Say “LNG” and the first thing that comes to mind for most of us is the potential for liquefied natural gas exports to Asia and other overseas markets. One of the hottest LNG markets right now, though, is domestic, and involves super-cooling natural gas into LNG and using it to power drilling rigs and hydraulic fracturing pumps, as well as ships, locomotives, and long-haul trucks. A number of small liquefaction plants have been operating for years in the US – most connected to peak shaving generation facilities but projects with capacity totaling more than 2 million gallons/day are under construction or being planned. Today we begin a new series examining the increasing use of LNG as a cheaper, cleaner alternative to diesel and shipping fuel, and the LNG production capacity being developed to keep pace with rising demand.
Daily Energy Blog
Heightened worldwide competition among LNG exporters is forcing a reality check on projects. LNG buyers, most of them in the Asia/Pacific region, are pressing for prices that more closely track natural gas value at the source—plus the known or calculable costs of liquefaction and shipping. Projects whose capital costs put their LNG pricing out of the money will not find the buyers they need to make their projects a “go.” The 16 or more LNG export projects under development in Western Canada are going through a winnowing process of sorts right now, largely because all are greenfield efforts and all but the smallest projects require new, expensive pipeline capacity to move their gas to port. Today in the third blog in our series on Western Canadian LNG exports, we examine the remaining field of contenders, including some floating or barge-based proposals that may gain an edge.
Canada’s National Energy Board (NEB) already has approved export licenses for nine LNG export projects in British Columbia that, if all built, would demand a total of up to 16 Bcf/d of Western Canada natural gas. Several other LNG export projects also are under development in BC. In reality, though, at most only a handful of all these projects will be financed and constructed. The BC government’s optimistic estimate is that five liquefaction “trains” with a combined gas throughput of 3.5 Bcf/d (to produce up to 25 million metric tons/year of LNG) will be online by 2023. The questions then are, what will it take for a project to advance, and which developers are making the most headway so far. Today, in the second of our Slip Sliding Away series, we start to assess BC’s top LNG export contenders, including a few late-arriving long shots that could surprise.
Exporting large volumes of Western Canadian gas as liquefied natural gas (LNG) would help resolve the region’s growing gas glut. The government of British Columbia has set a goal of having three major LNG export facilities in operation by 2020, and already is counting the money it expects to make in LNG-related taxes. But while more than a dozen liquefaction/export projects are under development in BC, none of them is a sure thing yet, and LNG sales and purchase agreements with utilities and others in the Asia/Pacific region have been slow in coming. Today we begin a series that considers whether our northern neighbor’s chance to supply gas to Japan, China, and South Korea may be Slip Sliding Away.
Natural gas production in the Gulf of Mexico (GOM) has been falling for 15 years, hurt first by hurricane-related rig damage, then more recently by the side effects of the BP/Macondo disaster, the on-shore sale boom, and the resulting sag in gas prices. But GOM gas production is about to uptick, due largely to two big, long-planned oil and gas projects finally coming online. Is the upcoming increase in gas production in the Gulf the first sign of resurgence, or is it the energy-sector equivalent of a “dead cat bounce.” In this blog, we consider what is ahead for gas production in the GOM.
The New England states and ISO-New England, which manages the region’s electric grid, are taking steps to keep the lights on during polar vortex events until new natural gas pipeline capacity through New England comes online. They also are making progress on an effort to have electric customers pay to help support new pipeline capacity developed specifically to serve gas-fired units. But while new gas-fired generation is being built in the region to replace older coal (and nuclear) capacity being retired, gas’s role in New England electricity production may well be stymied by a push to import large amounts of eastern Canadian hydroelectric power. Today we examine how New England is playing gas against hydro, and how the outlook for gas consumption by generators may be less bullish than some think.
The polar vortex events this past winter provided a jolting reminder to New England’s electricity sector that natural gas transmission infrastructure in the increasingly gas-dependent region needs further expansion. A comprehensive plan to ensure reliable electric supplies to Red Sox Nation for years to come is not yet in place, but more near-term fixes are being implemented and the elements of a long-term plan—new gas pipelines and new hydroelectric imports chief among them--are taking shape. Today we provide an update on gas-electric issues in New England.
For gas producers in Appalachia, this has not been such a good summer for basis – the price they get for their gas versus the benchmark at Henry Hub, LA. Basis in the eastern part of the Marcellus has been particularly weak, with negative differentials extending into New York. Even at some West Virginia points like Dominion South, producers have faced ugly basis for the past few months. But there are some points that have been relatively immune, including Columbia Gas TCO, which has been hanging in there at pricing pretty close to Henry. Even when parts of the Dominion South and TCO pipeline systems are on top of each other. Why are basis differentials in the Appalachian Mountains hopping around all over the place? Today we look into why some Northeast prices have taken a hit and others have not.
Natural gas prices for the nearby CME NYMEX futures contract at the Henry Hub in Louisiana have fallen by 38 percent from their high in February of $6.149/MMBtu to yesterday’s close at $3.847/MMBtu (July 24, 2014). Over the same period the price of CME NYMEX Appalachian coal has stayed virtually flat at $60/ton. So far falling gas prices have not increased power burn – the consumption of natural gas by power generators switching from coal. But natural gas prices in the Marcellus at Dominion South Point have fallen by nearly 60 percent since February to $2.46/MMBtu making natural gas a cheaper fuel than coal for power burn in that region. Today we discuss prospects for coal to gas switching this summer.
There is still a lot of summer left in Texas. Some say summer in the Lone Star state runs from Cinco de Mayo through the middle of the high school football season, which sounds about right. But so far at least, a combination of moderate electricity demand and relatively high natural gas prices has resulted in a decidedly non-stellar gas power burn. That is good news for those eager to see the state’s—and the nation’s—gas storage levels rebound from unusually low levels after the hard, cold winter of 2013-14. In this episode of our region-by-region series on gas power burn vs. gas storage rebuilding, we look at the Electric Reliability Council of Texas region, where gas-fired generation is king.
For companies whose success depends on low-cost natural gas, finding ways to mitigate gas price risk is critical. Using financial hedges is one way; another (though far less common) is acquiring working interests in gas production assets—that is, buying a physical hedge. Florida Power & Light, which consumes more gas than any other US electric utility, is getting into the act. But others—including a leading fertilizer manufacturer and a big steel maker—helped pioneer the approach. In this episode of our series on major gas consumers buying gas production assets, we look at how these earlier efforts are panning out, and how the flexibility built into the deals is paying off.
If a company expects to consume large volumes of natural gas for decades to come, why not remove at least some price risk by acquiring a working interest in gas production assets? Florida Power & Light (FPL), which burns more gas than any other US electric utility, recently asked regulators to permit the company to co-develop up to 38 gas production wells in the Woodford Shale with PetroQuest Energy, and to establish rules to let it make other, similar investments in the future. FPL is not first in its plan to acquire gas interests as a physical hedge; leading fertilizer and steel companies already have taken that plunge, with positive results. Today we examine what could become a trend: Major gas consumers buying a piece of the gas production action.
With U.S. natural gas production continuing to hit all-time records, the big question for the gas market is demand. Where is all that gas going to go? Well, we are pretty sure that most of the supply growth will be absorbed by the triad of new gas fired power generation, industrial demand and exports. The funny thing is that most of the volumes associated with these demand sources are located in one region – the southeastern U.S., with a heavy concentration of demand in Louisiana, home of the Henry Hub. This shift is turning what was a major supply area into an epicenter of natural gas demand, with the need for extensive new transportation paths into, rather than out of, the region. Today, we explore the implications of this transformation.
Growing Mexican demand for natural gas has been seen as a timely boon to Texas gas producers, which have been losing their Northeast and Midwest markets to the Marcellus and Utica. Gas exports to Mexico still are rising sharply, and several new gas pipelines are planned to move Eagle Ford, Permian and other US gas to Mexico. But the Mexican government is reforming its energy sector, a move that some hope will result in more aggressive development of domestic gas reserves. What does that mean for US gas exports to Mexico? Today we explore the changing lay of the land south of the border.
As we approach the 238th anniversary of our independence from the UK, is it possible the British Isles are about to become at least a bit dependent on us, natural gas-wise? With UK gas production falling, and with the aggressive actions of Vladimir Putin raising the specter of gas-supply interruptions from Russia to Western Europe, a case could be made that our jolly-good friends across the pond may be thinking risk-mitigation, supply diversification, and deals to buy more LNG from their former colonies. (They already plan to buy some.) But, as we discuss in today’s blog, gas prices in the UK are currently very low and the situation is, well, complicated.
