After enduring 2015-16 it is about time for some good news, right? And that’s just what 2017 is shaping up to be—a relatively good news year for energy markets. But don’t go crazy with this. The key word in that sentence is “relatively’” —which means better than 2015-16, but if you are looking for that other “R” word (“recovery”) you won’t see it here. Crude prices will be up some, but nothing like the first few years of this decade. Natural gas and NGL prices will be stronger too. But both may have to wait still another year before seeing a real upswing in 2018. Nevertheless, 2017 is looking good for most of the energy market. Not for everyone, mind you. Many will struggle because their assets are in the wrong places, they are at the wrong end of the food chain, or they were simply unprepared for this new market reality. How will you know the difference between the winners and losers? Well of course, by looking deeply into the RBN crystal ball to see what 2017—Year of the Rooster—has in store for us. Cock-a-doodle-do!
|Event||Speaker||Event Date||Event Location|
|E3 Consulting and Credit Agricole Annual Winter Energy Conference at Beaver Creek||Rusty Braziel||01/31/2017||Park Hyatt in Beaver Creek, Colorado|
|NCAC Council||Rusty Braziel||02/17/2017||Washington DC|
|SMU Cox Maguire Energy Institute||Rusty Braziel||04/18/2017||SMU Campus|
Posts from Rusty Braziel
A long-standing tradition at RBN is our annual Top 10 RBN Energy Prognostications blog, where we lay out the most important developments we see for the year ahead. Unlike so many forecasters, we also look back to see how we did with our forecasts the previous year. That’s right! We actually check our work. Usually we can get that all into a single blog. But a lot will be coming at us in 2017, so this time around we are splitting our Prognostications into two pieces. Tomorrow’s blog will look into the RBN crystal ball one more time to see what 2017 has in store for energy markets. But today we look back. Back to what we posted on January 3, 2016. Recall back in those days that crude production had not started to decline materially, West Texas Intermediate (WTI; the U.S. light-crude benchmark) was at $37/bbl, natural gas was $2.33/MMbtu in the middle of winter, Congress had just OK’ed crude exports, and weak exploration and production companies (E&Ps) were dropping like flies. Now let’s look at RBN’s Prognostications for 2016.
From the depths of despair in the first quarter when WTI crude collapsed to $26.21/bbl on February 11 and Henry Hub gas crashed to $1.64/MMbtu on March 3, we are back, sort of. Growth in the rig count has been nothing short of spectacular, up 249 or 62% from the low point in late May. Crude oil, natural gas and NGL prices have all more than doubled since the lows of Q1. Yes, 2016 has been quite a roller coaster ride for energy markets. Here in the RBN blogosphere, we’ve documented this saga every step of the way. Now at the end of the year, as we’ve done for the past five years, it is time to look back. Back over the past 12 months––to see which blogs have generated the most interest from you, our readers. We track the hit rate for each of our daily blogs, 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 at the top blogs of 2016 based on numbers of website hits in “The 2016 Hydrocarbon Top 10 RBN Blogs”.
Some 3.2 Bcf/d of new LNG export capacity will be coming online along Texas’s Gulf Coast over the next two and a half years, and 8 Bcf/d of new natural gas pipeline capacity is under development to transport vast quantities of gas through Texas to the Mexican border. But while gas-export opportunities abound, Texas gas production is down, mostly due to a big fall-off in Eagle Ford output, so exporters will need to pull gas from as far away as the Marcellus/Utica to meet their fast-growing requirements. That will flip Texas from a net producing region to a net demand region once when you factor in exports that will flow through the state. This profound shift will put extraordinary pressure on Texas’s unusually complex network of interstate and intrastate pipeline systems, which will need to be reworked and expanded to deal with the new gas-flow patterns. It also will have a significant effect on regional gas pricing––putting a premium on Texas prices. These issues and more are addressed in RBN’s latest Drill Down Report, highlights of which we discuss in today’s blog.
The natural gas pipeline grid in Texas is undergoing a historic transformation as interstate pipelines designed to move gas north and east from the Gulf Coast region are being reversed, enabling Marcellus/Utica gas to flow to LNG export markets in Louisiana and Texas, and via Texas for pipeline export to Mexico. With a history of oil and gas production going back more than 100 years, no region in the world has a more convoluted network of pipelines than Texas. The state can be viewed as a dense “spaghetti bowl” of interconnected interstate and intrastate systems that defies traditional gas market analysis, in part because intrastate pipelines do not post receipts and deliveries on their systems as required by federally regulated interstate pipelines. However, it is possible to assess the dynamics of regional flows and capacities by examining the morass of flow data available from interstate pipelines in the region that connect to the intrastates. To help make sense of this data, RBN has developed a simplified model that facilitates an understanding of Texas natural gas flows and capacities that we call (unsurprisingly since it’s RBN) the Fretboard Model because the region’s interstate pipelines and capacity constraints look (with just a bit of artistic license) very much like a guitar fretboard. In today’s blog, we introduce this model.
For the past month, WTI crude oil prices have averaged $49/bbl, trading within a relatively narrow $7/bbl range. Two years ago, this price would have been devastating for producers, but not so in late 2016. The crude directed rig count is up by 127 since May, +11 just last week. U.S. crude production is down about 1.2 MMb/d since April 2015, but over the past three months has stabilized at 8.5 MMb/d. On the gas side, since the second quarter of 2016 a combination of lower natural gas production and higher demand (from the power, industrial and export sectors) has worked off a big inventory surplus. Consequently, U.S. natural gas prices are up more than 70% since March, even considering the big price drop over the past week. NGL prices are at the highest value relative to crude for any October since 2012. Is this it? Is this what a Shale Era recovery looks like? In today’s blog, we consider a possible road map for the next couple of years. Warning, we have also included a short infomercial for RBN’s School of Energy next week in Houston.
Over the next three years, 16 pipeline projects are in the works to add more than 14 Bcf/d of new take-away capacity to move Marcellus/Utica natural gas to the south and west, relieving takeaway capacity constraints that have plagued the Northeast since 2012-13. Much of this gas will be moved to the Gulf Coast, primarily via reversals of pipes that traditionally transported gas north and east, and will target rapidly growing LNG and Mexico export markets. But few of these pipeline projects get the gas all the way to those export outlets. The new supplies must traverse “Miles and Miles of Texas” (and Louisiana) to reach the export gateways and along the way deal with shifting production trends within the state, pipeline systems that are "telescoped the wrong way" constraining capacity of the Texas pipeline grid, and unique regulatory considerations associated with Texas intrastate pipelines. These issues are addressed in RBN’s latest Drill Down Report, highlights of which we discuss in today’s blog.
Way back when—before 2012—few outside a small cadre of oil producers and marketers paid any attention to condensates, or even knew they existed. Then two events shook the condensate world. First came rapid growth in the Eagle Ford, where crude oil production turned out to be almost half condensates. Then the Department of Commerce started allowing condensate exports while maintaining the ban on international sales of mainstream crude oil. Suddenly condensates were the star of the show. But like the careers of one-hit rock & roll wonders, the stardom didn’t last long. The crude oil price crash hit Eagle Ford hard, resulting in a disproportionate decline in condensate production. Congress then sent condensates further back into obscurity by removing the export ban for all crude oil in December 2015, eliminating any special status for the product. That was the end of the road for the condensate story, right? Wrong. Because during condensate’s day in the sun, billions were spent on pipelines, stabilizers, splitters, export facilities and refinery modifications, all focused on providing new markets for condensates. Oops. Today we consider how the next chapter of the condensate saga will play out.
U.S. crude oil prices languish below $50/bbl, but the oil-directed rig count is up by 90, an increase of almost 30% over the past 12 weeks. Natural gas production is down less than 1% from the all-time high hit back in February even though the price of natural gas remains below $3/MMbtu. The price spread between U.S. propane and international markets is far below a level that should justify exports, but LPG exports to overseas markets continue at astronomical levels –– approaching 700 Mb/d, most of which is propane. What’s wrong with this picture? Why does it seem that relationships between energy production, demand and prices have broken down, or at least have undergone some fundamental shift? That is what our upcoming School of Energy Fall 2016 is all about. Warning: Today’s blog includes a commercial for our upcoming Houston conference, scheduled for November 2 and 3 at The Houstonian Hotel.
U.S. propane production from natural gas processing has doubled over the past five years, but domestic demand has hardly moved the needle. So the only way the propane market has balanced is through exports, and it is no overstatement to say that the ship has really come in for U.S. propane exporters. All those exports have also helped support the U.S.
This week the first Gulf Coast ethane export cargo will depart Morgan’s Point, Enterprise Products Partners’ new export terminal on the Houston Ship Channel. This is a history-making event for at least three reasons. First, it inaugurates ethane exports from the Gulf Coast, only five months after the first-ever U.S. overseas ethane exports out of Sunoco Logistics’ Marcus Hook, PA, terminal. Second, it launches a battle for Mont Belvieu ethane, to be fought between ethane exporters and new ethane-only steam crackers (ethylene plants) that will be coming online along the Texas/Louisiana coast over the next couple of years. And third, Morgan’s Point is not just another export terminal. It is a location steeped in Texas history, known in the 1830s as New Washington, with an important role in the Battle of San Jacinto – decisive battle of the Texas Revolution -- and legend has it, inextricably tied to the Texas anthem “The Yellow Rose of Texas.” In today’s blog we examine the upcoming fight between ethane exporters and U.S. crackers.
“Condensates are long and you can’t give them away … No, things have changed – condensate supply is tight and prices are running up relative to WTI … But wait wait, the oversupply is back and prices are down again.” No wonder the market’s love for condensates has faded. It’s a liquid hydrocarbon that is being buffeted by every force the market can bring to bear: declining production, lots of new committed infrastructure (stabilizers, pipelines, and splitters), wide-open export markets, volatile crack spread splitter economics -- the list goes on. Adding to this whirlwind is the fact that historically there has been limited analytical data to work with, with most condensate information buried deep inside crude production numbers from producer investor presentations and less-than-revealing Energy Information Administration (EIA) crude oil reports. But we have some new tools to help understand what’s going on, including the EIA’s new 914 crude quality data and condensate export numbers from ClipperData. Today, we continue our exploration of rapidly evolving condensate markets.
Few segments of the energy market have experienced the roller-coaster ride that U.S. condensates have been on over the past five years. Prior to 2011, U.S. condensates were a forgotten backwater of the hydrocarbon complex, mostly blended off into crude oil. Then condensates rapidly transitioned from obscurity to an oversupplied, price-discounted growth market, then to a driver of massive infrastructure investment, then to the star of the show as the only member of the U.S. crude oil family that could be exported. By mid-2014, producers and midstreamers were in love with condensates. Exports were legal and growing. New pipeline, splitter, stabilizer and export dock infrastructure was coming online. U.S. condensate markets were tightening and condensate prices were increasing. Then in one fell swoop in December 2015, Congress swept away all export restrictions on crude oil, potentially relegating U.S. condensates back to the obscurity from whence they came.
On Monday, September 3, 2007, dignitaries and thousands of Panamanian citizens watched a huge explosion level a hill near Paraiso, a village north of Panama City. That day launched work on a project that would eventually cost more than $6 billion (U.S.) to double the capacity of the Panama Canal and allow for the passage of longer and wider ships. Nearly nine years later on June 26, 2016, the expansion is finally scheduled to be open for business. The new canal capacity will be a major event in global energy markets, especially for growing volumes of U.S. natural gas, liquified petroleum gas (LPG) and petroleum product exports. In honor of this historic development, RBN will take you there! Rusty will be traversing the canal this Thursday, April 14th and will have the skinny on what is happening in Panama right now, with pictures to show for it. In today’s blog we set the stage for our voyage across the Panamanian Isthmus.
In the five weeks since February 11, the price of WTI crude oil on the CME/NYMEX spiked 50%, up from $26/bbl to $40/bbl (see black dashed circle in Figure #1). For hedge funds that took long positions in February, it was an awesome trade. And for beleaguered producers, it was certainly a bit of good news. But there are no celebrations in the streets of Houston and Oklahoma City. The fact that $40/bbl should be considered “good news” is sobering: Eighteen months ago, that price level would have been seen as a catastrophe for the producing community. In fact, it still is. In today’s blog we examine the factors that help push prices above $40/bbl and what it will take to really get US production growing again.