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!
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”.
The oil price collapse has opened a wide rift between high quality “good” assets, breakeven “bad” assets, and ruinous “ugly” assets. The consequences will impact energy markets for decades to come. In our recently published Drill Down Report, we demonstrate the differences between good, bad and ugly wells by examining the diversity of production economics across the Eagle Ford basin and why producers have been zeroing in on the counties——and areas within those counties—where initial production (IP) rates are highest, and preferably where large volumes of associated natural gas and natural gas liquids can be found as well. Today we consider Eagle Ford counties in more depth—their IPs, their internal rates of return (IRRs), and the number of new-well permit applications in each county in the first quarter of 2016.
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.
West Texas Intermediate (WTI) CME NYMEX crude futures settled up 92 cents/Bbl yesterday (January 28, 2016) at $33.22/Bbl and NYMEX Henry Hub natural gas futures settled up slightly at $2.182/MMBtu. The crude-to-gas ratio - meaning the crude price in $/Bbl divided by the gas price in $/MMBtu - was 15.22 X. For most of this year so far the ratio has been less than 15X On January 20, 2016 it dipped to 12.5 X – its lowest point since March 2009. Over the 5 years between 2010 and 2014 the ratio averaged 27X - reaching a high of 54X in April 2012. That lofty five year run for the crude-to-gas ratio was arguably responsible for much of the crude and natural gas liquids production boom since 2011 and a “Golden Age” of natural gas processing. Today we begin a two-part series discussing the ratio and the market implications if it stays low.
Over the past six years surging U.S. hydrocarbon production from shale has exceeded domestic demand in many cases – leading to the development of export infrastructure. Large volumes of natural gas liquids (NGLs) such as propane are already being exported. Natural gas exports in the form of liquefied natural gas (LNG) are about to start and the recent end to federal restrictions offers the possibility to increase crude exports if they become competitive. A critical assumption behind all these export opportunities is that the U.S. continues to be the only country (except Canada to a lesser degree) to successfully “crack the code” in shale exploitation to produce commercially significant volumes competitively. This assumption would be turned on its head if competing countries like Mexico, China, Poland, Argentina and the U.K. are able to unlock their own shale potential. Today we review RBN Energy’s first Drill Down report of 2016, which considers the many “below-ground” and “above-ground” factors that will determine whether and how quickly, shale development becomes a worldwide phenomenon.
Energy market volatility in 2015 was neither the result of random market fluctuations nor geopolitical orchestration. The market pressures had been building for years, as one market event triggered another, leading inexorably to the carnage of Q4 2015. In fact, there were thirty such market events, which are represented by dominos in the new book by Rusty Braziel, titled The Domino Effect now Amazon’s #1 bestselling book in four categories. More dominoes will topple in 2016 and the years b
2015 was a transformational year for the U.S. shale revolution. Act I of the Shale Revolution is now behind us. We’ll look back at the first decade -- 2005-2015 as the halcyon days – when there was always another market just around the corner. Shale started with dry gas in Texas, but those prices were crushed by the economics of wet gas and NGLs. In just a few years, that market too was annihilated, but economically attractive Appalachia dry gas and the big kahuna, crude oil took center stage. Now after a year of being beaten senseless by low prices, it is clear that those markets too have succumbed to the scourge of shale oversupply. That’s the end of Act I. There is nowhere else for producers to turn. The market dynamics facing Act II of the shale revolution are unprecedented. There is simply no way to predict what is going to happen next. Right? That’s silly. Of course we can! It is the perfect time to roll out RBN’s crystal ball one more time for 2016 - Year of the Monkey. Yup, there is more monkey business coming to energy markets.
Energy markets will long remember 2015. For producers and midstreamers, the memories won’t be pleasant. But it was not all bad news. Particularly if you happen to be an energy buyer or refiner. As we’ve done for the past four years, today is a day for looking back over the past twelve months in the RBN blogosphere – 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 have taken a page out of the late Casey Kasem’s playbook to look at the top blogs of 2015 based on numbers of website hits.
What do you do when prices are in the cellar, hundreds of rigs are idle, production growth has evaporated and the whole industry seems to be wondering how the numbers are going to work. Well of course, it’s time to head back to school to understand the new realities of energy markets. That is what School of Energy Spring 2016 is all about. This is nothing like other natural gas, crude oil or NGL conferences! The course work is hands-on. In each module we’ll drill down on an important aspect of the market, explain how it works, download spreadsheet models and learn how to use them. This time we’ve added more models than ever, crunching the numbers that explain everything from production economics to petrochemical margins in the context of today’s prices. You walk out the door with the how-to Powerpoints and the Excel models on your hard drive. Warning - today’s blog is a blatant commercial for our upcoming Houston conference.
The CME/NYMEX Henry Hub contract for January delivery hit a 17-year low yesterday (December 10, 2015) of $2.015/MMBtu, 46 % below year-ago price levels. But US gas production has been humming along near 73 Bcf/d, more than 3.0 Bcf above a year ago and about 1.0 Bcf below the all-time high earlier this year. It’s a similar story for crude oil, with oil prices closing at $36.76/Bbl yesterday, but production hanging in there above 9 MMb/d. This is a testament to lower drilling service costs and producers’ ability to improve drilling productivity. But can productivity gains and drilling costs keep up with continually lower commodity prices? Today we look at how productivity gains and falling drilling costs are impacting producers’ rates of return.
Mexico has emerged as an important and growing market for U.S. natural gas producers, and for U.S. midstream companies scrambling to develop gas pipelines to serve Mexico’s gas consumers. Meanwhile, U.S. gasoline, diesel and liquefied petroleum gas (LPG) exports to Mexico are also up. Petróleos Mexicanos (Pemex)—the state-owned hydrocarbon giant, now in the midst of a major reboot—is on the hunt for private-sector partners to help revive Mexico’s sagging oil and gas production, and U.S. oil producers and Pemex are planning their first swaps of crude. Today we highlight RBN Energy’s latest Drill Down report examining the changing yins and yangs of cross-border energy relations.
Eager to boost oil and natural gas production, the government of Mexico is in the midst of a multi-year effort to introduce more private-sector involvement and competition. The hope is that a series of reforms will lead to more investment and—over time—a Mexican energy sector that more closely resembles that of Mexico’s amigos North of the Border. Today, we continue our look at the ongoing transformation of U.S.-Mexico hydrocarbon trade and what it may mean for energy companies on both sides of the Rio Grande.
In connection with third-quarter earnings announcements, North American exploration and production companies (E&Ps) continued to announce large reductions in 2015 and 2016 capital budgets. But the most dramatic news is that RBN’s analysis of a study group of 31 E&Ps fourth quarter forecasts indicates that oil and gas production is now expected to level off in the fourth quarter of 2015 and into 2016. Today we update our analysis of E&P capital spending and oil and gas production guidance.