Daily Energy Blog

The US natural gas market is in a precarious state. CME/NYMEX futures contract prices have been settling at historic lows for this time of year. Producer returns are dismal in most shale basins.   Yet production volumes remain robust, and the supply/demand balance is way out of whack. The surplus in storage is soaring at more than 500 Bcf above last year and more than 400 Bcf above the 5-year average. It’s clear something has to give. But how will the imbalance get resolved and how will the resolution impact the price of natural gas? To help you navigate market signals and stay ahead of upcoming turning points, today we introduce our new daily NATGAS Billboard: Natural Gas Outlook report featuring storage and price forecasts plus a daily market outlook.

Yesterday (January 14, 2016) Cheniere Energy announced a delay to the first shipment of liquefied natural gas (LNG) out of its Sabine Pass liquefaction/export terminal in Louisiana that was expected this month (January 2016), but is now planned for late February or March of this year. Meanwhile, LNG demand has leveled off. LNG prices have collapsed and stayed low. And a slew of liquefaction capacity planned and committed to years ago—Sabine Pass and other U.S. projects included—is coming online, suggesting an LNG supply glut that could last into the early 2020s. But are the LNG market’s prospects really as grim as all that sounds? Today we begin a review of recent developments in the LNG market, and consider their implications for U.S. natural gas producers, midstream companies, and LNG exporters.

The U.S. natural gas market is facing an ultimatum. Natural gas storage inventories are carrying such a daunting surplus, that prices already at 21-year lows for December, seem primed to go even lower should supply or demand fail to cooperate and balance the market. A warm winter so far and the very real prospect of hitting a storage celling before next winter mean that something has to give.  Today we wrap up our series on the gas supply/demand balance with a look forward to how 2016 could pan out.

The natural gas market just managed to dodge a collision this summer between excess gas supply and available storage capacity. Now about a month into the gas winter season, storage inventories are still near record levels after topping 4.0 Tcf just two weeks ago. The Henry Hub CME/NYMEX January contract price closed yesterday (December 2, 2015) at $2.165/MMBtu, historically low even as we head into the highest demand months of the year. It’s now clear that 2016 will inherit this bearish market unless there is a Polar Vortex Tsunami in January and February. But what does this mean for producers, and how much will demand respond? In today’s blog, we begin a series on potential scenarios for the 2016 gas market balance.

A highly anticipated event in the U.S. natural gas market is when the Northeast region crosses the line from being a net gas taker from, to becoming a net gas supplier to, the rest of the country. Ever since the Marcellus and Utica shale began ramping up, Northeast production has been on a course to eclipse regional demand. RBN predicted 2015 would be the tipping point when the supply-demand balance would finally reverse on an annual average basis, marking a new phase for Northeast prices and for the U.S. gas market as a whole. We’ve seen that despite capitulating oil prices, capital budget cuts and lower rig counts, Northeast production has continued to reach new highs in 2015 – beating the record again this past Sunday (November 22,2015) at 20.3 Bcf/d according to Genscape. But regional demand also has been at record high levels. Today with less than two months left in the year, we determine whether the Northeast region will – or already has - crossed the threshold to net supplier in 2015.

Within and near the Marcellus and Utica shale plays, power plant developers are building more than a dozen new natural gas-fired generating units, mostly combined-cycle plants that can operate essentially around-the-clock. This construction boom, spurred by a combination of abundant, low-cost gas and the regulation-driven retirement of scores of older coal plants, is boosting gas consumption close to gas production areas and reducing—at least a bit—the surplus gas volumes that Marcellus and Utica producers and marketers need to move to markets outside the region. Today, we examine the race to build new power plants near production areas in the Northeast, and consider what the resulting local gas consumption might mean for the region’s gas prices and pipeline needs.

As we stated in Part 1 of this series, New York City will need increasing amounts of natural gas as it continues its shift from oil-fired power plants and oil-based space heating. New gas pipeline capacity to and through the Big Apple has been added as recently as May 2015, but the nation’s largest city still faces wintertime gas-delivery constraints that cause costly spikes in gas and power prices. Given the challenges of adding new pipeline capacity in one of the most densely populated parts of the U.S., developer Liberty Natural Gas is planning an offshore liquefied natural gas terminal that by late 2018 would inject gas into the city’s existing pipeline network on an as-needed basis. Today, we continue our look at the economics of using imported LNG to supplement gas supplies in the Northeast.