The U.S. midstream sector is clamoring to build takeaway pipelines for ballooning natural gas production volumes in the Permian Basin and get ahead of any developing takeaway capacity constraints. In the past year, a number of companies have floated plans for moving Permian gas supply east to the Gulf Coast, spurred on by two primary factors — expectations for accelerated supply growth in West Texas; and on the other end, emerging demand from a combination of LNG export facilities being developed on the Texas and Louisiana coasts, and the slew of export pipeline projects targeting growing industrial and gas-fired power generation demand in Mexico. These expansion projects are in a bit of a horse race, not just to beat the clock on potential transportation constraints, but also competing against an increasingly larger field to secure shipper commitments and make it to completion. Among the factors affecting their progress will be their in-service dates and their destination markets. Today, we provide an update on these competing pipeline projects, including the newest entrant, Tellurian’s Permian Global Access Pipeline.
Through the first half of the 2010s, U.S. production of field condensate — the ultra-light liquid hydrocarbon that bridges the gap between superlight crude oil and heavier natural gas liquids like natural gasoline — more than doubled, peaking at about 640 Mb/d in early 2015. As condensate production ramped up in the Eagle Ford and other plays, conde prices were discounted to move the product, markets were developed to absorb the barrels, and infrastructure was built to move the conde to those markets. Then, in a dramatic turnaround that continued into 2017, condensate production fell by more than one-third, the new markets — splitters and exports — were starved for product, and conde prices flipped from discounts to premiums. But the market is shifting yet again. Conde production is once more on the rise, with the Eagle Ford rebounding and production rising in the star of the show in crude oil markets: the Permian. Today, we discuss highlights from RBN’s new Drill Down Report on the condensate market roller-coaster.
U.S. exports of motor gasoline and diesel to Mexico are up 60% from two years ago, and the ongoing liberalization of Mexican energy markets is allowing players other than state-owned Pemex to become involved in motor fuel distribution and retailing there. But there’s a catch. The port, pipeline, rail and storage infrastructure currently in place to receive U.S.-sourced gasoline and diesel and transport it within Mexico is inefficient and stressed. Further, Pemex owns or controls most of these fuel logistics assets and has been slow to make them available to others. Today, we continue our series on efforts to facilitate the transportation of motor fuels to and within the U.S.’s southern neighbor.
To complete a single two-mile horizontal well in the Permian, producers or their contractors need to bring in several hundred thousand barrels of fresh, treated or brackish water — not an easy task in dry and dusty West Texas and southeastern New Mexico. And the water challenges don’t end there. Each barrel of crude oil that emerges from a Permian well can generate even more produced water that needs to be transported and safely disposed of. With Permian production of crude and associated natural gas rising fast, the sprawling region is experiencing a rapid build-out of water pipeline networks and other infrastructure aimed at keeping pace with hydrocarbon production growth. Today, we begin a blog series on water-related pipeline, storage and treatment infrastructure in the U.S.’s fastest-growing crude oil production area.
The Alberta natural gas market in Western Canada is in the midst of a seismic shift. Regional gas supply growth is accelerating. At the same time, export demand is eroding, but domestic demand — particularly from gas-fired power generation and oil-sands development — is on the rise. The incremental production along with the move toward intra-provincial demand has reconfigured flows and strained TransCanada’s infrastructure in the region. These factors resulted in extreme price volatility this past fall, a dynamic that’s likely to resurface in the New Year during low-demand times. Today, we continue our analysis of the Western Canadian gas market with a look at the changing transportation and flow dynamics in Alberta.
After being left for dead for more than five years, natural gas production in the greater Haynesville region has been surging upward — from about 5.7 Bcf/d this time last year to more than 7 Bcf/d today, an increase of 25% during 2017. Much of this growth has been coming from a new cast of characters, employing different technologies and different strategies than the first wave of Haynesville pioneers that established the play back in 2008, then abandoned it in 2012. But a couple of big challenges face the Haynesville. Today, we begin an examination of the Haynesville that will take us from production trends through producer strategies and finally into detailed calculations of production economics for the play.
Record high production with prices still rangebound! As of year-end 2017, Lower-48 natural gas production was at an all-time high — 77 Bcf/d and rising. NGL production from gas processing was at 3.7 MMb/d, the highest since EIA started recording the numbers. And U.S. crude oil output stood at 9.8 MMb/d, within spitting distance of the 10 MMb/d record set back in October/November 1970. All this with the price of WTI crude oil no more than 9% higher than it was this time last year, and natural gas prices 20% below year-end 2016. Yup, the dogs are out. Productivity is the culprit: longer laterals, super-intense completions, manufacturing-process pad drilling — the list goes on. Clearly the U.S. can’t absorb all this production growth, so the export market must be the answer. Or is it? Are we really that confident that world markets will make room for still more U.S. hydrocarbons? If not, what does it mean for prices? And ultimately, how will these prices impact U.S. producers? These are big questions, and with this much turmoil in the market it is impossible to know what will happen. Impossible? Nah. No mere market turmoil will dissuade RBN from sticking our collective necks out to peer into our crystal ball one more time to see what 2018 holds.
So here we are. Last workday of 2017. Which means it’s almost time again to post our annual Top 10 RBN Prognostications for the upcoming year. According to our long-standing tradition, we’ll do that on the first workday of the New Year — Tuesday, January 2, 2018. But today, it’s time to look back, too see how those 10 Prognostications we posted way back at the start of 2017 — The Year of the Rooster in the Chinese calendar — held up. Yes, we actually check our work! In today’s blog, we grade ourselves on our year-ago views of how 2017 would turn out for energy markets.
The new normal. Or at least the market’s perception of a new normal. That’s how we will remember 2017. Producers have come to terms with the possibility of crude prices in the $50-60/bbl range for a long time to come, and natural gas stuck around $3/MMBtu. But even in the face of this sober market outlook, crude oil production is near its all-time record. And Lower-48 natural gas blew past its historic maximum a few weeks back. Increasingly the biggest challenges facing the market are related to infrastructure –– where will all these hydrocarbons find a home. As we have over the past six years, RBN tracked these trends in 2017 as they played out, and now at the end of the year, it’s time to look back to see what topics generated the most interest from you, our readers. We monitor the hit rate for each of our blogs that go out to about 23,000 of our members each day, and the number of hits tells you a lot about what is going on in energy markets. So once again, we look into the rearview mirror to check out the top blogs of 2017, based on the number of rbnenergy.com website hits.
Western Canadian natural gas producers are increasingly facing oversupply conditions and price volatility. While competition and pushback from growing U.S. shale gas supply continues to be a factor, producers are now also contending with fresh problems closer to home — namely transportation constraints right where production is growing the most, in central Alberta. This fall, the Alberta market experienced extreme bottlenecks that left production stranded and sent area gas prices reeling. The ramp-up of winter heating demand has since helped ease the constraints, but the problems are likely to return in the spring when demand is lower, leaving producers exposed to the risk of severe price weakness again in 2018 and limited in their ability to grow supply. Today, we continue our look at what’s behind the local constraints and the implications for production growth and prices in Western Canada.
In recent weeks, more than 750 Mb/d of new crude oil pipeline capacity out of the Permian Basin has been announced, and more project plans are likely. For Permian producers and shippers, open seasons for takeaway projects now rival Christmas and New Year’s Eve as big winter events, and companies are evaluating these projects and their implications for the basin. This is a big deal. With Permian crude production rising quickly, the pace at which new takeaway capacity is added — and the markets that the new capacity accesses — are all-important factors. Today, we discuss the dynamics of how and when this next wave of pipeline projects will affect producers, midstreamers and ultimately crude prices.
This winter will be the last go-round for ISO New England’s Winter Reliability Program, under which the electric-grid operator in the natural gas pipeline-challenged region provides financial incentives to dual-fuel power plants if they stockpile fuel oil or LNG as a backup fuel. This coming spring, a long-planned “pay-for-performance” regime will go into effect, and gas-fired generators that can’t meet their commitments to provide power during high-demand periods — such as the polar vortex cold snaps that hit the Northeast in early 2014 — will pay potentially significant penalties. Today, we discuss the pitfalls that the pipeline capacity-challenged region may encounter as its power sector becomes increasingly gas-dependent.
EnLink Midstream Partners LP, seeking to offset declining natural gas production in the Barnett Shale — where the master limited partnership (MLP) has extensive midstream holdings — has been implementing a strategic plan focused on acquisitions and expansions in the burgeoning STACK play in central Oklahoma and in the Permian’s Midland and Delaware basins in West Texas. The level of investment the plan requires has prevented increases in the MLP’s distributions to unit holders for nine consecutive quarters, which in turn has left EnLink’s share price languishing at about half of its 2014 high. The MLP has reported promising signs of growth in Oklahoma and the Permian as well as increased utilization of its southern Louisiana infrastructure, which it says could lead to a higher distribution to unit holders in 2018. Today, we preview our Spotlight Report on EnLink, which provides a detailed analysis of the company’s business segments to determine if its strategic plan will indeed generate real growth over the next four years.
Western Canadian natural gas producers have long battled unrelenting competition from growing shale gas supply in the U.S. But recent price action at AECO — Canada’s benchmark natural gas hub in Alberta — suggests market conditions there have gone from bad to worse. AECO prices in recent months have fallen to the lowest levels in more than a decade, even dropping below zero at one point in intraday trading this fall. Fundamentals are increasingly bearish, given that Canadian gas production has rebounded to the highest level in close to 10 years, storage there is near to five-year highs and exports are facing further cutbacks as U.S. gas supply is itself at record highs. In addition, producers are contending with a number of transportation issues closer to home. Today, we begin a look at the factors affecting the Western Canadian gas market.
Falling production of motor gasoline, diesel and other refined products at Mexico’s aging refineries has created a south-of-the-border supply void that U.S. refiners and refined-products marketers and shippers are all too eager to fill. At the same time, the ongoing liberalization of Mexican energy markets is finally allowing players other than state-owned Petróleos Mexicános (Pemex) to become involved in motor-fuel distribution and retailing. The results of all this? U.S. exports of gasoline and diesel to Mexico are up 60% from two years ago, and U.S. companies are scrambling to develop or acquire the infrastructure needed to deliver refined products to Mexican consumers. Today, we begin a new series on the increasing role of U.S. companies in supplying, distributing and retailing motor fuels in Mexico, and on the new transportation and terminalling infrastructure being built to support that growth.