Every day, crude oil producers on Alaska’s North Slope re-inject nearly 7.8 Bcf of natural gas into their wells, enough gas to supply the entire U.S. West Coast—California, Oregon and Washington State. If only there were some way to monetize that gas supply, to move it to market. The problem is that there isn’t, at least in today’s gas/LNG market, which is characterized by ample supply and relatively low prices. This same market also favors infrastructure projects that are simple and low-cost; no one wants to make multibillion-dollar commitments when natural gas prices and margins are so low. Today we conclude our series on the tough times ahead for Alaska’s energy sector with a look at the state’s vast natural gas reserves and the challenges associated with tapping them.
Daily Energy Blog
The natural gas flow patterns that characterized the U.S. energy-delivery sector for the decades preceding the Shale Revolution are gradually being undone, and few, if any, states are more affected by these changes than Texas. The state remains the nation’s largest natural gas producer, and it still produces nearly twice as much gas as its consumes within its borders. But traditional Northeast and Midwest markets for Texas gas are being ceded to Marcellus/Utica producers, and more and more Northeast gas is flowing south/southwest to the western Gulf Coast, drawn by power/industrial demand, new LNG export terminals and rising pipeline-gas exports to Mexico. Today we begin a look at the dramatic shifts in gas flows out of Texas through key gas pipeline exit points.
Demand for U.S. natural gas exports via Texas is set to increase by close to 6 Bcf/d over the next few years. At the same time, Texas production has declined more than 3.0 Bcf/d (16%) to less than 17 Bcf/d in the first half of November from a peak of over 20 Bcf/d in December 2014, and any upside from current levels is likely to be far outpaced by that export demand growth. Much of the supply for export demand from Texas will need to come from outside the state, the most likely source being the only still-growing supply regions—the Marcellus/Utica shales in the U.S. Northeast. Perryville Hub in northeastern Louisiana will be a key waystation for southbound flows from the Marcellus/Utica to target these export markets along the Louisiana and Texas Gulf Coast, particularly given the hub’s connectivity and prime location. Today, we look at the pipeline expansion projects into Perryville that will make this flow reversal possible.
With today’s low crude oil and natural gas prices, the survival of exploration and production companies depends on razor-thin margins. Lease operating expenses––the costs incurred by an operator to keep production flowing after the initial cost of drilling and completing a well have been incurred––are a go-to variable in assessing the financial health of E&Ps. But it’s not enough for investors and analysts to pull LOE line items from Securities and Exchange Commission filings to find the lowest cost producers, plays, or basins. More than ever we need to understand—really, truly, deeply—what LOEs are, why they matter, how they change with commodity prices, production volumes, and other factors, and how we should use them when comparing players and plays. Today we begin a series on a little-explored but important factor in assessing oil and gas production costs.
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.
Forecasting in U.S. energy markets characterized by hair-trigger price volatility, ever-improving well drilling and completion productivity, and the unraveling of old norms is a bit of a high-wire act. But just as big-tent tightrope walkers get better with practice, energy prognosticators can gain from experience––and from taking a look back at previous forecasts to see what they got right, what they may have missed, and what’s changed in the interim. Today we continue our review of a recent presentation at RBN’s School of Energy earlier this month on forecasting lessons learned.
On the last day of October 2016, the first-ever shipment of Chinese motor gasoline to the U.S. was delivered to Buckeye’s Reading terminal in New York Harbor. The vessel took a circuitous route to New York, taking on cargo in the Hong Kong lightering zone, stopping in South Korea to take on another parcel of clean product, dropping off some benzene in Houston, and then finally heading to New York. That complicated journey suggests that the economics of a regular China-to-East Coast gasoline trade route are not there (at least for now), but the shipment highlights a trend: China is becoming more assertive as an exporter of petroleum products and the implications are global. In an international market defined by oversupply, inroads by China necessarily result in other producers losing market share. In today’s blog, we examine the impact of rising clean petroleum product exports—particularly from China, but also from India—and the corresponding ripple effects both on the world market and on U.S. refiners.
Over the past few weeks, publicly traded independent refining companies reported their latest quarterly results, and nearly all lamented on a common theme: the cost of Renewable Identification Numbers (RINs) is out of control. However, the financial burden is not felt equally across the industry, as companies with integrated marketing operations (refining, blending and retailing) don’t face the same RINs-cost albatross as merchant refiners who don’t have retail operations. Today we review the escalating RIN costs that obligated parties have endured this year and explain how the degree of financial pain depends on the level of refiners’ downstream integration.
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.
Natural gas pipeline takeaway projects under development out of the U.S. Northeast would enable ~10 Bcf/d to flow south from the Marcellus/Utica supply area. About half of that southbound capacity is geared to serve growing power generation demand directly south and east via the Mid-Atlantic states. But another nearly 5.0 Bcf/d is headed southwest to the Louisiana and Texas Gulf Coast for growing LNG export and Mexico demand—and that is on top of about 4.4 Bcf/d of reversal (or backhaul) capacity already added over the past two years. Much of the Gulf Coast-bound backhaul capacity will converge on the Perryville Hub, a market center located in northeastern Louisiana, about 220 miles north of the U.S. national benchmark Henry Hub. As such, the ability for gas to move through Perryville and get to downstream demand market centers will be key to balancing the natural gas markets. Today, we take a closer look at the historical and future pipeline capacity in and around the Perryville Hub.
The Shale Revolution changed everything about U.S energy markets, and in the process made forecasting the production and pricing of crude oil, natural gas and NGLs a heck of a lot harder. But we all learn from experience. In the early days of the Revolution, few could have predicted how quickly output would rise, how challenging it would be for pipeline takeaway capacity to keep up with production, or how successfully crude-by-rail would fill the gap – until that gap went away with the Revolution’s most recent phase. Comparing past forecasts to what actually happened is instructive though, and maybe––just maybe––today’s projections for the future are more informed than the forecasts of 2011 or 2013. In today’s blog we look at a recent presentation on forecasting lessons learned at RBN’s School of Energy earlier this month.
Intrastate natural gas pipelines in Texas reach far and wide, and can transport extraordinary volumes of gas. The problem is, the traditional supply/demand dynamics that spurred the development of all that pipe decades ago are being up-ended by burgeoning Marcellus/Utica production headed to the Gulf Coast and the demand-pull of gas to planned LNG export terminals along the Texas coast and to Mexico. Lone Star State pipelines that for years have flowed north and east to the Houston Ship Channel and beyond now must flow south and west. Today, we continue our review of efforts to rework and expand key elements of Texas’s intrastate gas pipeline network to meet growing export needs, this time with a look at plans by Enterprise Products Partners.
Production of natural gas liquids in the Northeast has been rising sharply for several years now, challenging the ability of NGL producers and midstream companies to deal with it all. Lately, though, drilling in “wet” gas parts of the Marcellus and Utica shale plays has slowed, mostly because prices for NGLs have sagged due to lower crude prices and the high cost of takeaway capacity, thereby reducing the incentive to drill for the wet gas responsible for NGL production growth. However, it is quite possible that total NGL production growth could continue for some period of time as more ethane is extracted from wet gas instead of being “rejected”. Meanwhile, new NGL pipeline capacity out of the Marcellus/Utica has been coming online, providing a relief valve of sorts. Today we begin a blog series on recent developments regarding Northeast NGL production, takeaway capacity and pricing.
Forty years ago, Alaska was seen as the next big thing for U.S. crude oil production––and it was. With the completion of the Trans Alaska Pipeline System in 1977, Alaska North Slope production took off, and by early 1988 it was topping 2 MMb/d and accounting for nearly one-quarter of total U.S. output. But that was the peak; since then, ANS production has fallen steadily, and in August 2016 it averaged only 443 Mb/d, or 5% of the national total. While there is clearly a lot of oil (and natural gas) still in the ground in the North Slope region, developing those resources would be very costly. Today we begin a two-part series on energy production in the 49th state with a look at the oil side of things.
Northeast production growth, the primary driver of overall gains in U.S. natural gas output in recent years, has largely stalled in 2016. Rig counts in the Marcellus/Utica dropped to near six-year lows, and the region has been facing constraints—from takeaway capacity and in the past month or two from storage injection capacity. But market factors are again about to roil the Northeast: 1) winter heating demand is on its way, and 2) more takeaway capacity has come online in the past month and still more is coming before the year is up. Today, we review recent Northeast natural gas production trends using pipeline flow data from Genscape and assess factors that will impact regional production this winter.
