With storage inventories soaring to record-high levels and production remaining relatively flat, the U.S. natural gas market is in dire need of record demand this summer to balance storage. All eyes are on power generation to soak up the gas storage surplus. Low gas prices and increased gas-fired generating capacity makes natural gas the go-to generation fuel this year. However, in the largest summer demand market – Texas – natural gas is facing increasing competition from wind. Wind power still provides a much smaller share of Texas’s power than natural gas, but the addition of several big wind farms in 2015 gives wind a stronger footing in the Texas market this year. Today we take a closer look at the potential impact of growing wind generating capacity on natural gas demand, particularly in Texas.
When the Rockies Express (REX) Pipeline was being planned and built a few years ago, no one could have predicted that the natural gas-hungry Northeast REX was developed to serve would soon become a gas-production behemoth able to meet its own needs and have plenty of gas left over. But that’s just what happened, and in response, REX’s owners developed a revised strategy that deals with the reality of Marcellus/Utica production growth by making more and more of REX bi-directional. Now, Tallgrass Energy Partners (TEP), a master limited partnership (MLP), has acquired a 25% interest in REX from Sempra, joining existing co-owners Tallgrass Development (an affiliate with a 50% stake in REX) and Phillips 66 (with a 25% stake), and has laid out a long-term vision for maintaining—and even increasing—REX’s relevance in a still-changing energy world. Today, we consider TEP’s $1.08 billion investment in REX, and the steps that the pipeline’s co-owners are taking to bolster REX’s future.
Northeast natural gas production has been averaging nearly 3.0 Bcf/d higher this year than last year, while demand has lagged behind due to mild weather. At the same time, storage inventories are running well above normal and there is little new takeaway capacity due online this summer. This means the Northeast is under pressure to balance excess supply in the region. In today’s blog, we wrap up our analysis of the Northeast supply/demand balance with a closer look at recent demand trends.
As U.S. electric utilities become increasingly dependent on natural gas-fired power, they’re looking for ways to mitigate the risk of future gas-price volatility. One hedging option that’s gained some attention lately is direct utility investment in natural gas production assets, the idea being that by acquiring gas-in-the-ground—especially now, when gas prices seem low and many financially strapped gas producers are eager to make deals—utilities can lock in the price of at least part of the future gas needs. Today, we consider the latest efforts by electric utilities to expand their gas hedging strategies—and hold the line on future gas prices—by including direct investments in gas production assets.
The Northeast has been the biggest driver of U.S. natural gas production growth in recent years, and while rig counts have come down, output from the Marcellus and Utica has remained resilient and helped offset declines in other supply regions. In the process, the Northeast has reinvented itself, shifting from a gas-thirsty consuming region to one of the biggest gas net producing regions in the U.S. But pipeline flow data indicates that Northeast production peaked in February and growth has flattened since then. Is the data signaling a long-term peak or is this a temporary lull? Today, we continue our analysis of the Northeast supply/demand balance with a closer look at recent production trends.
The U.S. Northeast natural gas supply/demand balance has been getting less and less short in recent years due to the onslaught of Marcellus/Utica production, and in 2015 flipped to net long supply for the first time on an annualized basis. That means the 15-state Northeast region as a whole produced more gas in 2015 than it used. Then, in the winter of 2015-16, the region reached another milestone when it ended the season net long supply for the first time. Now regional production may be flattening out and future growth is at risk as takeaway capacity projects face economic and regulatory headwinds. What does that mean for the Northeast balance going forward? Today, we begin a series analyzing the latest fundamental trends in the Northeast gas market.
Even in tough times like these, companies need to look ahead, to consider what steps they would take--or investments they would make--if, for example, oil prices were to rise to X dollars per barrel, or the cost of drilling and completing a well were to fall by Y%. For methanol producers, these “what-ifs” might include what if methanol prices (holding steady the past few months at $249/metric ton, or MT) were to rebound to where they stood a year ago ($442/MW in May 2015)? Or what if we could add new capacity at a fraction of the cost of new-build? Today, we consider how building more methanol capacity might make sense in the right circumstances.
Energy Transfer Partners (ETP is the nation’s second-largest master limited partnership (MLP), with a market capitalization of $16.6 billion, $39.7 billion in 2015 revenue and $8 billion in 2015 capital investments, and a general partner—Energy Transfer Equity (ETE)—whose once-promising merger deal with Williams Cos. has turned ugly and may well be doomed. ETP’s extensive holdings include several major interstate and intrastate natural gas pipelines, midstream natural gas services, and natural gas liquids (NGL) pipelines and services; it also holds approximately 27.5% of the limited partner interests and all of the general partner interest in Sunoco Logistics Partners (SXL). With ETP’s size, its huge portfolio of midstream assets, and its high-profile general partner, the MLP was an obvious choice for our new Spotlight Report. Today, we provide the highlights of the report, which is available to RBN Backstage Pass subscribers.
The U.S. natural gas market is carrying about an 850-Bcf surplus in storage versus last year and the 5-year average. But it looks like the surplus will finally start to contract in earnest over the next few weeks. So the big question is -- will it be fast enough to prevent crippling supply congestion by this fall? With Canadian storage inventories also high and U.S. gas production still averaging slightly higher than last year, it seems record demand will be needed to bring storage into balance. Today we look at the prospects for demand this summer to trump last year’s record demand.
With the first month of storage injection season now behind us, the weekly storage report from Energy Information Administration (EIA) shows U.S. natural gas stocks at about 850 Bcf higher than last year. While the surplus vs. 2015 has contracted from over 1,000 Bcf at the start of injection season April 1, it has a long way to go before the gas market is out of the woods, and prices are reflecting that. The CME/NYMEX Henry Hub contract for June delivery settled Wednesday at $2.141/MMBtu, down 68 (24%) from last year, and the balance-of-summer strip is priced at an average $2.408/MMBtu as of yesterday’s settles, 48 cents (17%) lower than a year ago. Given the sheer size of the overhang at this point, the pace of the surplus contraction will be at least as important to price direction as the fact that it is contracting. Today we look at the various supply and demand factors that could either help or hinder the market to whittle down the storage surplus this summer.
More than 3,000 MW of new, natural gas-fired generating capacity is either under construction in New England or will be soon, but some of the gas pipeline projects that would ease long-standing constraints into and through the six-state region have hit rough patches. Kinder Morgan in mid-April suspended plans for its Northeast Energy Direct project, a “greenfield” pipeline across Massachusetts and southern New Hampshire, and a few days later the state of New York denied the co-developers of the already-delayed Constitution Pipeline—a key link between the Marcellus and New England--a needed water quality permit. The fates of some other major projects in the Northeast are uncertain too. Today, we provide an update on pipelines in the land of Yankees and Red Sox.
The U.S. natural gas market ended the winter withdrawal season with inventories carrying a record high overhang and an enormous surplus versus previous years. Since then, the historic surplus has begun to contract, and the CME/NYMEX Henry Hub futures contract has responded, rallying 11.2 cents since April 1st to settle at $2.068/MMBtu Thursday. Now, well into the third week of injection season, the big questions are whether the recent bullishness can be sustained and what it will take to relieve the surplus in storage. In today’s blog, we assess how the existing surplus will impact summer storage activity and prices.
After a series of construction setbacks, the Panama Canal expansion is finally expected to come online by mid-2016. The wider, deeper canal locks will enable any LPG ship (up through Very Large Gas Carriers, or VLGCs) on the planet to take the time- and money-saving short-cut, and also will accommodate all but a few of the world’s biggest liquefied natural gas (LNG) vessels. That can only help U.S. liquefied petroleum gas (LPG) and LNG exporters, who for competitive reasons need the low transportation costs to Pacific Basin markets that shipping in super-bulk will provide. Today we discuss how the expansion project may boost exports of hydrocarbons from the U.S. Gulf Coast.
Mexico’s need to import increasing amounts of transportation and cooking fuels--mostly gasoline, diesel, and liquefied petroleum gas (LPG)—from the U.S. is spurring an infrastructure development boom on both sides of the Rio Grande. Over the past few years this has been a frequently reoccurring pattern: A fast growing market for hydrocarbons emerges, and the need to efficiently move increasing volumes of product from points A and B to points C, D and E quickly becomes urgent. All hands are called on-deck: trucks, railroads, barges, pipelines—plus storage facilities and distribution terminals. Today, we consider the latest initiatives to deliver gasoline, diesel, jet-kero and LPG from Texas to its southern neighbor.
U.S natural gas storage inventories ended the winter heating season at a record high for this time of year of 2,480 Bcf as of April 1, 2016. Yesterday (Thursday April 14) the Energy Information Administration (EIA) reported that U.S. natural gas storage fell a notch as of April 8 to 2,477 Bcf or 956 Bcf (63%) higher than the corresponding week last year. CME/NYMEX Henry Hub natural gas futures prices for May delivery closed at $1.970/MMBtu yesterday, 56 cents lower than last year at this time. Moreover the current 12-month strip is averaging $2.48, 32 cents lower than last year at this time. In today’s blog, we look at how inventories got here and implications for the summer market.