Winter Demand

The latest weather forecasts for the second half of December have taken the edge off the U.S. natural gas market and reduced the chance of a true doomsday storage scenario. But U.S. gas storage inventories nonetheless remain at historically low levels, and long-term weather forecasts are notoriously fickle. So this winter could still see a resurgence in volatility before the market finds a balance. And while Henry Hub prices went on a wild ride earlier this month before settling back in below $4/MMBtu, for most of December thus far, Eastern gas prices have traded at levels that make LNG exports from there uneconomic. In today’s blog, we continue our review of the winter U.S. gas market with a closer look at how Cove Point Liquefaction (CPL) might respond to high prices.

Reliably low Henry Hub natural gas prices are a primary, long-term driver of U.S. LNG exports. But prices were up as much as 40% during November and, with gas inventories unusually low, Henry prices could spike considerably higher if winter weather continues to come in colder than normal. Which raises the question, how high would gas prices need to go before U.S. liquefaction becomes the lever that balances the U.S. gas market? The short answer is, it depends on where the LNG is headed — and lately, a lot more is bound for Europe. Today, we continue our review of the current gas market with an analysis of LNG variable costs and UK National Balancing Point prices, and how they will help determine LNG export volumes if U.S. gas prices spike.

The U.S. natural gas market enters winter this year in a delicate balance: production is at an all-time high and growing fast, but gas storage inventories are well below year-ago levels and the five-year average — and at an all-time low relative to consumption. If winter weather is normal or mild, the U.S. gas market will likely begin to settle into a period of sub-$3/MMBtu prices. But this year’s low inventory level means that colder-than-typical weather this winter could spell more gas price upside than the market has seen in many years. Today, we continue our review of the current gas market with a look at the relationship between gas- and coal-fired generation, and at how the combination of low gas storage inventories and low coal stockpiles might play out this winter.

U.S. natural gas supply continues to set all-time records, and strong production growth is expected to continue. Most of these supply gains will come from the Northeast, where another round of pipeline capacity additions are being completed. But despite all this incremental gas output, a combination of cold weather last winter and hot weather this summer means that U.S. gas storage inventories are likely to end the fall season at their lowest levels since 2005. And even this comparison understates how low inventories are — gas consumption has grown dramatically in the past 10 years, and storage inventories are at all-time lows when considered in terms of the number of days of average consumption. Today, we begin a series on the implications of historically low gas storage inventories, including what the gas market might look like if this winter turns out to be colder than normal.

U.S. natural gas production has been essentially flat this summer as many producers curtailed, deferred or delayed drilling and well completions earlier in the year. However, some of the same producers, particularly in the Northeast, in their most recent earnings calls, indicated they expect to meet their 2015 production targets by increasing output this winter. In today’s blog, we look at how and why producers defer production and the potential impacts on the market in Q4.

Fast-rising propane production in the Marcellus and Utica shale plays, the reversal and repurposing of the Cochin Pipeline and other factors have exposed gaps in the midstream infrastructure that shuttles and stores large volumes of propane within the U.S.  Perhaps one of the most obvious of those gaps is the inability to pipe propane from Ohio/West Virginia/southwestern Pennsylvania to big propane consumption areas in the nation’s heartland.  Enterprise Products Partners has been working on a fix—a relatively short pipeline across northern Illinois that it seems would add a lot of flexibility per mile.Today, we consider Enterprise’s planned propane takeaway project and how it might affect the propane market.

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.

Does it make sense to build natural gas pipeline capacity that will only be used a few weeks a year? That’s a question that continues to spark debate in New England, where the existing pipeline network is sufficient most of the year but unable to supply the region’s growing number of gas-fired power plants during the coldest winter days. What’s the answer? Building gas pipeline capacity that will remain largely unused? Relying on oil and LNG as a permanent gas-supply backup for power generators? Or maybe building pipeline capacity to provide not only peak, wintertime service to generators but off-peak service to LNG exporters? Today, we continue our look at a vexing dilemma with major implications for Marcellus gas producers.