Crude oil has always been the big draw for producers in the Permian –– and in the especially prolific Delaware Basin within the Permian –– but the wells there also produce large volumes of “wet” natural gas that needs to be gathered, processed and transported to market. A lot’s been written about the Permian’s still-strong oil production and the infrastructure developed to support it; we’ve also covered natural gas liquids (NGLs) in the play. Now it’s time to delve into the gas processing and gas pipeline capacity out of West Texas and southeastern New Mexico, including pipes into the increasingly important Mexican market. Today, we discuss recent developments on the gas side of the U.S.’s hottest (remaining) oil production area.
Daily energy Posts
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 2012, the capacity of the Jones Act fleet of tankers and large articulated tug barges (ATBs) has increased by more than one-third, to 22.5 million barrels, and over the next 18 months, new-build tankers and more large ATBs will add another 4.5 million barrel –– or 20% –– to the capacity total. That’s raised a lot of concern among vessel owners about a capacity glut and the potential for bargain-basement charter rates. What’s important to factor in, though, is that a lot of older Jones Act vessels are getting close to retirement age, and their exit from the shipping “work force” will help to mitigate the effects of any over-build. Today, we continue our series on recent developments in the Jones Act fleet and how they affect crude oil and petroleum products shippers.
With crude storage tanks along the U.S Gulf Coast nearly full, the nine storage terminals currently operational in the Caribbean offer an advantageous close-by alternative. Right now these terminals are heavily used by Venezuela for oil blending and distribution, but there has been growing interest and investment from outside the region. China is now neck and neck with the U.S. as the world’s largest crude importer and is making a significant strategic investment in Caribbean storage to cement crude supply deals with Latin American producers. Private equity fund ArcLight Capital and trader Freepoint Commodities together purchased a huge terminal and shuttered refinery in the U.S. Virgin Islands in January of this year (2016) and have leased most of the working storage to Chinese-owned Sinopec. Today, we examine the growing role of Caribbean crude terminals. (This blog is based on Morningstar’s recently published Caribbean Crude Storage Outlook , which provides a comprehensive analysis of this evolving market.)
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.
Despite slowdowns in drilling, completions and crude oil production in the Niobrara Shale region in northeastern Colorado and eastern Wyoming, new pipeline takeaway capacity out of the tight oil play is being built, apparently due to the expectations of some that the Niobrara will bounce back more quickly than most other basins if and when crude prices rise –– and stay –– above $55-60/bbl. Later this year, the 340 Mb/d Saddlehorn/Grand Mesa Pipeline to the crude storage and distribution hub in Cushing, OK is expected to begin operation, supplementing Pony Express and White Cliffs, which already move crude from the Bakken and the Niobrara’s Denver-Julesburg and Powder River basins, and giving Niobrara producers more than enough takeaway capacity for the foreseeable future. Today, we look at the possibility of an infrastructure over-build in the eastern Rockies.
Whether or not Shell Chemicals follows through on its plan to build a $6 billion ethylene plant near Pittsburgh, PA –– and when that steam cracker comes online –– will have a significant impact on the U.S. ethane, ethylene and polyethylene markets. By consuming an estimated 90-100 Mb/d of ethane, the cracker’s operation would reduce the volume of ethane that needs to be moved out of the “wet” Marcellus/Utica production area, trim the amount of ethane available for export from marine terminals, and likely push ethane prices higher than they would otherwise be. Today, we examine what’s driving plans for the Northeast’s first cracker, and what effects the plant will have.
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.
The famous Field of Dreams misquote “If you build it, they will come” certainly has proved true for the midstream companies that added a record 18.7 MMbbl of crude oil storage capacity in PADD 2 in late 2015 and early 2016. During that six-month period, crude inventories in PADD 2 blasted 24.4 MMbbl higher to a record 155.6 MMbbl. And while PADD 2 oil stockpiles have been shrinking somewhat in recent weeks, they remain above 150 MMbbl—a mark the PADD had never seen before this year. Storage levels have been particularly high at the Cushing, OK storage and distribution hub within PADD 2. Why is so much crude being socked away? Today, we continue our look at the new storage capacity being added in the U.S., and at why demand for storage has been so high.
June was somewhat of a game-changer for the 2016 U.S. natural gas market. Summer weather finally arrived and U.S. consumption, particularly from power burn, was at record highs, as were exports to Mexico. Meanwhile, production volumes sagged, flattening and even declining versus year-ago levels in recent weeks. The market response to all of this was swift. The CME/NYMEX Henry Hub prompt futures contract ripped nearly $1.00 higher over the last five weeks to flirt with the $3.00/MMBtu mark.
We are getting into the peak summer driving season and gasoline demand has been hitting all-time highs. You might think that inventories would be drawing down and that the U.S. would need to import more gasoline and gasoline blending components. But not so. U.S. refineries are cranking out the products. Gasoline stocks are up 10% from a year ago—15 million barrels (MMbbl) higher than the top of the five-year range—and last week gasoline inventories made a contra-seasonal move upward, increasing by 1.4 MMbbl. Net exports for the first quarter were up almost five times the same period in 2015. But what does all this mean for refined product markets in general, and gasoline balances in particular? Today, we examine the state of U.S. petroleum product markets.
A few weeks back Rusty Braziel sat down with Don Stowers, Chief Editor of Pennwell’s Oil & Gas Financial Journal, to talk about the big picture – some of the most important issues facing the oil and gas industry, the lasting impact of the Shale Revolution, and Rusty’s thoughts from 40-plus years in the energy business. It turned into the cover story of their June 2016 issue. Today, we recap a few of the interview questions. You can download the full article (along with Rusty’s smiling face on the cover) at the bottom of the blog.
The international market for liquefied natural gas (LNG) is in the midst of a wrenching transition. The old order, founded largely on long-term, oil-indexed contracts that called for certain volumes of LNG to be delivered by specified Point A to specified Point B, is being replaced by a new order characterized by intense competition among suppliers, new sources of supply (and demand), a glut of liquefaction capacity expected to last at least a few years, more spot purchases, and contracts incorporating destination flexibility—and, for many, tied to natural gas (not oil) prices. Today, we continue our exploration of the industry’s fast-changing dynamics with a look at the fierce battle now under way among LNG suppliers for market share, and at new approaches to pricing LNG.