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.
Imported liquefied natural gas from the U.S. is helping Mexico address major challenges facing its gas sector. For one, LNG shipments from the Sabine Pass export terminal in Louisiana to Mexico’s three LNG import facilities have been filling a gas-supply gap created by delays in the country’s build-out of new pipelines to receive gas from the Permian, the Eagle Ford and other U.S. sources. Imported LNG also is playing — and will continue to play — a key role in balancing daily gas needs within Mexico, which has virtually no gas storage capacity but is planning to develop some. Today, we consider recent developments in gas pipeline capacity, gas supply, LNG imports and gas storage south of the border.
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.
This past winter’s gas price spikes shined a bright light on the changing dynamics driving Eastern U.S. natural gas markets, especially the growth in gas-fired generation that is contributing to more frequent — and more severe — spikes in gas prices in the region on very cold days. There are other changes too. For one, gas is increasingly flowing from the Northeast to the Southeast as prodigious Marcellus/Utica production growth is pulled into higher-priced, higher-demand growth markets. In today’s blog, we conclude our series on ever-morphing gas markets on the U.S.’s “Right Coast” by examining how gas pipeline flows back East have changed on days besides the winter peaks, how much demand could be unlocked by forthcoming pipeline projects, and what that new demand will mean for flow and price patterns.
Increasing production of NGL-packed associated gas in the adjoining SCOOP, STACK and Merge plays in central Oklahoma and rising interest in the Arkoma Woodford play in the southeastern part of the state are spurring a bevy of natural gas-related infrastructure projects. New gas-gathering systems are being developed, new gas processing capacity has come online, and at least another 1.1 Bcf/d of processing capacity is under construction or will be soon. To help bring all the resulting gas and NGLs to market, new takeaway pipeline capacity out of Oklahoma is being planned too. Today, we continue our review of ongoing efforts to add gas-processing and takeaway capacity in the hottest parts of the Sooner State.
Over the next two years, increasing natural gas demand for Gulf Coast LNG exports will reverse flow patterns across the Southeast/Gulf region, resulting in supply/demand imbalances, pipeline capacity constraints and regional price aberrations. The most significant of these developments will occur in the backyard of Henry Hub, Louisiana, where growing supplies in the north of the state will compete for pipeline capacity to get down to coastal export facilities. More Louisiana north-to-south pipeline capacity is needed. The only questions are where the capacity is needed most, and who will build it? Today, we continue our review of Louisiana gas supply, demand and transportation capacity.
For a couple of years now, Buckeye Partners has been working to advance a controversial plan to reverse the western half of its Laurel refined-products pipeline in Pennsylvania to allow motor gasoline, diesel and jet fuel to flow east from Midwest refineries into the central part of the Keystone State. Some East Coast refineries that have relied on Laurel for 60 years to pipe their refined products as far west as Pittsburgh have been fighting Buckeye’s plan tooth and nail, arguing that it would hurt their businesses and hurt competition in western Pennsylvania gas and diesel markets — and refined-product retailers in the Pittsburgh area agree. Now, after a state administrative law judge’s recommendation that Pennsylvania regulators reject Buckeye’s plan, Buckeye has proposed an alternative: making the western half of the Laurel Pipeline bi-directional, which would allow both eastbound and westbound flows. Today, we consider the latest plan for an important refined-products pipe and how it may affect Mid-Atlantic and Midwest refineries.
Four years ago this month, crude oil was selling for north of $100/bbl and natural gas prices were more than 50% higher than they are now. But while hydrocarbon prices sagged later in 2014 — and through 2015 and early 2016 — the declines didn’t deal a crippling blow to U.S. exploration and production companies. Instead, most of the upstream industry weathered the crisis remarkably well. Amidst that striking recovery, the 10 gas-focused E&Ps we’ve been tracking have engineered the strongest return to profitability. After $40 billion in pre-tax losses in 2015-16, they reported a collective $5.2 billion in pre-tax operating income in 2017, with all 10 producers in the black, as well as a 150% increase in cash flow over 2016, to $11.7 billion. However, gas prices have languished below $3.00/MMBtu since early February 2018 — their lowest level since mid-2016 — which means that the gas producers don’t have the tailwind that higher oil prices have been providing to their oil-focused and diversified competitors. Today, we conclude our blog series on E&Ps’ 2018 profitability outlook and cash flow allocation with a look at companies that focus on natural gas production.
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.
Could it get any worse? Possibly, but the last time we saw petchem margins this bad was in the depths of the 2008-09 economic meltdown, and back then the atrocious margin levels resulted in drastic plant curtailments and in some cases permanent shutdowns. But this time around the petchem industry is in the process of bringing on even more capacity! Is the current situation a fluke, or a harbinger of things to come? In today’s blog we examine recent trends in steam cracker margins, by far the largest demand sector for natural gas liquids (NGLs) and consider what these developments may mean for NGL markets in general, and ethane in particular.
The Louisiana natural gas market has undergone major changes in recent years, from the decline of its offshore and onshore production volumes to the emergence of new export demand from LNG terminals. But there are many more changes on the way. The industry has plans to add another 5.0 Bcf/d of liquefaction and export capacity in the Bayou State between now and 2023. At the same time, there are a slew of pipeline projects designed to carry Marcellus/Utica gas supply to the Perryville Hub in northeastern Louisiana. And, Louisiana’s own gas supply is soaring from the Haynesville Shale. The timing of these emerging factors will drive supply-demand economics and volatility in the region — including at the national pricing benchmark Henry Hub — over the next five years. Today, we take a closer look at the timing and extent of the supply and demand factors affecting the Louisiana gas market.
Defying predictions of widespread bankruptcies and credit defaults, the U.S. exploration and production companies (E&Ps) we track returned to profitability in 2017 through a strategic transformation that featured the “high-grading” of portfolios, impressive capital discipline and an intense focus on operational efficiencies. However, the road to recovery has been longer and more challenging for some companies, particularly a few of the E&Ps in our Diversified Peer Group, whose output and reserves are more balanced between oil and gas. Their portfolio realignments have been the biggest among our three peer groups — collectively they have shed $36 billion in assets and 3.6 billion barrels of oil equivalent (boe) in proved reserves over the last three years. Today, we continue our review of how rebounding oil prices are affecting E&P cash flow, this time focusing on producers with a rough balance of oil and natural gas assets.
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.
Everyone in the North American gas industry knows that a big wave of U.S. LNG exports is coming. Although Cheniere Energy’s Sabine Pass terminal in southwestern Louisiana started shipping out LNG in 2016, exports really started having a major impact in 2017 — increasing demand for U.S.-produced gas, providing an outlet for Marcellus and Utica supplies, and affecting physical flows at the Henry Hub and in south Louisiana more generally. But with the first four liquefaction trains at Sabine Pass all but fully ramped up, attention in recent months has been turning to the next facility being commissioned: Dominion’s Cove Point terminal on Chesapeake Bay in Maryland, which exported its first cargo in early March. But tracking gas pipeline flows into the Cove Point plant has not been easy, and in today’s blog, we consider the various possibilities and discuss our view of how best to monitor the amount of LNG feedgas going into Cove Point.
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.