There has been a lot of acrimony and polarization among the natural gas industry, the environmental community, various consumer advocates, industrial energy users, organized power markets and renewables developers in recent years. However, the ongoing government efforts to prop up the power sector’s coal-fired and nuclear generators have succeeded in uniting all those disparate interests into a single voice saying a single word: No! Today, we discuss the history of the administration’s planned support of coal and nuclear, the unusually unified reaction to it from groups that are more often at odds with each other, and some underlying assumptions about natural gas that aren’t — well — how the gas industry says it works.
Daily energy Posts
Crude oil pipelines out of Cushing are filling up. With U.S. crude production approaching the 11 MMb/d mark, more and more production from the Rockies, Midcontinent and Permian is funneling into the Cushing, OK, trading hub. It’s getting increasingly difficult to get all of that volume to the major demand center at the Gulf Coast. The two major pipelines out of Cushing — Seaway and Marketlink — are near full capacity and differentials are responding as West Texas Intermediate (WTI) at Cushing is now trading at a $7.60/bbl discount to Magellan East Houston (MEH) at the Gulf. Today, we look at some of the major factors affecting the WTI-MEH spread, space on major pipelines between the two points, and potential implications going forward.
The Permian Basin is awash in light, sweet crude oil that’s cheap to produce and easy to process. It’s so awash, in fact, that supplies are overwhelming takeaway pipeline capacity. The resulting bottleneck in West Texas has cratered prices in Midland, where West Texas Intermediate (WTI) — the region’s light, sweet benchmark — has blown out price-wise against the same grade in other locations, including Houston, with its crude-export docks. Less well known, but influential beyond its geography, is Midland West Texas Sour, or WTS. WTS is suffering from the same wide differentials as WTI at Midland, and those yawning spreads are dragging down the price of Maya, Pemex’s flagship heavy, sour crude. Today, we discuss some surprising ripple effects of takeaway constraints out of the Permian.
Western Canada is blessed with extraordinary hydrocarbon resources and in recent years has been ramping up production in the Alberta oil sands and in the Duvernay and Montney shale plays. The U.S. is pretty much Canada’s only crude oil and natural gas customer, though, and there are limits to how much Canada can export to its southern neighbor — especially in the Shale Era, with the U.S. producing more oil and gas than ever and meeting an increasing share of its own needs. So Canadian producers, midstream companies and others have been working to gain access to new, overseas markets. It has not gone well. Pipeline projects to transport oil and gas to the British Columbia coast have been set back time and again, as have plans for crude and LNG export terminals. At last, there may be some good news. The Canadian government has stepped in to help push through a critically important oil pipeline to the coast, and BC’s leading LNG project just signed on a major new investor/customer. Today, we consider recent moves that could finally allow large volumes of Western Canadian oil and gas to be shipped to Asia.
Crude oil pipelines out of the Permian are filled to capacity and the differentials between crude in Midland and in Cushing and Gulf Coast destination markets are wide and likely to widen. That has spurred Permian producers and shippers to consider every possible option for moving incremental barrels out of the play, including two old short-term standbys: tanker trucks and crude-by-rail. Cost isn’t a major issue — the price spread and the Permian’s low break-evens will probably justify the higher expenses associated with trucking and railing crude. But that doesn’t mean that badly needed truck and rail capacity can appear with a poof as if by magic. No, even wads of cash may not be enough to quickly round up the hundreds — thousands? — of trucks and drivers that would be required to make a significant dent in the Permian’s takeaway shortfall. And developing brand new crude-by-rail terminals can take a year or more — too much time to address the play’s more immediate needs. Today, we continue our look at the frenzied efforts under way to move more Permian crude to market.
The sharp increase in U.S. crude oil exports over the past couple of years is tied primarily to Texas ports — mostly Corpus Christi and the Houston Ship Channel. Louisiana, a distant second in the crude-exports race, has a long list of positive attributes, including the Louisiana Offshore Oil Port (LOOP) — the only U.S. port currently capable of fully loading the Very Large Crude Carriers that many international shippers favor. It also has mammoth crude storage, blending and distribution hubs at Clovelly (near the coast, connected to LOOP) and St. James (up the Mississippi). In addition, St. James is the trading center for benchmark Light Louisiana Sweet, a desirable blend for refiners. The catch is that almost all of the existing pipelines at Clovelly flow inland — away from LOOP — many of them north to St. James. That means infrastructure development is needed to reverse these flows southbound from St. James before LOOP can really take off as an export center. Today, we continue a blog series on Louisiana's changing focus toward the crude export market and the future of regional benchmark LLS.
Necessity is the mother of invention, and the desperate need to transport increasing volumes of crude oil out of the severely pipeline-constrained Permian is spurring midstream companies and logistic folks in the play to be as creative as humanly possible. With the price spread between the Permian wells and the Gulf Coast exceeding $15/bbl in recent days — and possibly headed for $20/bbl or more soon — there's a huge financial incentive to quickly provide more takeaway capacity, either on existing pipelines or by truck or rail. Are more trucks and drivers available? Is there an idle refined-products pipe that could be put back into service? Could drag-reducing agents be added to an existing crude pipeline to boost its throughput? How quickly could that mothballed crude-by-rail terminal be restarted? Today, we discuss frenzied efforts in the Permian to add incremental crude takeaway capacity of any sort — and pronto.
U.S. crude oil exports have averaged a staggering 1.6 MMb/d so far in 2018, up from 1.1 MMb/d in 2017, and the vast majority of these export volumes — 85% in 2017 — have been shipped out of Texas ports, with Louisiana a distant runner-up. The Pelican State has a number of positive attributes for crude exporting, though, including the Louisiana Offshore Oil Port (LOOP), the only port in the Lower 48 that can fully load the 2-MMbbl Very Large Crude Carriers (VLCCs) that many international shippers favor. It also has mammoth crude storage, blending and distribution hubs at Clovelly (near the coast and connected to LOOP) and St. James (up the Mississippi). In addition, St. James is the trading center for benchmark Light Louisiana Sweet (LLS), a desirable blend for refiners. The catch is that almost all of the existing pipelines at Clovelly flow inland — away from LOOP — many of them north to St. James. That means infrastructure development is needed to reverse these flows southbound from St. James before LOOP can really take off as an export center. Today, we consider Louisiana's changing focus toward the crude export market and the future of regional benchmark LLS.
Even with crude oil prices down $1.67/bbl yesterday, the wide differential between Permian prices and those in destination markets held up, with WTI Midland trading at $15.60/bbl below the same quality of oil on the Gulf Coast. This has become a red-hot topic for all Permian-watchers. For example, in first quarter earnings calls, a number of producers not only reported their Permian well productivity and drilling plans, they also reviewed how much firm pipeline space they have signed up for in the Permian and how they plan (or hope) to avoid negative financial consequences from the differential blowout. With so much demand for new pipeline space, shouldn’t it be easy to get a bunch of shippers signed up for long-term commitments to fund a new project? Today, we’ll look at what it takes for commitments to pay off massive pipeline projects, the hurdles midstream companies go through to achieve it, and the possibility of new pipeline projects getting added to the development schedule.
For a month now, the number of active drilling rigs in the U.S. has topped 1,000, the first time that’s happened since the spring of 2015, when the rig count was in the midst of a frightening tailspin — it fell from more than 1,900 in November 2014 to only 400 in May 2016. What a long, strange trip it’s been, not just for the rig-count total but for gains producers have seen in drilling productivity and in crude oil and natural gas production per well. Exploration and production companies are doing far more with less, trimming costs and increasing returns in the Permian, the Marcellus/Utica and other key production basins to levels few would have thought possible a few years ago. Today, we review the key changes we’ve seen in drilling productivity, and what they mean for U.S. E&Ps and midstream companies and the rig count going forward.
Seems like just about everything to do with energy markets is up these days. Crude oil prices are back to the levels of late 2014. Crude production hit a 10.6 MMb/d record volume last week, while lower-48 natural gas has been bouncing around an 80 Bcf/d record level. Exports of crude, gas and NGLs are at all-time highs. But all those hydrocarbon molecules must find their way from the wellhead to market, and in several high-growth regions, that is becoming increasingly problematic, as midstream infrastructure struggles to keep up. In our recent School of Energy, we examined these developments, considering their impact on production trends, domestic demand and the outlook for growth in export volumes. Did you miss it? Not a problem. We taped the whole conference, and School of Energy Online is now available in 12 hours of streaming video, along with all the Excel models, slides, and graphics that we use to tie energy markets together. Today, in this unabashed advertorial, we review some of the highlights of the conference.
Large-scale and well-funded producers in the Permian have built dedicated gathering systems and signed up for pipeline-takeaway options to keep their barrels moving to markets at the Gulf Coast and Cushing. For the most part, smaller producers don’t have the same options, for a variety of reasons. More and more, barrels from outside the core areas of the Permian are competing for the last bits of pipeline space and producers are being forced to rely more heavily on Permian trucking companies to help keep their crude flowing. Truckers are being asked to make less desirable, less economical and longer hauls, and are passing those costs back to the producer. With pipeline takeaway capacity maxed out, trucking capacity is being pushed to the limit too, with several potential upstream impacts. Today, we look at trucking options for smaller producers in second-tier production areas, the impact of boom-bust cycles on trucking companies and what tight trucking capacity means for the basin as a whole.
If you’ve been watching market prices over the last week, you’ll have noticed that Permian differentials have tightened a bit. With the capacity of the new Midland-to-Sealy pipeline ratcheting up and the 146-Mb/d Borger refinery near Amarillo coming back online, there has been a brief respite for crude oil prices in West Texas. But soon, continued growth in crude production will again max out pipeline capacity out of the Permian until one of the major new pipes starts operating in 2019. In the interim, producers and traders without firm pipeline space will be taking deep price discounts, all the while attempting to maintain their revenue streams by sticking to their development plans or, at the very least, avoiding the specter of well shut-ins. Today, we dive into the current state of affairs regarding Permian pipeline allocations, the impact on producer logistics, and what it all means for price differentials.
As Permian crude differentials continue to widen, trading at a $8.45/bbl discount to Magellan East Houston this week, a lot of people are pointing fingers at midstream companies for not completing new takeaway pipeline projects quickly enough. But even in the oil patch, it takes two to tango and producers can also share some of the blame. Historically, the focus in the Permian has been on larger producers, with their sprawling acreage positions and their focus on creating long-term competitive advantages through efficient drilling programs. Many of the smaller, private equity-backed producers adopted more short-term strategies. Their game has been to prove undervalued acreage and then flip those assets to more substantial players. But these strategies are beginning to change. Today, we continue our series on Permian differentials with a look at how the recent ramp-up in the development of second- and third-tier production areas is affecting the region’s crude oil output, pipeline takeaway constraints and price differentials.
The Permian is a beehive of activity on the burgeoning water midstream front — the pipelines, saltwater disposal wells and other assets being built to facilitate the delivery of water to new wells for hydraulic fracturing and the transport of “produced water” from the lease to disposal or treatment sites. But the Bakken — arguably the birthplace of the water midstream sector nearly a decade ago — is no slouch, and a model of sorts for the infrastructure build-out now under way in the Permian. The volume of water needed for Bakken well completions is up sharply in recent years; more important still, the region is generating more than 1 MMb/d of produced water, and producers and water midstreamers alike are building new takeaway pipelines and drilling new SWDs to more efficiently deal with it. Today, we discuss water- and produced-water-related infrastructure in one of the U.S.’s largest production regions.
Price differentials in the Permian Basin are widening at a rapid pace. The discount for Midland crude to West Texas Intermediate (WTI) at Cushing has widened by over $4/bbl since the beginning of March and the discount to Magellan East Houston (MEH) crude was over $7/bbl yesterday. Permian production is increasing at a breakneck pace as new players are entering the scene. Private equity-backed exploration and production companies (E&Ps) are no longer just acquiring and flipping acreage, as they are being forced to prove their assets are profitable and can generate a return on investment. The combination of large drilling plans from the majors and new production from these smaller operators — with no new pipeline takeaway capacity in sight — has sent Permian crude pricing into a tailspin. Today, we begin a new series on the recent slide in Permian prices, how new producer strategies are contributing to it, and what it means for pipeline space, trucking and midstream infrastructure.