The Shale Revolution has caused big changes in U.S. crude oil production, in domestic flows of crude via pipelines, ships and rail tankcars, and in crude import volumes. Flow changes in particular have negatively affected the Strategic Petroleum Reserve’s ability to accomplish its two primary goals: protecting U.S. refineries from the worst effects of a major crude oil supply interruption, and—when called upon by the International Energy Agency—quickly injecting large volumes of crude into global markets. A fix now in the works would add Gulf Coast marine terminals dedicated specifically to moving SPR-stockpiled crude to those who need it, both within the U.S. and overseas. Today we conclude a two-part blog series on challenges and coming changes at the SPR.
More than a dozen crude oil pipelines can deliver up to 3.4 million barrels/day (MMb/d) to the greater Houston area, with another 550 Mb/d of capacity planned, and as domestic production starts to grow again, a new round of projects is under way to build-out the region’s distribution pipelines, storage and marine-dock infrastructure. The developers of these Houston-area projects include a range of midstream players: from large, diversified midstreamers that own the long-distance pipelines flowing into the region to smaller players planning their first Houston projects. Today we conclude a two-part blog series on the latest round of projects and on the increasingly intense competition for barrels.
As U.S. crude production ramps back up and larger volumes flow to the Gulf Coast, competition is building among midstream companies for control over the final miles from pipeline to refinery or marine dock. Nowhere is this more evident than the Houston area, where more than a dozen pipelines can deliver as much as 4 million barrels/day to the region’s 10 refineries as well as to export docks. Owners of the long-distance incoming pipelines—seeking to secure terminal, storage and dock fees—are making significant midstream investment in Houston, but smaller players are also developing assets. Today we begin a two-part series describing the build-out and how competitive the market has become.
Fundamental changes in U.S. crude oil production, crude transportation patterns, refinery sourcing of oil, import volumes and other factors have undermined the ability of the Strategic Petroleum Reserve to mitigate the domestic impact of a world energy crisis. Worse yet, the Department of Energy’s planned fix for the SPR will take at least several years—assuming it’s allowed to proceed according to plan. Today we consider current shortfalls in the SPR’s crude-delivery network, the potential effect on U.S. refineries in the event of an emergency, and the DOE’s plan to fix things.
A major component of the formula used to set the price of Maya—Mexico’s flagship heavy crude, and a key staple in the diet of many U.S. Gulf Coast refiners—was changed earlier this month, raising new questions about this important price benchmark for nearly all heavy sour crude oil traded along the U.S. Gulf, and points beyond. The change came as Maya production volumes continue to fall, and as Maya is facing increasing competition from Western Canadian Select (diluted bitumen) from Western Canada. Today we conclude a two-part series on Maya crude oil, the new price formula and its potential effects.
The agreement by OPEC and several non-OPEC members to cut crude oil production by a total of 1.8 million barrels a day (MMb/d), which caused a rise in crude prices, kicked in on January 1. Now, more than three weeks in, many in the market remain skeptical that the deal will hold, and are on the lookout for the slightest hint that parties to the agreement may be—for lack of a kinder word—cheating. In today’s blog, “Won’t Get Fooled Again—Monitoring Compliance With The OPEC/NOPEC Deal To Cut Production,” we recap the agreement’s terms, examine how participating producers might try to skirt the rules, and discuss ways to check that everyone is acting on the up and up.
Plains All American Pipeline announced on Tuesday that it has agreed to acquire Alpha Crude Connector (ACC), an extensive, FERC-regulated crude oil gathering system in the Permian’s super-hot Delaware Basin, for $1.215 billion. At first glance that might seem to be a lofty price, but the development of the ACC system appears to be a classic case of right-place/right-time because it addresses a fast-growing need for pipeline capacity across an under-served area. And, with its multiple connections, ACC is an attractive source of crude to fill currently underutilized downstream pipelines headed to Midland, the Gulf Coast to Cushing. Today we review Plains’ newly announced agreement to acquire the ACC pipeline system in southeastern New Mexico and West Texas.
While oil prices have risen in recent months, they are a far cry from the $100/bbl prices of two and half years ago, and there is certainly no guarantee they won’t fall back below $50. In other words, the survival of exploration and production companies continues to depend on razor-thin margins, and E&Ps must continue to pay very close attention to their capital and operating costs. Lease operating expenses—the costs incurred by an operator to keep production flowing after the initial cost of drilling and completing a well have been incurred—are a go-to cost component in assessing the financial health of E&Ps. But there’s a lot more to LOEs than meets the eye, and understanding them in detail is as important now as ever. Today we continue our series on a little-explored but important factor in assessing oil and gas production costs.
The capacity of a pipeline built to transport crude oil or refined products is often thought to be tied only to the pipe’s diameter and pumps, as well as the viscosity of the hydrocarbon flowing through it. Increasingly, though, midstream companies are injecting flow improvers—special, long-chain polymers known as “drag reducing agents” —into their pipelines to reduce turbulence, thereby increasing the pipes’ capacity, trimming pumping costs or a combination of the two. The role of these agents has evolved to the point that they aren’t simply being considered to boost existing pipelines, their planned use is being factored into the design of new pipes from the start. Today we begin a series on DRAs and their still-growing influence on the midstream sector.
Maya, Mexico’s flagship heavy crude, has been a key staple in the diet of U.S. Gulf Coast refiners for a long time, and it has faithfully served as a price benchmark for nearly all heavy crude oil traded along the U.S. Gulf, and points beyond. Maya’s price, relative to lighter benchmark grades such as Louisiana Light Sweet (LLS) or Brent, provides ready insight into the profitability of heavy oil (coking) refiners. But production of Maya peaked in 2004 and has declined considerably since then, raising questions about its continuing efficacy as a price benchmark. Now it’s come to light that a component of the Maya price formula was changed effective January 1, 2017. Although the change—related to the formula’s fuel oil price component—might be viewed as a relatively minor tweak, it raises new questions about this important heavy oil price benchmark. Today we begin a two-part series on Maya crude, the new price formula and its potential effects.
It hasn’t been widely reported, but during cold snaps in late fall and early winter, a number of crude oil producers in the Permian Basin have faced a “perfect storm” of events that made it challenging to meet crude pipelines’ vapor pressure standards. At first glance, this may seem like a problem for “the technical folks” to deal with, but in fact the issue has been affecting the ability to move crude to market, and the price of oil at Midland, TX versus the crude hub at Cushing, OK. It has even forced Permian producers to “shut in” some crude production—at least for a time—along several major pipelines in the region because they’ve been unable to adequately prepare their crude for piping or trucking. Today we examine an under-the-radar problem that’s been vexing producers in the U.S.’s leading crude oil play, and affecting oil prices and markets.
In 2015, Sooners held on tight as Oklahoma was rocked by 890 earthquakes with a magnitude of 3 or higher—up sharply from only 43 earthquakes in 2010 and an average of less than two earthquakes per year in the previous quarter-century. Oklahomans have experienced hundreds of earthquakes this year too, including a record-breaking 5.8 event on September 3 and, on November 6, a 5.0 quake very near Cushing, OK, which serves as the delivery point for the CME/NYMEX Light Sweet Crude contract and which has earned the nickname “Pipeline Crossroads of the World”. Today we look at the latest quake near Cushing and other recent pipeline disruptions to assess the resilience of critical crude-delivery systems.
It’s been a tough few years for Canadian oil producers. As they ramped up production in the oil sands, Canadian E&Ps faced pipeline takeaway constraints that drove down the price of Western Canadian Select versus Gulf Coast crudes. The Keystone XL pipeline would have largely solved things, but when that project was killed by Canada’s U.S. friends and neighbors, oil sands producers had to settle for a series of smaller, more incremental projects that provided only a partial fix. The devastating Alberta fires of May 2016 reduced production and pretty much eliminated constraints for much of this year. But volumes have recovered, and if oil sands production is to continue growing, more pipelines and new customers will be needed. Today we consider Canada’s long-running effort to ensure there’s enough capacity to move its crude to market, two major projects that just won the backing of the Canadian government, and what may be next.
With today’s low crude oil and natural gas prices, the survival of exploration and production companies depends on razor-thin margins. Lease operating expenses––the costs incurred by an operator to keep production flowing after the initial cost of drilling and completing a well have been incurred––are a go-to variable in assessing the financial health of E&Ps. But it’s not enough for investors and analysts to pull LOE line items from Securities and Exchange Commission filings to find the lowest cost producers, plays, or basins. More than ever we need to understand—really, truly, deeply—what LOEs are, why they matter, how they change with commodity prices, production volumes, and other factors, and how we should use them when comparing players and plays. Today we begin a series on a little-explored but important factor in assessing oil and gas production costs.
Forecasting in U.S. energy markets characterized by hair-trigger price volatility, ever-improving well drilling and completion productivity, and the unraveling of old norms is a bit of a high-wire act. But just as big-tent tightrope walkers get better with practice, energy prognosticators can gain from experience––and from taking a look back at previous forecasts to see what they got right, what they may have missed, and what’s changed in the interim. Today we continue our review of a recent presentation at RBN’s School of Energy earlier this month on forecasting lessons learned.