Providing the capacity to transport Marcellus/Utica natural gas to and through the state of Texas to LNG export terminals and to Mexico will require pipeline reversals, new pipe and other enhancements along a combination of interstate and intrastate lines. In many ways, the long-distance part of the job––the reversal of large-diameter pipelines between the Northeast and the Lower Mississippi Valley––is the more straightforward; the greater challenge will be reworking the complicated pipeline networks between the Texas/Louisiana state line and the U.S./Mexico border. Today we review Texas pipeline projects being planned to allow increasing southbound flows of Northeast gas.
A total of 13 U.S. liquefaction trains with a combined capacity of about 58 MTPA (~8 Bcf/d) are either in early stages of operation along the Gulf Coast or under construction and scheduled to be online by the end of 2019. Of that, about 3.2 Bcf/d is being developed along the Texas Gulf Coast. Beyond that, a “second wave” of liquefaction projects is lining up, with as much as an additional 11 Bcf/d of capacity proposed for Texas by the early 2020s. While many of these second-wave projects may not get built, those that do will require the construction or rejigging of hundreds of miles of pipelines, particularly along that Gulf Coast corridor. Several of the first and second wave liquefaction projects have proposed to build laterals that connect to and branch out from nearby long-haul pipelines, creating new Gulf Coast-bound delivery points for Eagle Ford shale gas as well for supply that will eventually move south from supply basins as far north as the Marcellus and Utica shales. Today, we take a closer look at these liquefaction-related pipeline projects and how they will connect to and impact the existing pipeline network.
Natural gas utilities and power generators in southern New England will have access to additional gas supplies this winter as Spectra Energy brings its 342-MMcf/d Algonquin Incremental Market (AIM) project into service. But Kinder Morgan’s planned 72-MMcf/d Connecticut Expansion has been set back a year (to November 2017) due to permitting delays and, more important, a multi-state effort to enable electric distribution utilities (EDUs) to contract for gas pipeline capacity for generators appears to have died, and with it prospects for at least one major project. Is New England destined to remain gas-supply constrained for years to come? Today we consider recent developments regarding gas supply in the northeastern corner of the U.S., and what they may mean for Marcellus/Utica producers.
Fundamental, far-reaching changes in natural gas pipeline flows within the Lone Star State to enable increased gas supplies to reach LNG terminals and Mexico cross-border points give new significance to the issue of federal versus state pipeline regulation. Given Texas’s independent streak, it comes as no surprise that federal and state rules are night-and-day, with the Texas regs being largely hands-off and the feds’ being very hands-on. The differences are worth examining because they affect project development, pipeline tariffs, relationships between pipeline owner/operations and gas sellers/buyers—even the degree of transparency regarding shipper contracts and daily pipeline flows. Today we consider the differences between federal and state regulatory oversight of gas pipelines in Texas, and why they matter.
Global demand for motor gasoline is on the rise, and U.S. refineries—as a group, still the most sophisticated in the world—are poised to play a critical role in providing much of the needed incremental gasoline supply to Asia, Latin America and other growing markets. This important topic was the focus of a recent talk at the Center for Strategic and International Studies (CSIS) by our good friend, Dr. Fereidun Fesharaki, chairman of international energy consultant FGE, who also discussed the International Maritime Organization’s (IMO) new (and controversial) decision to limit sulfur in bunker fuel to 0.5% by January 2020—a move that will test the capabilities of refineries worldwide. Today’s blog provides highlights from this presentation.
New power plants in Mexico have spurred natural gas demand south of the border––and fast-rising gas imports from the U.S, particularly Texas. Thus far, pipeline exports from Texas to Mexico have primarily been supplied by gas produced within the Lone Star State, but a big squeeze is on as nearby Texas production volumes decline (particularly the Eagle Ford) and export demand continues to increase, not just from Mexico but from new liquefaction/LNG export terminals along Texas’s Gulf Coast. Today, we unpack the shifting Texas supply and demand balance and potential implications for the market.
The shale boom breathed new life into East Coast refineries that were under threat of closure by their owners between 2009 and 2012. Now some of those same refineries are under threat again, this time due to poor margins as well as the high cost of compliance with environmental regulations. After enjoying three years of improved margins through access to advantaged domestic crude delivered by rail from North Dakota, five East Coast refineries are now paying international prices for imported crude again in 2016 after differentials between domestic benchmark WTI and international equivalent Brent narrowed to less than $1/bbl in the wake of the crude price crash and an end to the federal ban on most crude exports. Today we discuss PADD 1 refinery prospects.
New “Tier 3” requirements to limit sulfur content in gasoline are set to take effect in just over two months — on January 2017. In March 2013, the Environmental Protection Agency (EPA) proposed to limit the sulfur content of gasoline produced or imported into the U.S. to no more than 10 parts per million (ppm) from the current “Tier 2” 30 ppm standard by January 1, 2017. With these upcoming “Tier 3” requirements, refiners have been developing their strategies to meet the regulations and in some cases have already invested hundreds of millions of dollars in their facilities. Today, we look at the various approaches refiners can take for compliance and their impacts on the industry.
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.
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.