance to U.S. and Canadian producers, Louisiana refiners and Gulf Coast exporters.
TC Energy’s Columbia Gas and Columbia Gulf natural gas transmission systems’ recent expansions out of the Northeast — the Mountaineer Xpress and Gulf Xpress projects, both completed in March — are responsible for a large portion of the uptick in Marcellus/Utica production in the last few months and they’ve added an incremental 860 MMcf/d of capacity for Appalachian gas supplies moving south to the Gulf Coast. The two projects join a number of other expansions in recent years that have inextricably tied Marcellus/Utica supply markets to attractive demand markets along the Texas and Louisiana coasts. Where is that latest surge of southbound supply ending up? Today, we look at the downstream impacts of the completed projects, namely on Louisiana gas flows and LNG feedgas deliveries.
Of the many midstream companies with Permian crude oil gathering systems, a few also own bigger-diameter pipelines that shuttle crude to regional hubs as well as even larger takeaway pipelines to the Gulf Coast. Noble Midstream Partners is one of those that employs this “well-to-water” strategy, which enables midstreamers to participate in multiple links of the value chain; it can also give them better control over oil quality as crude makes its way from wells in West Texas and southeastern New Mexico to coastal refineries and export docks hundreds of miles away. Today, we conclude our series on Permian crude gathering with a look at the master limited partnership’s (MLP) mix of gathering, shuttle and long-haul pipelines.
It’s no secret by now that Permian oil markets have struggled over the last two years as nagging takeaway-pipeline constraints put a damper on production growth and, at times, hammered pricing in the basin. Like the Houston Astros’ opponents in the AL West, though, the days are numbered now for Permian oil market constraints, as two new large-diameter pipelines from West Texas to Corpus Christi will be in-service by the end of the month. One of those pipes, Plains All American’s Cactus II, is set to enter service this week. Today, we assess the potential implications of the latest Permian long-haul pipeline expansion, and introduce RBN’s new weekly publication, Crude Oil Permian!
For a few days in late July, the price differential between propane stored at Enterprise Products Partners’ salt caverns in Mont Belvieu, TX, and propane stored at facilities owned by others a few hundred yards away quickly widened to as much as 10 cents/gallon. That’s by far the biggest spread of its type we can recall, and while we can’t say for certain what caused the “Enterprise-vs.-others” propane differential to blow out, there’s a likely — and familiar — culprit: NGL infrastructure constraints. Something else this unusual pricing event confirmed is that, no matter where the NGL storage, fractionation or pipeline constraint may occur, it almost always has an outsized effect on the much smaller NGL storage and fractionation hub in Conway, KS. What’s with that? Today, we look at the recent, rapid slide in propane prices at Enterprise’s Mont Belvieu storage facility and discuss what it tells us.
The Niobrara production area in the Rockies is a complicated place to determine crude oil supply and demand balances. It’s at the crossroads of a number of supply areas, with volumes coming in from Canada and the Bakken, as well as locally from the Powder River and Denver-Julesburg basins. And in terms of destinations, there are well-established local markets, or you can send the molecules to Salt Lake City, or southeast to the Cushing, OK, hub and beyond. The Niobrara is one of the few growth areas we look at where there is substantial pipeline capacity for inflows and outflows, with the option to service multiple markets. Now, there are a couple of new pipeline projects ramping up in the Rockies, and given the region’s interconnectivity, it’s a good bet that the status quo in the Niobrara is in for some big changes. Today, we recap the new pipeline projects and then dive into what it could mean for the midstream balance in the Powder River and D-J.
It’s been nine months since Plains All American’s Sunrise II crude oil pipeline started service out of the Permian to the Wichita Falls, TX, crude hub. In that time, it has transformed the balance of supply versus downstream takeaway capacity at Wichita Falls and become a critical conduit of Permian crude to the Cushing and Gulf Coast markets. What’s more, Plains is planning to build the Red Oak Pipeline from Cushing through Wichita Falls to the Gulf Coast in 2021, which will further solidify Sunrise II as an important outlet for Permian oil for some time. With two other new long-haul Permian crude pipelines — EPIC and Cactus II — days away from starting interim service to the Gulf Coast, an analysis of Sunrise II’s impacts thus far provides some clues as to how future expansions will reshape the region. Today, we discuss how Plains’ Sunrise II project has affected crude oil flows from the Permian to Wichita Falls, and from there to Cushing and the Gulf Coast, as well as what its role will be when Red Oak comes online.