Mexico’s power sector is one of three major demand centers U.S. natural gas producers and pipeline projects are targeting, the other two being the U.S. power sector and LNG exports. U.S. natural gas exports to Mexico are up 20% year-on-year in 2016 to date to nearly 3.5 Bcf/d––more than double the export volume five years ago––and are poised to soar past 6 Bcf/d by the end of the decade. Mexico’s energy operators are on a tear adding new natural gas-fired power generation capacity and building a sprawling network of natural gas transportation capacity. But delivering increasing volumes of U.S. natural gas to Mexico will require substantial changes on the U.S. side as well, particularly in Texas. Today, we continue our look at plans for adding pipeline export capacity along the Texas-Mexico border.
Daily energy Posts
For the past month, WTI crude oil prices have averaged $49/bbl, trading within a relatively narrow $7/bbl range. Two years ago, this price would have been devastating for producers, but not so in late 2016. The crude directed rig count is up by 127 since May, +11 just last week. U.S. crude production is down about 1.2 MMb/d since April 2015, but over the past three months has stabilized at 8.5 MMb/d. On the gas side, since the second quarter of 2016 a combination of lower natural gas production and higher demand (from the power, industrial and export sectors) has worked off a big inventory surplus. Consequently, U.S. natural gas prices are up more than 70% since March, even considering the big price drop over the past week. NGL prices are at the highest value relative to crude for any October since 2012. Is this it? Is this what a Shale Era recovery looks like? In today’s blog, we consider a possible road map for the next couple of years. Warning, we have also included a short infomercial for RBN’s School of Energy next week in Houston.
The increasing availability of LNG at low and relatively stable prices, combined with the ability to expedite the installation of LNG receiving/regasification infrastructure, has the potential to spur faster growth in global LNG demand than many have been expecting. If that happens, the current––and still growing––glut in worldwide liquefaction capacity could shrink in a few years’ time, and a “second wave” of U.S. liquefaction/LNG projects could start coming online by the mid-2020s. Today, we conclude our series on U.S. LNG exports with a look at how low, stable LNG prices may turn the market toward supply/demand balance.
Several oil-sands expansion projects committed to when crude oil prices were double what they are today are finally coming online, and midstream companies active in Alberta are building new crude/diluent pipelines and storage capacity to keep pace. New storage caverns for natural gas liquids are also in the works, giving a much-needed boost to Canada’s Energy Province. Today we conclude our series on midstream infrastructure under development in or near Western Canada’s oil sands region that move and store hydrocarbon liquids.
After about four weeks offline for modifications and maintenance, Cheniere’s Sabine Pass liquefaction terminal in Cameron Parish, Louisiana began accepting nominal deliveries of feed gas starting last Friday, indicating the facility is due to ramp up to capacity any day now. Since the first export cargo in February, about 130 Bcf, or 0.6 Bcf/d, of natural gas has been delivered to the terminal. While those aren’t quite game-changing volumes yet, deliveries just prior to the outage were averaging more in the vicinity of 1.2 Bcf/d and indications are that deliveries could ramp up to more than 1.0 Bcf/d in short order with the restart and grow to more than 2.0 Bcf/d by the end of 2017. It’s clear that LNG exports are quickly becoming a prominent and inescapable feature of the U.S. natural gas market. Today, we wrap up our series on the growing impact of LNG exports on the U.S. supply/demand balance.
The past production profiles of the ten companies in RBN’s Gas-Weighted E&P peer group are dramatically different from the Oil-Weighted and Diversified U.S. E&Ps, boosting production by over 18% from 2014 to 2015, while the output of the other two peer groups was virtually flat. The group as a whole finally put on the brakes in early 2016 because of mounting debt and persistent low gas prices, cutting capital investment by 49% to dampen production growth to 4%. However, a small group of producers with solid balance sheets and strong hedging protection continue to target double-digit output growth. And with gas prices over $3.00/MMbtu, more growth is on the way. In today’s blog we discuss 2016 capital spending and production for our representative group of E&Ps whose operations are primarily focused on natural gas.
Many factors are weighed before a midstream company commits to building, or a shipper commits to shipping on, a major crude oil pipeline. Where is incremental pipeline capacity needed? What would be the logical origin and terminus for the pipeline? What should the project’s capacity be, and what would be the capital cost of building the project? Where the economic rubber really meets the road is the question of what unit cost––or rate per barrel––would the pipeline developer need to charge to recover its costs and earn a reasonable rate of return on its investment. A really important aspect of that is what the developer will be allowed to charge, once regulators get into it. Today we continue our review of crude oil pipeline economics with an overview of who regulates oil pipelines, how they do it, and what it means for rates.
In Part 1 of this series we discussed the fact that new pipeline development is driven by either need or opportunity, and more often than not, a combination of the two. The key question that pipeline developers and their customers (the shippers) have to consider before committing to build new capacity, we said, is whether it will “pay” to flow crude on the pipeline once it’s built––not just the first year or the first three, but for years if not decades to come. To answer this question, pipeline developers and shippers have to consider both current and future economics. There are three fundamental factors that drive pipeline economics: 1) future supply dynamics (and the resulting price impact) at the origination point (Point A); 2) future demand (and price) at the destination point (Point B); and 3) the transportation cost to flow crude from Point A to Point B.
Handling the flood of Marcellus/Utica gas headed to Gulf Coast LNG export terminals and to Mexico will require pipeline reversals and expansions, new pipe and a coordination of interstate and intrastate pipeline capacity. That’s a tall order in itself, but there’s more: Texas’s intrastate pipelines operate under an entirely different set of regulations than their interstate counterparts––different rules on pipeline tariff rates, pipeline rules, permitting, eminent domain, you name it. In today’s blog we continue our look at developmental history of the Lone Star State’s two gas pipeline systems––one regulated in Washington, DC and the other in Austin––and how it may affect the transformation of the overall natural gas transportation grid.
There is a natural gas renaissance of sorts happening south of the U.S.-Mexico border. The state-owned Comisión Federal de Electricidad (CFE) is investing heavily in expanding and modernizing its power generation fleet with thousands of megawatts of new, natural gas-fired power plants, and the energy secretary also last October put forth an aggressive five-year plan to build out a pipeline system to supply growing gas-fired generation demand. Mexico’s power generation demand is increasingly a target for U.S. gas producers and pipeline projects. At the same time, as we discuss in Part 2 of RBN’s Miles and Miles of Texas Drill-Down Report published last week, a good portion of this new demand is relying on — and in large part has been driven by — availability of low-priced gas from the U.S. via Texas and the U.S. Southwest states. But there is a lot that needs to happen on both sides of the border over the next few years to facilitate this mutually beneficial relationship. Already since October, Mexico’s newly appointed independent pipeline operator, Centro Nacional de Control del Gas Natural (CENAGAS), has pulled back on the pipeline buildout. Today, we begin a two-part series on how plans to facilitate this new demand are progressing, starting on the Mexico side of things.
Texas’s vast natural gas pipeline network is undergoing a major transformation to enable gas from the Marcellus/Utica shale plays to flood south/southwest into and through Texas to LNG export terminals and to Mexico. To grasp the complexity of the task at hand, it is critically important to understand how Texas’s “spaghetti bowl” of interstate and intrastate pipeline systems evolved in parallel but under very different regulatory constructs, and with the intention of serving very different market needs. In today’s blog, we begin an examination of the state’s two pipeline systems––one regulated by the Feds in Washington, DC and the other by the Texas Railroad Commission in Austin, TX––and why the intrastate system has taken on a new significance for U.S. natural gas markets.
Developing a multibillion-dollar liquefaction/LNG export project takes perseverance and patience––and having good luck wouldn’t hurt. The “first wave” of U.S. projects is now cresting; the first two liquefaction “trains” at Cheniere Energy’s Sabine Pass LNG facility are essentially complete, and 12 other trains are under construction and scheduled to come online in the 2017-19 period. But what about the “second wave” of projects that was supposed to be arriving soon thereafter? Today we continue our series on the next round of U.S. LNG projects with a run-through of the projects themselves and a look at how (despite the current market gloom) there is at least some cause for optimism that a few may get built by the early 2020s.
Oil-sands expansion projects coming online and the resulting need for more diluent are among the drivers behind a number of midstream infrastructure projects in the province of Alberta, including natural gas processing plants and fractionators; oil and diluent pipelines; and oil/NGL storage facilities. The total volume of work is surprising, considering the fact that oil-sands production economics are iffy right now, if not downright upside down. Today, we continue our look at midstream projects under development within Canada’s Energy Province, this time focusing on gas processing and fractionation facilities.
Over the next three years, 16 pipeline projects are in the works to add more than 14 Bcf/d of new take-away capacity to move Marcellus/Utica natural gas to the south and west, relieving takeaway capacity constraints that have plagued the Northeast since 2012-13. Much of this gas will be moved to the Gulf Coast, primarily via reversals of pipes that traditionally transported gas north and east, and will target rapidly growing LNG and Mexico export markets. But few of these pipeline projects get the gas all the way to those export outlets. The new supplies must traverse “Miles and Miles of Texas” (and Louisiana) to reach the export gateways and along the way deal with shifting production trends within the state, pipeline systems that are "telescoped the wrong way" constraining capacity of the Texas pipeline grid, and unique regulatory considerations associated with Texas intrastate pipelines. These issues are addressed in RBN’s latest Drill Down Report, highlights of which we discuss in today’s blog.
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.
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.
A group of 15 diversified exploration and production companies we have been tracking collectively has slashed capital expenditures by 70% since 2014, but so far the cumulative effect of these spending cuts has been only a 5% decline in production. Now, several of these E&Ps––especially those targeting the Permian Basin and the SCOOP/STACK plays––are planning capex increases and/or expecting production gains. Today we discuss 2016 capital spending and production for a representative group of E&Ps whose operations are roughly balanced between oil and natural gas.