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.
It’s no secret that a long list of pipeline projects have been proposed to help move natural gas out of the Northeast production areas. But if you were a Marcellus or Utica producer, how would you decide whether you were interested in new capacity that hadn’t been proposed or built yet? Of course, pipeline companies have armies of engineers, cost estimators, and market analysts to bring one of these monster projects to fruition. But for anyone else, particularly in the early stages, how do you even know it’s a reasonable idea? For anyone testing a concept, you need a way to ballpark some scenarios for a new pipe. We’ve been running a blog series on our RBN Pipeline Economics Estimation Model, a quick, rule-of-thumb “sanity test” for new capacity. Today, we wrap up our walk-through of the model, with a real-world example to gauge the accuracy of the model, and then with a discussion on how the model can be used to measure economies of scale in picking the minimum volume you probably need for a new pipeline.
Canadian ethylene plants have been receiving U.S.-sourced ethane by pipeline for two and a half years now, and waterborne ethane exports from Marcus Hook, PA to Norway started earlier in 2016. Soon the real fun will begin, when Enterprise Products Partners initiates (and quickly ramps up) ethane exports from a new, 200 Mb/d terminal on the Houston Ship Channel at Morgan’s Point. The destinations of the ships leaving Morgan’s Point are likely to be places like India, Brazil, Europe, and maybe even Mexico. Today, we consider the imminent bump-up in U.S. ethane export capacity, the international markets ethane will be headed to in the near-term, and the longer-term question about how much ethane exports can grow.
The U.S. Northeast now produces all the propane and butane it needs on an annual basis (Energy Information Administration - EIA PADD 1 plus Utica production from Ohio), but the seasonal nature of the region’s demand—and a dearth of in-region storage—means a lot of the natural gas liquid (NGL) production needs to be railed to storage facilities elsewhere during the warmer months, then be moved back in to meet wintertime needs. This propane/butane back-and-forth raises costs and reduces producer netbacks. Surely there is a better way. Today, we continue our review of NGL storage (or the lack thereof) in the Northeast, and how proposed NGL storage facilities in the region might help.
Over the past 20-some days, U.S. natural gas prices have gone from being the lowest in more than a decade to very close to last year’s levels. The July 2016 CME/NYMEX Henry Hub natural gas futures contract on Thursday (June 23) settled at $2.698/MMBtu, up about 70 cents (36%) from where the June contract expired ($1.963/MMBtu on May 26) and also up nearly 50 cents (23%) from where the July contract started as prompt month on May 27 (at $2.169). Market buying to unwind short positions initially kick-started the rally, but since then hot weather and a boost in power demand has kept the rally going. National average temperatures have averaged nearly 8 degrees (Fahrenheit, or F) higher in June to date versus May, and in the past week they’ve climbed above the peak summer levels normally not seen until mid- to late-July. Gas consumption on a temperature-adjusted basis also soared in the first half of June, led by power burn (gas use for power generation). The combination of hot weather and higher gas usage per degree of demand has been practically made-to-order for the oversupplied gas market, and has led to record power burn in June to date. But higher prices have the potential for bearish consequences—the recent gains have catapulted natural gas prices well above prices for coal on a cost-per-MMBtu basis—making the latter fuel more economically competitive in the power generation sector. That’s welcome news for coal producers, but what will it do to natural gas demand and in turn gas prices? Today, we look at the shift in the coal-gas price relationship and the potential impact to power burn and the gas market.
Tallgrass Energy Partners’ Pony Express Pipeline provides capacity to move 230 Mb/d of Bakken crude oil received at Guernsey, WY all the way to the mega-hub at Cushing, OK, making it one of the most important pipeline corridors out of the Williston Basin. Possibly because of its moniker ‘Express’, it is often thought of as a bullet line, hauling barrels 760 miles in a straight shot across Wyoming, Colorado, Nebraska, Kansas and into Oklahoma.
After the $5 billion-plus expansion of the Panama Canal is dedicated this Sunday, June 26, the first “New Panamax” vessel scheduled to pass through the canal’s new, longer, wider locks will be the Lycaste Peace, a Very Large Gas Carrier (VLGC) that is transporting propane from Enterprise Products Partners’ Houston Ship Channel export terminal to Tokyo Bay in Japan. What remains to be seen, though, is how many other supersized vessels carrying propane, liquefied natural gas (LNG) or other hydrocarbons will follow, and how soon. Today, we mark the formal opening of the newly enlarged Atlantic-Pacific short-cut with a look both at the game-changing potential of the expanded canal and the realities of today’s energy and shipping markets.
More new crude oil storage capacity came online in the U.S. in the fourth quarter of 2015 and the first quarter of 2016 than in any half-year period in memory, and still more capacity is being planned. Even with all this new capacity—and the slowdown in crude oil production—the storage utilization rates at Midwest/Mid-continent and Gulf Coast tank farms, underground salt caverns and refineries are at or near record highs too. And tens of millions more barrels of storage capacity are on the drawing boards in anticipation of further incremental needs. But the energy sector is pulling back, right? What gives? Today, we begin an update on crude storage trends and crude storage facilities in Petroleum Administration for Defense Districts (PADDs) 2 and 3, which together account for 82% of U.S. crude storage capacity.
A big build-out of Jones Act product tankers and large ocean-going barges is well under way, just as the future demand for these vessels is coming into question. Within the next 18 months, a total of 17 Jones Act product tankers and large ocean-going articulated tug barges (ATBs) with a combined capacity of more than 4.5 million barrels (MMbbl) will be delivered, boosting the total fleet capacity of these types of vessels by 20%. These new-vessel orders were made a few years ago in response to increased shipments of crude oil within the U.S. that, at the time, had resulted in a shortage of Jones Act product tankers and large ATBs. This in turn led to higher charter rates and the resulting increased costs of shipping crude oil and petroleum products in the coastwise trade. Now though, the decline in U.S. crude oil production has upended expectations. Today, we begin a series on the impact of hydrocarbon market changes on the Jones Act fleet.
New and expansion natural gas pipeline projects have been part and parcel of the shale production boom in the U.S. Northeast. In fact, Northeast gas production could not have reached anywhere near its current level and become a major natural gas supplier to the U.S. without the substantial addition of takeaway capacity out of the Marcellus/Utica shale areas. At the same time, the competition among pipeline developers jockeying to be in the right place at the right time has been fierce. And now, low natural gas prices and uncertainty about future production growth have only increased the competition---not all projects will make it to in-service. The risks are higher for big pipeline projects, but so are the stakes. These days, the overall risk tolerance among shippers and investors is low, especially among producers. So if you’re a producer, how can you make sure you don’t end up on the wrong side of a transportation deal? In today’s blog, we continue our walk-through of the RBN Pipeline Economics Estimation Model. We’ll follow up in a later installment with a real-world test and other ways to use the model.
For the past five years, crude oil producers in the Bakken have depended on railroads to transport a significant share of their output to market—there simply hasn’t been enough pipeline capacity out of the tight-oil play. Now, construction of the long-awaited, 450 Mb/d Dakota Access Pipeline (DAPL) is finally poised to begin, and a late-2016 online date for DAPL is planned. DAPL’s capacity would enable producers to further reduce their use of crude-by-rail, but with Bakken production on the decline, will DAPL really be needed? And what about additional out-of-the-Bakken takeaway capacity being planned? Today, we consider the challenges and pitfalls of developing midstream infrastructure in fast-changing markets, focusing on Bakken crude.