Just before the holidays, the Federal Regulatory Commission issued its final decision on the oil pipeline index rate for the next five years. The what?? Well, once rates for interstate oil pipelines are set and accepted by FERC, the rates can move around to match the market, but any increases are capped by an annual index announced by the FERC each year. The index is equal to the current year’s inflation rate, plus an “adder” that is calculated by the FERC every five years based on an examination of the industry’s results from the previous five years. In today’s blog, we explain how a few tweaks in the way FERC calculates the cost-of-service-based adder will significantly affect how much liquids pipeline rates can rise through the first half of the 2020s.
There has been a lot of acrimony and polarization among the natural gas industry, the environmental community, various consumer advocates, industrial energy users, organized power markets and renewables developers in recent years. However, the ongoing government efforts to prop up the power sector’s coal-fired and nuclear generators have succeeded in uniting all those disparate interests into a single voice saying a single word: No! Today, we discuss the history of the administration’s planned support of coal and nuclear, the unusually unified reaction to it from groups that are more often at odds with each other, and some underlying assumptions about natural gas that aren’t — well — how the gas industry says it works.
It’s no secret that the political and regulatory environments for new pipeline development in New York and the New England states are notoriously challenging. That reputation has been reaffirmed recently, as several natural gas pipeline projects targeting the region have been sidelined by permitting delays or denials. As a result the region continues to experience gas transportation constraints and price spikes during peak demand periods. But midstreamers have had some success penetrating the New York City metropolitan market (including the Lower Hudson Valley, Long Island and northern New Jersey), which may bode well for the handful of projects currently looking to serve the area. Today, we review recent and planned capacity additions into The Big Apple and its greater metro area.
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.
The Shale Revolution sparked a multibillion-dollar re-plumbing of the U.S. crude oil pipeline network that continues to this day, two years after oil prices started falling and one year after oil production volumes followed suit. While the pace of development has at times seemed hectic, the individual decisions to build new pipelines involve a lot of studying, vetting and number crunching. After all, pipelines don’t come cheap, and their success depends to a considerable degree on their long-term usefulness to the market. One of the most important factors in determining whether a crude oil pipeline project makes sense is its capital cost and, with that, the cost of moving oil through it. Today, we continue our look at crude pipeline economics with a discussion of the basics of estimating pipe size and cost, and figuring the optimal capacity of a given pipeline project.
Eight years into the Shale Revolution –– and two years into a crude oil price slump that put the brakes on production growth –– midstream companies continue to develop new pipelines to move crude to market. As always, the aims of these investments in new takeaway capacity may include reducing or eliminating delivery constraints, shrinking the price differentials that hurt producers in takeaway-constrained areas, or giving producers access to new markets or refineries access to new sources of supply. Whatever the economic rationale for developing new pipeline capacity, midstreamers and potential crude oil shippers need to examine–– early on –– the likely capital cost of possible projects, if only to help them determine which projects are worth pursuing, and which aren’t. Today, we begin a series on how midstream companies and potential shippers evaluate (and continually reassess) the rationale for new crude pipeline capacity in today’s topsy-turvy markets.
The U.S. refining industry appears to be transitioning from an era of high margins and record throughputs. Falling crude prices at first increased refining margins – especially as demand for cheap refined products like gasoline expanded. Now product inventories are brimming and margins are squeezed. As we explain today the industry can look forward to an extended period of low crude prices while regulatory requirements and the pace of economic growth largely drive refined product trends.
Did you miss our School of Energy a few weeks back in Houston? Not a problem! The entire School of Energy conference is now available online in streaming video format. The conference video, presentation slides and spreadsheet models are available for purchase as individual Modules or as a full conference package. It’s the next best thing to being there! School of Energy is unlike other natural gas, NGL or crude oil conferences. It combines all three! And the curriculum includes a comprehensive analysis of current energy markets and in-depth instruction on how to use RBN spreadsheet models covering everything from production economics to gas processing. We walk through key developments for each of the three hydrocarbons including the increasingly important links between them. Fair warning – today’s blog is a blatant advertorial.
There is talk that natural gas flaring in the Bakken is peaking and will soon start to decline. But even the most optimistic forecast has the share of gas being flared falling from the current 30% plus to between 5 and 10% by 2020. That goal is still 10 to 20 times the 0.5% share of gas being flared in Texas. Can more be done to reduce Bakken flaring to Texas levels? Today we look at what it would take to slow Bakken flaring to a flicker.
The recent tragic spate of four rail accidents involving crude-by-rail, three of them carrying crude from North Dakota, have increased pressure for regulation of rail tank car standards. The railroad industry- through the Association of American Railroads (AAR) - proposed improved safety standards in 2011 for tank cars carrying hazardous materials including crude oil. These standards have been adopted by US tank car builders and were mandated this week by the Canadian Government for new tank car construction. If the new standards applied to all existing tank cars then at least 75,000 cars manufactured before 2011 would require retrofitting. Today we examine the impact hastily implemented new regulatory requirements might have on Bakken crude oil takeaway.
Forty percent of the world’s fuel oil - the residual oil left over after extracting lighter products from crude oil - is used as bunker oil to power Ocean going vessels. Much of that fuel has relatively high sulfur content. Given that refineries sell fuel oil for less than the cost of crude – the bunkers market has traditionally been a convenient dumping ground for unwanted high sulfur residual fuel oil. New international regulations that came into force in 2012 drastically reduce the permitted sulfur content in bunkers after 2015 in the world’s populated coastal regions. Today we describe the impact the new rules could have on refiners.
Does lightning strike twice? How about three times? Sure seems like the coal industry has been hit by three lightning bolts in the past several years: a recession that reduced demand for electrical power, low prices for competing fuels (i.e., natural gas), and new federal regulations on smokestack emissions. Today we review regulations that have left coal power generators singing the smokestack blues.
Most Americans only come into contact with the Jones Act when they wonder why their cruise ship stopped off at a foreign port. This maritime legislation from a bygone era (1920) is nearly a century old. The Jones Act increases costs for US coastal shipping. That constraint has restricted the availability of waterborne options to alleviate recent US energy supply bottlenecks. Today we look at the impact of the legislation in energy markets.
The US American Phoenix, a 339 MBbl oil tanker built in Mobile, AL was launched earlier this year on June 21, 2012 (see picture below). The American Phoenix is the only US built tanker to be launched so far in 2012. On her maiden voyage in August the American Phoenix delivered a cargo of gasoline from Lake Charles, LA to Port Canaveral FL, two United States ports.
Next time you fill up with regular; spare a thought for what the product went through to make it into your tank. Before you got a chance to put the pedal to the metal, the tiger in your tank had to treat a digestive problem that was causing too much gas. It was all in honor of something called Reid Vapor Pressure (RVP) regulations. Today we open the window on the issue to air the pungent details.
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RVP stands for "Reid Vapor Pressure" a measure of gasoline volatility indicated in pounds per square inch (PSI) at 100 degrees Fahrenheit. The higher a gasoline's RVP the more quickly it evaporates. The RVP for gasoline should always be below normal atmospheric pressure or 14.7 PSI. If the RVP gets higher than 14.7-PSI fuel might evaporate in the gas tank on a hot day resulting in a vapor locked engine (car won’t start) or worse yet, an explosion. At the same time you need a certain RVP level in the winter when it gets cold or your car won’t start because the fuel won’t vaporize in the carburetor.