While crude oil takeaway capacity out of the Permian Basin from major hubs is probably overbuilt for the time being that is not the case for gathering systems bringing barrels from the wellhead to mainline terminals. Production in the Permian has slowed since the drop in oil prices reduced drilling activity but is still increasing from sweet spots in the Midland and Delaware basins in West Texas where pipeline gathering can save producers as much as $2/Bbl in trucking fees. Today we continue our review of gathering infrastructure build out to deliver more crude to takeaway hubs in the Permian.
Daily energy Posts
The New York market for residential and commercial heating oil is traditionally tight in the winter months when demand exceeds local production and supplies are supplemented from storage and inflows/imports from outside the region. Coming into winter this year inventory levels were above normal for the time of year and market prices are in contango (a condition where future prices are higher than today) – encouraging further storage. Today we explain how the result is an extension of traditional seasonal storage trade opportunities and a shortage of available inventory capacity.
A highly anticipated event in the U.S. natural gas market is when the Northeast region crosses the line from being a net gas taker from, to becoming a net gas supplier to, the rest of the country. Ever since the Marcellus and Utica shale began ramping up, Northeast production has been on a course to eclipse regional demand. RBN predicted 2015 would be the tipping point when the supply-demand balance would finally reverse on an annual average basis, marking a new phase for Northeast prices and for the U.S. gas market as a whole. We’ve seen that despite capitulating oil prices, capital budget cuts and lower rig counts, Northeast production has continued to reach new highs in 2015 – beating the record again this past Sunday (November 22,2015) at 20.3 Bcf/d according to Genscape. But regional demand also has been at record high levels. Today with less than two months left in the year, we determine whether the Northeast region will – or already has - crossed the threshold to net supplier in 2015.
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.
Ethane has been in the doghouse for years since the shale gas boom kicked in, with production greatly exceeding demand and hundreds of thousands of barrels per day being “rejected” into the natural gas stream – owing to the fact that netbacks for liquid ethane are lower than pipeline natural gas. One way to understand that relationship is to track the price ratio of ethane at Mont Belvieu, TX to natural gas at Henry Hub, compared on a BTU basis. That ratio of ethane-to-gas languished at 95% between Q1 2014 through the summer of this year, and in November 2014 dipped to only 61%. That means that the BTU value of ethane at that point was only 61% of natural gas. Ethane that cheap is an awesome value for steam crackers using the feedstock to produce ethylene and other petrochemicals. But a couple of months ago (September 2015), the price of ethane started to ramp up relative to gas, blasting through 140% in late October. Is that bad news for future ethane prices? What does that portend for ethane once all the new steam crackers being built come online and overseas exports – also coming soon -- ramp up. Today we look at the recent rebound in the ratio of ethane to natural gas and consider whether this is a signal that ethane is out of the doghouse.
Yesterday (November 19, 2015) the Energy Information Administration (EIA) published its first official weekly natural gas storage report in its new five-region format indicating an injection of 15 Bcf over the past week for a total U.S. inventory of exactly 4 Tcf. The new methodology and reporting format is a vast improvement in the granularity and clarity of government natural gas storage inventory data. But it also potentially moves the target for the slew of industry analysts who lose sleep trying to predict it each week. How the changes impact EIA inventory data and the ability of analysts to predict that data will become clearer in the coming weeks and months. But we got more clues this week as the EIA released dual versions of last week’s report on Monday showing significant differences leading up to launch of the new report on Thursday. Today we compare the results of the old versus new methodology.
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.
Mexico’s energy relationship with the U.S. is undergoing radical changes as its oil production sags, its refineries produce too much high-sulfur fuel oil and too little gasoline and diesel, and its imports of U.S. natural gas and transportation fuels rise. Add to this already complicated story the Mexican government’s efforts to inject competition and private-sector participation into a national energy sector long-dominated by state-owned Petróleos Mexicanos (Pemex) and that company’s plan to swap light U.S. crude for heavy Mexican oil. In today’s blog, “With A Little Help From My Friends—Mexico’s Oil Sector in a State of Flux,” Housley Carr begins a look at the ongoing transformation of U.S.-Mexico hydrocarbon trade and what it may mean for U.S. players—and Pemex.
Permian Basin crude production more than doubled since 2011 to reach nearly 2 MMb/d today, but that rate of increase has leveled off since prices crashed last year. Meantime 750Mb/d of long-haul pipeline takeaway capacity came online in the first half of 2015 - greatly exceeding today’s take-away requirements. And there is more to come next year when the 470 Mb/d Enterprise Midland-to-Sealy pipeline is expected online – leading to fears regional pipeline infrastructure is overbuilt. How about inside the Permian Basin? Today we start a series reviewing Permian gathering system build out.
Within and near the Marcellus and Utica shale plays, power plant developers are building more than a dozen new natural gas-fired generating units, mostly combined-cycle plants that can operate essentially around-the-clock. This construction boom, spurred by a combination of abundant, low-cost gas and the regulation-driven retirement of scores of older coal plants, is boosting gas consumption close to gas production areas and reducing—at least a bit—the surplus gas volumes that Marcellus and Utica producers and marketers need to move to markets outside the region. Today, we examine the race to build new power plants near production areas in the Northeast, and consider what the resulting local gas consumption might mean for the region’s gas prices and pipeline needs.
It used to be the case that if natural gas even came up in power-industry discussions of generation, it happened at the end of a meeting—“Well, we’re done with our nuclear and coal plans, anyone have anything else to discuss before we go to dinner? Oh, that’s right—anything happening with gas?” Now it’s the other way around. It seems like every discussion starts with gas, whether it’s about the plants being low-cost and easy to site, about concerns around reliability and price volatility, or around the impact of the gas market on coal investments. And power is clearly the fastest growing segment of the U.S. natural gas market. But does all this attention from the power market mean that the natural gas industry really understands the power side? Perhaps not. In fact, we’ve found that frequently, as soon as we get beyond the marketers and analysts who deal specifically with supplying gas-fired power generation, there’s a lot the natural gas industry (and the energy markets in general) can learn about power plants, electricity markets, and how natural gas fits in. So for that reason, we’ve concluded that now is a good time for a primer on how gas-fired generation works, how it fits together with energy markets and how it might be affected by national policy changes. Today we take on this challenge with the first installment of a three-part series.
As we stated in Part 1 of this series, New York City will need increasing amounts of natural gas as it continues its shift from oil-fired power plants and oil-based space heating. New gas pipeline capacity to and through the Big Apple has been added as recently as May 2015, but the nation’s largest city still faces wintertime gas-delivery constraints that cause costly spikes in gas and power prices. Given the challenges of adding new pipeline capacity in one of the most densely populated parts of the U.S., developer Liberty Natural Gas is planning an offshore liquefied natural gas terminal that by late 2018 would inject gas into the city’s existing pipeline network on an as-needed basis. Today, we continue our look at the economics of using imported LNG to supplement gas supplies in the Northeast.
Did you miss our School of Energy a few weeks back in Houston? Not a problem! The entire School of Energy conference is now available online in streaming video format. The conference video, presentation slides and spreadsheet models are available for purchase as individual Modules or as a full conference package. It’s the next best thing to being there! School of Energy is unlike other natural gas, NGL or crude oil conferences. It combines all three! And the curriculum includes a comprehensive analysis of current energy markets and in-depth instruction on how to use RBN spreadsheet models covering everything from production economics to gas processing. We walk through key developments for each of the three hydrocarbons including the increasingly important links between them. Fair warning – today’s blog is a blatant advertorial.
The U.S. natural gas market is starting its 2015-16 winter season with a whopping 3,929 Bcf in storage, equal to the record maximum level set Nov. 2, 2012. Meanwhile gas production is also well above last year. Given these conditions, the market will need record demand to absorb incremental production and work off the surplus in storage. But weather forecasts so far are pointing toward a delayed start to winter heating demand. The price of natural gas has sagged under the pressure with the prompt CME/NYMEX Henry Hub futures contract treading at a price less than half this time last year. And, now, a number of operational factors and constraints are set to kick in for the winter that could further disrupt an oversupplied market. In today’s blog, we look at the storage and transportation dynamics that could factor into how the market balances this winter.
There’s been at least some progress the last two years on Alaska’s ambitious plan to pipe huge volumes of North Slope-sourced natural gas to the state’s southern coast, supercool it into liquid form, and ship the resulting LNG to Asia. Over that same period, however, the international LNG market has been rattled by weak demand, rock-bottom prices and an impending supply glut. Alaska is itching to become a major LNG supplier by the mid-2020s, but is anyone willing to buy what it’s selling? Today, we provide an update on Alaska’s LNG plan, including a newly approved state buy-out of TransCanada’s interest in key elements of it.