U.S. crude oil production is finally falling in response to the collapse in oil prices that started in mid-2014. Output is now poised to drop below 9 MMb/d--700 Mb/d off its April 2015 peak—and the rate of decline is accelerating. That raises all-important questions of how low will production go, which shale basins will be hit the hardest, and the most important question of all - how much will oil prices need to rise to reverse those declines? Understanding the factors necessary to answer these questions is the focus of RBN’s latest Drill Down report that we highlight in today’s blog. The bottom line? All production economics is local.
Two weeks ago, Tallgrass Energy, operator of the Rockies Express Pipeline (REX) received final approval to begin construction on its Zone 3 Capacity Enhancement (Z3CE) expansion project, its second east-to-west flow capacity expansion in as many years. The last one went into service last August and has been running at capacity near 1.8 Bcf/d for much of winter 2015-16. The Z3CE expansion will again increase westbound takeaway capacity on the mainline from the heart of the Marcellus/Utica shale by another 0.8 Bcf/d, on top of the existing 1.8 Bcf/d. Today we bring you the up-to-the-minute scoop on the latest REX expansion.
Tallgrass Energy’s Rockies Express Pipeline (REX) last week received final approval to begin construction on its Zone 3 Capacity Enhancement expansion project (Z3CE), which would expand east-to-west capacity out of the Marcellus/Utica shale production area to a record 2.6 Bcf/d. This project comes on the heels of REX’s East-to-West expansion (E2W), which came online last August and in one fell swoop gave Northeast producers their first substantial westbound firm forward-haul transportation capacity, totaling a full 1.8 Bcf/d. The upcoming Z3CE capacity (0.8 Bcf/d) will mark yet another milestone in the Great Pipeline Reversal that’s expected to ease supply congestion in the Northeast and support beleaguered Marcellus/Utica pricing points. That new capacity is not due in-service until late 2016. But now with nearly a full winter’s worth of pipeline flow data for the first E2W expansion, we can get a preview of potential impacts of the additional capacity on flows and pricing. Today we look at winter-to-date gas flows on REX and what they tell us about the Marcellus/Utica market.
Lately, it’s not just liquefied natural gas (LNG) prices that are headed south, it’s LNG cargoes too. A few days ago, the first LNG shipment from Cheniere Energy’s Sabine Pass liquefaction/export terminal was sent to Brazil, where a drought has slashed hydroelectric production and boosted the need for natural gas-fired power.
In January 2015 new international regulations came into force that reduced the permitted sulfur content in ships “bunker” fuel in Northern European and North American coastal regions. So far, international shipping companies and cruise lines have been responding to these rules primarily by switching to marine gasoil (MGO), burning lower-sulfur fuel oil, or sticking with higher-sulfur fuel oil and adding “scrubbers” to capture most of the sulfur being emitted by their ships’ engines. More recently, though, some of the shipping sector’s biggest players have unveiled plans to boost the use of liquefied natural gas (LNG) as a bunker fuel, figuring that LNG bunkering will not only help them meet existing regulations but the tougher rules likely to be implemented over the next few years. Today, we begin a short series on the opportunities and challenges associated with shifting ships from fuel oil to LNG.
The monthly Energy Information Administration (EIA) Drilling Productivity Report (DPR) provides a leading indication of expected crude and natural gas production from seven leading shale basins across the U.S. The latest DPR released earlier this week (March 7, 2016) included a massive 2.5 Bcf/d upward revision to the shale gas production forecast for March. The upward revisions fly in the face of expectations of production declines at recent 17-year low prices. But they also validate daily pipeline flow data showing actual production climbing to a new daily record in February 2016 and continuing to stay robust. Today we break down the latest DPR data, what the revisions mean and consider implications for the market.
On Friday (March 4, 2016) the April NYMEX/CME futures contract settled at $1.666/MMBtu, the lowest contract settlement since 1999. Rock bottom prices reflect a growing supply/demand imbalance and concerns about hitting storage capacity limits later this year. Last Thursday’s EIA report showed U.S. gas inventory stands 827 Bcf above last year at this time and 687 Bcf above the 5-year average. These are the biggest surpluses the market has seen since 2012. Moreover, our latest NATGAS Billboard storage outlook shows March withdrawals lagging way behind last year and expanding the surplus further heading into April. In today’s blog, we look at how a similar situation was resolved in 2012 and what it will take to bring down the surplus this year.
Times are tough in the methanol market. Posted and spot prices for methanol have continued falling (to levels not seen since 2010). New methanol capacity, planned during the good ol’ days, has been coming online, further depressing prices. And while more methanol-to-olefins (MTO) plants are starting up in China—the product’s biggest market—they are running at far less than full speed. But one bright spot for U.S. methanol producers is dirt-cheap natural gas, providing U.S. plants a competitive advantage versus those in the rest of the world. Today, we examine recent developments in the methanol market and consider what may be coming next.
Just a few years ago, the possibility of overseas ethane exports was almost incomprehensible. Lack of infrastructure, high handling costs, no suitable ships and minimal market demand made ethane exports seem extremely unlikely. But then the shale gas boom transformed the ethane market. Now U.S. ethane production greatly exceeds demand and each day hundreds of thousands of barrels of ethane are being rejected into the natural gas stream. Consequently a few pioneers are hammering through the challenges associated with overseas ethane exports, including the construction of specialized tankage, loading facilities, ships and unloading facilities. And international chemical companies are spending hundreds of millions of dollars to modify olefin crackers to use the cheap feedstock. Now the first of those pioneers has made it to the new ethane frontier. In today's blog we examine the impact of imminent ethane exports from the Energy Transfer/Sunoco Terminal at Marcus Hook, PA.
For the first time ever, U.S. natural gas-fired power plants are routinely generating more electricity than their coal-fired counterparts, at least during the spring, summer and fall. Prior to 2015 coal held a clear lead over natural gas in power generation but last year they were neck and neck at 33% of fuel consumed for power generation according to the latest Energy Information Administration (EIA) statistics released Friday (February 26, 2016). This is partly due to tightening federal environmental rules, but another major driver is very low natural gas prices, which have been averaging below $2/MMBtu. Coal prices have been falling too as coal markets respond to stronger-than-ever competition from gas, but not enough to prevent a lot of coal-to-gas switching in the power sector. Today, we update last fall’s analysis of the death-match battle between coal and natural gas with a look at how persistently low gas prices may keep gas on top.
After years of debate and speculation regarding prospects for U.S. exports of liquefied natural gas (LNG), the first cargo left the Gulf Coast around 8:30 pm EST Wednesday (February 24, 2016) from Cheniere’s Sabine Pass terminal, according to Genscape’s global LNG cargo monitoring service. The vessel carrying a little more than 3.0 Bcf of LNG is reportedly bound for Petrobras in Brazil. The incremental export demand that this LNG cargo and others like it to follow represent, is potentially good news for U.S. gas producers, with benchmark futures prices at Henry Hub, LA closing yesterday (February 25, 2016) near record seasonal lows at $1.711/MMBtu in the face of mild winter demand, record production and brimming storage levels. Today we look at how this first cargo was supplied and what that tells us about current and future impact to flows and regional prices.
General Partners Phillips 66 and Spectra Energy control midstream Master Limited Partnership (MLP) DCP Midstream Partners (DPM). The partnership owns midstream transportation and processing assets along the natural gas and natural gas liquids (NGL) supply chain. Similar to many MLPs its Limited Partner unit price has declined by more than 50% in the past year. Despite exposure to difficult market conditions in the Eagle Ford and East Texas, a strong performance from the NGL logistics segment is expected to propel a 20% gain in net income between 2015 and 2017. Today we review our latest spotlight analysis report on DPM.
The first U.S. liquefied natural gas (LNG) export cargo from the Lower 48 is now likely within just a week or two of shipping from the Cheniere Sabine Pass, LA terminal. In the meantime, physical flow data is already giving us a first glance at how the terminal will be supplied from U.S. natural gas production. In today’s blog, we begin a look at flows to the terminal, how the gas is getting there and where it’s coming from.
Demand for liquefied natural gas has been flat recently, but liquefaction/LNG export capacity is on the rise. The resulting supply/demand imbalance along with the crash in crude oil prices has sent LNG prices to unexpectedly low levels, and raises questions about the competitiveness of all the new Australian and U.S. projects coming online in 2016-20. Today, we continue our examination of the fast-changing international market for LNG with a look at the new capacity being added to an already saturated LNG market, and how U.S. LNG exporters might fare in a hyper-competitive world.
As of the weekly EIA natural gas storage report due out today (Thursday) for the week ending February 5, 2016, the U.S. gas inventory surplus is likely to grow to near 600 Bcf above levels at the same time last year. Current weather forecasts suggest the surplus over 2015 will soar to near 800 Bcf by the end of February. With outright inventory levels already exceptionally high, this surplus growth kicks the market’s oversupply problem further down the futures curve – meaning prices could stay lower for longer. Today we look at the winter 2015-16 fundamentals leading to this surplus and what it means for the rest of 2016.