The six liquefaction “trains” under development at Cheniere Energy’s Sabine Pass liquefied natural gas (LNG) terminal will demand nearly 4 Bcf/d of natural gas on average, the first 650 MMcf/d of that starting within a few months. And the five trains now planned at Cheniere’s Corpus Christi site—yes, now five, not three—will require another 3.2 Bcf/d. Taken together, that’s about 10% of current daily gas production in the U.S.; in other words, a monumental logistical task. Today, we start a series looking at the challenges of securing and moving huge volumes of gas to LNG export terminals, the emerging epicenters of U.S. gas demand.
As natural gas takes on an ever-expanding role in Asian energy markets, the traditional practice of sourcing liquefied natural gas (LNG) through long-term, “point-to-point” supply deals at oil-indexed prices is being challenged on several fronts. For one, U.S. exporters are linking the price of their LNG to Henry Hub gas prices. For another, Asian LNG customers, eager to reduce costs in a suddenly glutted LNG market, are working to renegotiate their oil-linked deals, and turning to the LNG spot market, where prices have been attractively low. Fast-changing market dynamics include planned gas pipelines from Siberia to China that may well make the Asian LNG market more like Europe, where LNG competes head-to-head with piped-in gas and with coal. Today, we continue our look at the changing international market and what it means for U.S. and Canadian gas producers and LNG exports.
Expectations for continuing rampant production growth for natural gas, natural gas liquids (NGLs) and crude oil have evaporated in the heat of the price melt-down. Volumes may be holding their own, even with 60% less rigs running, but the days of month-after-month record increases in production are behind us, at least for a while. But what about all that infrastructure that has been and continues to be built? Billions of dollars are going into pipelines, processing plants, petrochemical plants, terminals, storage, etc. based on a much higher production growth scenario than now looks likely. So what happens next? That issue is the theme of a new RBN conference scheduled for July 23rd in New York City called State of the Energy Markets, and is the subject of today’s blog – also an advertorial for the conference.
RBN analysis of 31 exploration and production (E&P) companies shows sharp differences between two groups of gas-weighted firms. The US diversified group is struggling to increase production, and slashing capital spending in light of weak profitability. Meanwhile, the Appalachian group is flying high as the most profitable classification in our analysis – largely as a result of slashing costs in response to weak natural gas prices. Today we wrap up our three-part analysis of U.S. E&P company’s 2015 outlook.
In just a few months’ time, it’s become easier to get regulatory approval to use unmanned aerial systems—more commonly known as drones—and the number of ways drones can be employed by the oil and gas sector has grown substantially. In fact, drones are getting involved in just about everything: geologic mapping, site surveying, methane detection, pipeline inspection—you name it. Today, we explore how drone use in the energy sector is quickly morphing from geeky to mainstream.
Asian consumers of liquefied natural gas (LNG) hope to use the current supply glut—and the start-up of U.S. LNG export facilities--to their long-term advantage. Their very understandable goal is to up-end the old market structure, which for years has had them paying far more for LNG than their Western European counterparts. How will the coming revolution affect U.S. natural gas producers and the next round of U.S. LNG export projects? Today, we continue our review of the fast-changing global market for LNG with a look at a new set of Asian LNG buyers and at the region’s fast-changing supply/demand dynamics.
Last year at this time (May 2014) the natural gas market was concerned with how depleted US natural gas storage might be by the start of the 2014-15 gas winter season. A short year later, the concern now is how full storage could get before next winter. CME/NYMEX Henry Hub natural gas futures prices for June delivery closed at 2.915/MMBtu yesterday – presumably reflecting a decidedly bearish 2015 supply/demand balance with forecasts predicting summer-ending inventory at upwards of 4.1 Tcf, which would be the highest on record. Today we provide an update on gas fundamentals.
The E&Ps have cut Capex to the bone, but as a group they expect oil and gas production in 2015 to increase versus last year. That’s true from an overall perspective, and it is an important indicator of upcoming production trends. But the real revelations come when you dig into the details. In the oily sector, small and mid-size companies are making deeper cuts but are faring much better than the big boys. On the gassy side, E&Ps in Appalachia are knocking it out of the park, while more diversified gassy players are having a much harder time of it. Today we begin a blog series to drill deeper into the company numbers to see why and how these differences happen.
Producers in the Marcellus and Utica shale plays could be moving a lot more natural gas into New England, if only there was enough pipeline capacity to get it there. An increasingly gas-hungry neighbor to the nation’s most prolific production area, New England has added precious little capacity to transport gas, and the fates of game-changing pipeline projects that have been proposed hang in the balance. The region’s unique gas-delivery challenges, their market impacts and possible solutions are the subject of RBN Energy’s newly released Drill Down report, “Please Come To Boston—New England’s Ongoing Gas-Supply Dilemma”. Today, we provide a preview, and highlight some of the report’s findings.
At a time when market prices have been weakened by a surplus of new natural gas production waiting for demand to develop, Mexico has been stepping up to the plate by increasing imports. Gas demand for Mexican power generation, industrial use, and commercial and residential space heating continues to increase at a torrid pace south of the Rio Grande, much to the relief of gas producers in the Eagle Ford, the Permian Basin and other U.S. plays within reach of the international border. Today we provide an update on Mexico’s growing dependence on U.S.-sourced gas, and the implications for producers and midstream companies.
The latest Energy Information Administration (EIA) Drilling Productivity Report projects natural gas production in the Marcellus and Utica up 170 MMcf/d in April, and forecasts growth of another 150 MMcf/d in May and June to average about 3.8 Bcf/d higher in Q2 than in the same period last year. While there is talk of deferred well completions and shut-ins, it has yet to translate to a slowdown in production volumes in the Northeast region. Our analysis suggests that barring record-high demand, the region will struggle to balance growing supplies this summer with potentially dramatic consequences for prices Today we conclude our analysis of the Northeast gas supply/demand balance.
Japan takes up less real estate than California, and South Korea is smaller than Kentucky, but the two Asian nations are giants in the international liquefied natural gas (LNG) market. Their outsized appetite for LNG, combined with their interests in diversifying their sources of gas supply, could provide a major boost to U.S. and Canadian natural gas producers—only, though, if the price is right. Today, we continue our look at the fast-changing international market for LNG, rising Asia demand, and what these changes mean for gas producers and LNG exporters.
A key supply/demand balancing mechanism in the U.S. Northeast natural gas market – displacement of flows – is about to be history, at least in the summer months. With regional supply close to 4 Bcf/d higher year-over-year and now fewer options for offsetting the supply growth, the region faces significant downside risk for prices and even production this summer. The question is, can regional storage, demand and outflow capacity help prevent a widespread summer 2015 supply glut? Today we look at prospects for balancing the surplus in the region, starting with storage and demand.
The pace of liquefied natural gas (LNG) demand growth in Asia will be a critical factor in determining how much natural gas North American producers export over the next 10 to 20 years, and gas/LNG export levels are sure to affect U.S. and Canadian gas production levels and prices. Last year's pause in Asian LNG demand growth--combined with a collapse in LNG prices--led many to wonder, where is all this heading, and what does it mean for gas producers and LNG exporters? Today, we continue our review of the fast-changing international LNG market with a look at Asia's burgeoning gas needs and how they will likely be met.
At yesterday’s close (April 28, 2015) the CME NYMEX Henry Hub natural gas futures strip (average) for the nearby 12 months was $2.794/MMBtu. That was only slightly above Monday’s three year low for the strip. The price weakness has been brought on by concern about a growing storage surplus. Last week the Energy Information Administration (EIA) last week reported that U.S. natural gas storage as of April 17 was 737 Bcf, or 83%, higher than this time last year. Within a year, the gas market has gone from the biggest storage deficit and lowest inventory since 2003 at the end of March 2014, to a massive year-over-year surplus and the possibility of a record-high inventory by the end of injection season. In today’s blog, we look at how inventories got here and implications for the summer gas market.