It’s been a volatile summer for U.S. natural gas. The CME NYMEX front month contract spiked from $1.96/MMBtu in late May to $2.99 on July 1, up more than 50% in just over a month. Since then the price has headed mostly south, closing at $2.62/MMBtu on Tuesday, down $.37/MMBtu from its summer high a few weeks ago. As often is the case, the primary culprit has been weather. But for the first time, a new factor is starting to have an impact: LNG exports. During August, approximately 30 Bcf of gas will likely flow into Cheniere Energy’s Sabine Pass for now-routine LNG exports from Train 1 and the initial volumes needed for the start-up of Train 2. The more recent decline in gas prices just happened to follow the announcement that the entire Sabine Pass LNG facility will be shut down for several weeks starting next month for maintenance and to address a design issue. Was LNG a factor in the price decline? Hard to say. We may get a better sense of the market impact of LNG exports when the plant starts back up. At that point even more gas –– up to 1.25-1.5 Bcf/d in total –– could be sucked out of the market, possibly taking a 125-Bcf bite out of supply by the end of this year. The gas market has changed. From here on out, you won’t be able to understand the U.S. natural gas market without a solid grasp of LNG export dynamics. Today, we begin a two-part series on how international demand for U.S.-sourced LNG will have an increasing effect on gas supply, demand and price.
Of the 18 Bcf/d of incremental pipeline takeaway capacity out of the Marcellus/Utica that is due to come online over the next few years, nearly one-third is heading to demand markets in the Southeast via the Atlantic Coast states. The southeastern U.S is a fast-growing region, and its residents and businesses are becoming increasingly dependent on gas-fired power generation –– a real boon to Northeast gas producers. Today, we continue our look at how pipeline takeaway capacity will stack up against Northeast production over the next several years, this time with a focus on projects that will move gas to the Southeast.
Given their proximity to the Marcellus and Utica shale regions, the Midwestern states and Ontario would appear to be logical consumers of the increasing volumes of natural gas being produced in Pennsylvania, West Virginia, and eastern Ohio. The catch has been that the pipelines built years ago to serve the Midwest and Canada’s most populous province were designed to move gas into those regions from western Canada, the U.S. Gulf Coast, the Midcontinent and the Rockies, not the nearby Marcellus/Utica. That’s being corrected. Today we continue our look at how pipeline takeaway capacity will stack up against Northeast production over the next few years, with a focus on the Midwest and Ontario.
The Northeast natural gas market in recent years has been defined by its lack of sufficient infrastructure for growing production in the region. Pipeline takeaway capacity constraints have restricted production growth and driven Northeast prices to the lowest in the country. But could that soon change? With drilling activity slowing and 18 Bcf/d of takeaway due in-service over the next few years, is it possible the Northeast takeaway capacity will get overbuilt? Today, we continue our look at how pipeline takeaway capacity will stack up against Northeast production.
Natural gas producers in Western Canada are still struggling to find new markets to replace those they’ve lost to Marcellus/Utica producers in recent years. It hasn’t been easy, and they certainly haven’t been helped by the high cost of transporting gas to Ontario and the Upper Midwest, by the failure of LNG export projects in British Columbia to advance, or by the collapse of oil prices that has slowed growth in the oil sands sector (a huge consumer of gas). Despite the gloom, though, there are at least some rays of hope. TransCanada is considering big cuts in pipeline tolls in exchange for commitments to long-term deals. It’s also possible that at least one BC LNG export project may become a reality by the early 2020s. And some gas producers in the Montney shale region in the Canadian Rockies are focusing on areas where they also can produce vast amounts of condensate for use as diluent in the nearby oil sands region. Today, we provide an update on the ongoing (and often frustrating) efforts to expand gas production in BC and Alberta.
The latest natural gas transaction data from the Federal Energy Commission (FERC) shows the natural gas market is increasingly relying on published index prices for transacting physical volumes for day-ahead and month-ahead deliveries. Index prices — volume-weighted averages of all eligible prices reported to index publishers by location — are considered representative of the market and mitigate some of the perceived price risk associated with “fixed-price” deals, in which the price is independently negotiated between counterparties. But in order to make their indices representative and grounded in market reality, publishers — or price reporting agencies (PRAs) — rely strictly on prices from those independent fixed-price deals to set the index in the first place. As more of the deals done are based on index, what happens to the index itself? Today, we continue our review of natural gas transactional data and what it says about how the market is evolving.
Over the past five years, essentially all of the growth in U.S. natural gas production has come from the Marcellus/Utica shale regions in the Northeast, constrained only by takeaway capacity, and as of 2015 the region began producing more gas than it can consume almost all year round. There are about two dozen pipeline projects planned to come online totaling nearly 17.5 Bcf/d over the next few years to help Northeast producers target demand in other regions, namely growing power generation demand, LNG export markets along the U.S. Gulf Coast, (see Back Down South), and Mexico via Texas. But since mid-2014, drilling activity has slowed dramatically across the U.S., including the Northeast, and output in Marcellus/Utica has flattened out. Is it possible that the market is headed toward an overbuild situation in which Northeast takeaway capacity will end up far exceeding regional production? That has certainly happened in just about every other segment of the U.S. energy market — from pipes moving gas east out of the Rockies and Texas, to crude by rail, to crude oil pipelines to the Gulf –– with important implications for the market. Could it happen in the Northeast? Today, we begin a series on the prospect of an overbuilt Northeast gas market.
Until a few years ago, a good bit of the natural gas produced along the Gulf Coast was piped long-distance to warm homes and businesses in the Northeast and the Midwest. Now, though, cheap-to-produce Marcellus and Utica shale gas has come to dominate gas heating and power markets from Boston to Cleveland, and Northeast-sourced gas is starting to move into Louisiana and Texas, competing head-to-head with Gulf Coast production. With Marcellus/Utica gas production in ascendance, what will be the fate of all the gas still being produced along the U.S. Gulf Coast? That’s the subject of RBN’s latest Drill Down Report, highlighted in today’s blog, which describes the battle lines being drawn and the important roles LNG exports and Mexican demand will play in keeping U.S. gas markets in balance.
After averaging more than a nickel below Henry Hub all this year, the California Border natural gas price spiked to 66 cents/MMbtu above Henry on Friday. This kind of price volatility is no surprise to anyone following the radical shifts in California energy markets, starting five years ago when the state legislature enacted its 33%-by-2020 renewable portfolio standard (RPS) law. By mid-2015, more than 14,000 MW of new solar and wind power had pulled down gas demand in California to the point that natural gas prices at the SoCal Border were averaging a negative basis to Henry Hub. Still not satisfied, last year California legislators voted to establish a 50% renewables target for 2030. On top of it all, the West Coast was coming up on a La Niña year that would bring more rain –– and hydroelectric generation –– to the Pacific Northwest and eventually into California. With all that renewable power (solar, wind and hydro), California seemed headed for an unprecedented period of low gas prices, but it did not turn out to be so simple. In today’s blog, we continue our look at California’s power and gas markets with the events and drivers that shaped late 2015 and the first six-plus months of 2016, and consider what’s to come.
California energy markets look quite a bit different today than they did five years ago when the state enacted a renewable portfolio standard (RPS) law that requires every utility and other electricity retailer to serve 33% of their load with renewable energy by 2020. Since then, California has seen huge changes in its energy balances – it shut down the nuclear generating plants at San Onofre, regulators expedited the build-out of new transmission lines to get more wind and solar power into the market, the state implemented a carbon cap-and-trade program, the legislature increased the RPS target to 50%, and SoCal Gas’s Aliso Canyon natural gas storage facility sprung a leak. Today, we look at the changes in California’s energy markets since 2011, and what they mean for future developments in a state far out front in the adoption of renewables and environmental regulation.
Energy Transfer Partners (ETP) is the nation’s second-largest master limited partnership (MLP), with a market capitalization of $19.6 billion, $39.7 billion in 2015 revenue and $8 billion in 2015 capital investments. ETP’s general partner is Energy Transfer Equity (ETE), whose once-promising merger deal with Williams bit the dust in June. ETP’s extensive holdings include several major interstate and intrastate natural gas pipelines, midstream natural gas services, and natural gas liquids (NGL) pipelines and services; it also holds approximately 27.5% of the limited partner interests and all of the general partner interest in Sunoco Logistics Partners (SXL). With ETP’s size, its huge portfolio of midstream assets, and its high-profile general partner, the MLP was an obvious choice for our Spotlight Report series. Today we summarize Part Two of our ETP Spotlight Report, which focuses on the company’s Midstream and Liquids segments.
Since the first LNG ship left its dock in February, Cheniere’s Sabine Pass LNG terminal has exported 17 cargoes containing the super-cooled, liquefied equivalent of over 50 Bcf of natural gas from the first of six planned liquefaction “trains.” And in a monthly progress report filed with the Federal Energy Regulatory Commission last month, Sabine Pass said it expected to begin loading a commissioning cargo from Train 2 in August, with commercial operation of that facility starting as early as September. In today’s blog we provide an update of Sabine Pass’s export activity, as well as the impact on the U.S. gas flows and demand.
Published index prices are the mainstay of most energy commodity markets. That is certainly true of U.S. natural gas. Of all natural gas deals done in the U.S. last year, almost 80% of the total transaction volume was priced based on an index published by one or more of the industry trade publications covering U.S. gas, such as Natural Gas Intelligence, Platts and Argus. But there could be a problem brewing. For publications to compute an index price there must be enough deals reported that are NOT priced on an index - called an “outright” or “fixed” price. If all, even most deals are done at an index price, there can be no index. Does that sound a bit circular? Well it should. In today’s blog we delve into the sometimes arcane world of commodity index pricing. Arcane maybe. But with $150 million in U.S. natural gas moving each day based on index deals, it is worth understanding how all this works, and how things could go awry. Fortunately, it is possible to know quite a bit about how the U.S. natural gas market uses index transactions.
We talk a lot here in the RBN blogosphere about the bearish market effects of the Shale Revolution, and frequently highlight the U.S. Northeast natural gas region — rapidly growing gas production from the Marcellus/Utica; oversupplied, trapped-gas conditions; and resulting regional price discounts. These dynamics are driving massive investments in pipeline reversals, expansions and new capacity to move the gas to market. Northeast producers are counting on that increase in takeaway capacity to relieve price pressure and balance the market. But all this gas moving out of the region needs a home. Fortunately, new demand is emerging, from exports (to Mexico and overseas LNG) and into the U.S. power sector. One of the big growth regions is the U.S. Southeast, where power utilities are investing heavily in building out their fleet of gas-fired generation plants and are banking on this new, unfettered access to cheap Marcellus/Utica gas supply. Today’s blog provides an update on power generation projects coming up in the southern half of the Eastern Seaboard, based on a recent report by our good friends at Natural Gas Intelligence — “Southern Exposure: Gas-Fired Generators Rising in the Southeast; But Will Northeast Gas Show Up?”
With liquefaction capacity and supply of liquefied natural gas on the rise and LNG demand flat, prices for super-cooled, liquefied gas are low and may well stay low into the early 2020s. That’s a concern for LNG suppliers, who (like all suppliers) would prefer it if demand was soaring and supply was a little tight. There are some rays of hope, though, in what many have seen as a gloomy time for the LNG sector. After all, with spot LNG prices below $5/MMBtu (far lower than they were 30 months ago) and ample supplies of LNG available, a growing list of nations are looking either to become LNG importers or to significantly expand their LNG imports. Today, we continue our review of the LNG market with a look at the new demand that may be spurred by supply surpluses and low prices.