The inventory of drilled-and-uncompleted wells (DUCs) in the U.S. Lower 48 grew by nearly 1,900 between the months just before oil prices and rig counts collapsed and early 2016—a 50% increase in a roughly two-year period, according to new DUCs data in the Energy Information Administration’s (EIA) September Drilling Productivity Report (DPR—See the DPR DUC report here.). Since January’s peak of nearly 5,600 DUCs, producers have been working down the national inventory of DUCs, with the DPR showing the overall count closer to 5,000 as of August (2016) ––but that is still up more than 1,300 from the December EIA’s 2013 baseline. This incremental growth in the number of “dormant” wells is key to understanding and predicting how long production can remain supported or grow in a low-rig count environment. Moreover, there are regional differences in the DUCs inventory counts and trends that provide critical insights on how various market factors are impacting drilling activity. Today, we walk through the EIA DUCs data for each of the producing regions.
Daily Energy Blog
The “first wave” of liquefaction/LNG export projects in the U.S. is cresting. Two new liquefaction trains in Louisiana are already producing liquefied natural gas, and a dozen other trains are under construction and scheduled to begin commercial operation in the Lower 48 over the next three years. The problem is, these multibillion-dollar facilities––planned when LNG market dynamics were much more favorable––are “rolling in” as the global market faces a supply glut, weak LNG demand growth, and low prices. Today, we begin a series on the next round of U.S. LNG projects and how soon market conditions might improve enough to justify building them.
For some time now, discussions about the possible development of Canadian liquefaction/LNG export terminals have focused on the Western Canadian coast in British Columbia––partly because most of Canada’s natural gas reserves are nearby in northeastern BC and in Alberta, and partly due to Asia being a primary LNG target market. . But it could be that liquefaction/LNG export projects in Eastern Canada may make more sense. In today’s blog, “So Far Away –Sending Western Canadian Natural Gas East for Export as LNG,” LNG Ltd.’s Greg M. Vesey considers the rationale for piping Western Canadian natural gas long distances to Quebec and the Canadian Maritimes for export as LNG.
At long last, the Energy Information Administration (EIA) has reported an “official” estimate of the U.S. drilled-and-uncompleted well (DUC) inventory as part of its monthly Drilling Productivity Report. DUCs are a critical factor in forecasting production trends, as many of these wells are likely to be some of the first to come online as soon as prices move higher and thus have the potential to boost production quicker and easier than would otherwise be the case. However, the number of DUCs has been a difficult thing to measure, though not for lack of trying. There are, in fact, widely varying counts from many different sources circulating in the industry. Today, we begin a short series on these latest DUC counts and their potential implications.
Natural gas production volumes in the Permian Basin are very near the all-time record of 6.9 Bcf/d set last September, and crude oil and gas producers alike see nothing but blue skies for the highly prolific West Texas/Southeast New Mexico play. The Permian already has a lot of gas processing capacity, but a good bit of it is older, and parts of the region—especially the super-hot Delaware Basin—need more of the big, efficient cryogenic plants that can process 100 to 200 MMcf/d. Today, we continue our review of gas production and processing in the biggest U.S. gas-producing region that is not named Marcellus.
Planned liquefaction/LNG export facilities along the South Texas coast and growing demand from Mexico’s electric power sector together will require several billion cubic feet/day of additional U.S. natural gas over the next three to five years. Gas producers from the Marcellus/Utica to the Permian are targeting these markets, but there are questions regarding whether the Lone Star State’s existing pipeline infrastructure is sufficient to deliver all that gas to these critically important export markets. Part of the solution will be optimizing the use of Texas’s impressive—but sometimes misunderstood intrastate pipeline networks, particularly the far-reaching systems operated by Enterprise, Energy Transfer and Kinder Morgan. Today, we discuss one part of the solution, an inexpensive but impactful Kinder Morgan project that will enable about 1 Bcf of natural gas from various sources to reach South Texas LNG exporters and Mexico on KM’s intrastate system.
Despite the doom and gloom that many see in the global LNG market –– too much supply, weak demand growth, and low LNG prices –– the possibility remains that the sector may offer the opportunity for low-cost, highly responsive market participants to do quite well, and even thrive. How can that be? After all, we’ve just seen another year of low crude oil prices resulting in very low oil/natural gas margins, and the expectation of high oil/gas margins were critical in supporting the development of many U.S. liquefaction/LNG export projects. But a combination of responsive demand, low cost infrastructure development and the possibility that number of exporting countries could run out of gas at or near the end of their existing contracts could change the outlook for ongoing LNG export development. Today, we look at the LNG market in the context of themes discussed at the North American Gas Forum (NAGF). Warning: this blog includes a plug for this year’s NAGF conference.
California and New England are two of the nation’s quirkier regions when it comes to energy –– and we mean that in the nicest way possible. So maybe it’s not too surprising that, at a time when the U.S. is just beginning a big push to export natural gas as LNG, the Golden State and “Yankeeland” (as some still refer to New England) are turning to imported LNG to help them deal with possible gas shortages during peak demand periods this coming winter. In neither case is liquefied natural gas considered to be a long-term fix, but –– for now at least –– LNG may be playing a role in keeping the pilot lights lit and the electric lights on. Today, we look at how the stockpiling and use of LNG can still make sense in a nation with an abundant supply of gas.
Of all the demand markets in the U.S., the biggest prize eyed by Marcellus/Utica natural gas producers is the Gulf Coast region, where a combination of industrial demand, LNG exports and power generation projects is driving a need for more and more gas. And beyond the U.S. Gulf Coast states, there lies still another market capable of gobbling up even more of the excess Northeast gas supply: Mexico’s rapidly growing gas-fired generation sector ––that is, assuming pipelines in Texas can get it all the way there. There is over 4.0 Bcf/d of Marcellus/Utica-to-Gulf-Coast takeaway capacity planned to be completed over the next few years. Today, we look at the status and timing of Northeast pipeline takeaway projects targeting the Gulf Coast.
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.
