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.
The international market for liquefied natural gas (LNG) is an inherently risky business where returns depend on paying back huge upfront infrastructure investments with cash flows based on volatile energy prices. Tectonic shifts in the market are giving North American LNG exporters and natural gas producers an opportunity to become pivotal players. The world is on the cusp of an LNG supply glut that may last several years, and the old order of long-term supply contracts with prices indexed to oil is being phased out in favor of a market structure that features more destination flexibility, more spot market sales—and, for U.S. and maybe some Canadian and Mexican LNG exporters—more liquefaction “tolling” deals with LNG prices linked to gas. Today, we continue our look at what these changes mean for the North American energy sector.
The U.S. Northeast natural gas market thus far has been able to offset local production growth primarily by pushing out supply from other regions. But recent trends in pipeline flows suggest that for the first time, net flows into the Northeast will fall to zero this summer, marking the end of displacement. Meanwhile, regional natural gas production could be as much as 4 Bcf/d higher this summer than last. The result could put this summer’s prices in a precarious position further challenging producers suffering in an oversupplied market. . Today’s blog looks at recent trends in Northeast flows and implications for prices this summer.
Yesterday the Energy Information Administration (EIA) released their 2015 Annual Energy Outlook that forecasts U.S. demand for natural gas to increase by as much as 42% from 2014’s 26 TCF/year to 37 TCF/year by 2040. That translates to 101 BCF/d and is predicated on long term supplies of relatively cheap gas! Can the U.S. produce that much gas over the long term? Last week a group that is little known outside the natural gas industry – the Potential Gas Committee (PGC) provided an answer to that question when they announced their latest estimate of economically recoverable natural gas resources in the U.S. Today we analyze the impact of the latest PGC estimate and its long-term implications for the natural gas industry.
MarkWest Energy Partners is clearly the big dog in the Marcellus/Utica, with by far the largest gas processing and fractionation capacity there.
The fast-growing need for natural gas processing and fractionation capacity in the Marcellus/Utica is creating tremendous opportunities for midstream companies. But determining which assets to develop and when to develop them is complicated by the volatility of hydrocarbon markets, and by the fact that the region has only minimal NGL storage capacity. In today’s blog, we continue our in-depth review of NGL-related infrastructure in the Upper Ohio River Valley with a look at Blue Racer’s existing and planned assets there.
This year’s natural gas power burn is shaping up as a record-breaker, mostly because gas consumption needs to rise sharply to offset increased production and the power sector is best able to ramp up its gas use. But what will it take, gas-price-wise, for utilities and independent power producers to increase their 2015 power burn by 2, 3 or even 4 Bcf/d this year? And which parts of the U.S. are likely to see the most dramatic coal-to-gas switching? Today we continue our look at this year’s power burn and its significance to Marcellus and other gas producers.
Natural gas processing in the Marcellus and Utica plays has quickly become a much larger—and more complex—business as major players race to keep up with fast-rising capacity needs and to ensure that the various elements of their infrastructure operate as an integrated, well-oiled “machine”. And, in a region with only minimal NGL storage capacity, one of that machine’s most important characteristics must be an ability to deal with all the “what-ifs” that could otherwise lead to logistical chaos, particularly those issues dealing with ethane. Today, we continue our in-depth review of Marcellus/Utica NGL infrastructure with a look at MarkWest’s innovative NGL network and distributed de-ethanization system.
The Energy Information Administration’s (EIA) latest U.S. monthly crude production statistics published March 30th show January production down 135 Mb/d versus December 2014, the largest month-on-month decline since June 2011. There was an earlier warning sign from EIA. The agency’s Drilling Productivity Report (DPR) published March 9th predicted that production would decline in April in three major U.S. oil production regions – Bakken, Eagle Ford and Niobrara. Since oil and NGL prices crashed last fall, the market has been watching with bated breath for the first signs of a production slowdown. Certainly rig counts have nosedived amid producer budget cuts in 2015. But are we really seeing the beginnings of a long-term slowdown just yet? Was the DPR a harbinger of the January production decline? The clues lie within the DPR report. Today’s blog parses DPR methodology, assumptions and risks as well as contributing market factors to get to the bottom of what is driving those reported production declines.
Natural gas liquids production in the Utica and “wet” Marcellus has taken off like a rocket, and all that ethane, propane, butane and natural gasoline needs to be either moved out of the region or consumed there. That presents a real operational challenge to midstream companies, mostly because the Upper Ohio River Valley offers very little of the NGL storage capacity that Mont Belvieu—the center of the NGL universe—has in spades. Storage is the mechanism that helps balance out supply and demand on any given day. How can the nation’s fastest-growing NGL production play function without the luxury of significant NGL storage? Today, we continue our look at infrastructure development in the region.
Producers in the Bakken are making progress reducing the natural gas flaring that had put an unwelcome spotlight on the region. The fix, spurred in part by tightening regulations, is being made possible by the addition of new gas processing capacity and increased efforts to use “stranded” gas at the well-site. (A drilling slowdown associated with soft crude prices is providing an assist.) Today, we take a fresh look at what’s been happening on the flaring front in western North Dakota, where gas flares still light the nighttime sky.
The U.S. Midwest region is slated to get an infusion of cheaper Northeast natural gas supply later this year as the first of five new westbound pipeline expansions is expected to begin service in November. Already a couple of projects are moving gas to the Midwest from the Northeast. The Northeast-to-Midwest capacity will have a huge impact on the Midwest supply stack and consequently on prices. The Chicago Citygates forward curve shows prices flipping from premiums to discounts later this year. Today’s blog continues our look at how new pipeline capacity will re-shuffle the Midwest’s supply stack and change regional pricing.