Producers in the Bakken are making progress reducing the natural gas flaring that had put an unwelcome spotlight on the region. The fix, spurred in part by tightening regulations, is being made possible by the addition of new gas processing capacity and increased efforts to use “stranded” gas at the well-site. (A drilling slowdown associated with soft crude prices is providing an assist.) Today, we take a fresh look at what’s been happening on the flaring front in western North Dakota, where gas flares still light the nighttime sky.
The U.S. Midwest region is slated to get an infusion of cheaper Northeast natural gas supply later this year as the first of five new westbound pipeline expansions is expected to begin service in November. Already a couple of projects are moving gas to the Midwest from the Northeast. The Northeast-to-Midwest capacity will have a huge impact on the Midwest supply stack and consequently on prices. The Chicago Citygates forward curve shows prices flipping from premiums to discounts later this year. Today’s blog continues our look at how new pipeline capacity will re-shuffle the Midwest’s supply stack and change regional pricing.
Cold weather, abundant supplies of natural gas and lower-than-normal winter gas prices spurred record power burns in January and February, and the power burn for the rest of 2015 is likely to be record-breaking too. It almost has to be; all the gas expected to be produced this year needs to go somewhere, and there’s only so much that can be stored. That suggests continued softness in natural gas prices—hardly good news for gas producers.
For years now, the international LNG trade has been based primarily on long-term contracts between buyers and sellers, and those deals have been indexed to oil prices. That long-standing regime is now tottering, however, and a New World Order that would add considerable flexibility to LNG trading—and increase the role of the LNG spot market—may be in the offing. That would have huge implications for U.S. natural gas producers who want to export increasing amounts of liquefied gas.
Natural gas production is growing faster in the Marcellus and Utica than any other part of North America. Even with lower prices, Appalachia natural gas production will probably hit record highs in the next few days, and NGL production is into the stratosphere, now more than four times where it was two years ago, growing on average 6% PER MONTH!
An average of 13 Bcf/d of natural gas flows into the Midwest from producing regions in Canada, the Midcontinent, the Southeast and the Rockies. Over the past 7 years the region has been in the crosshairs of major infrastructure and supply changes to the North American natural gas market, starting in 2008 with the Rockies Express (REX) pipeline and continuing today as surplus Northeast supplies reverse pipeline flows and push into the Midcontinent.
As if there weren’t enough reasons to add new natural gas pipeline capacity through New England, it’s time to consider another: the Sable Island and Deep Panuke gas production areas off the coast of Nova Scotia are quickly losing their oomph, and soon the Canadian Maritimes will need to rely more heavily on gas from other, more distant sources, including the Marcellus. Developing pipelines to move large volumes of Marcellus gas through New England to New Brunswick and Nova Scotia will not be easy though. Today we continue our look at the challenges of supplying gas to New England and its northern neighbors.
Does it make sense to build natural gas pipeline capacity that will only be used a few weeks a year? That’s a question that continues to spark debate in New England, where the existing pipeline network is sufficient most of the year but unable to supply the region’s growing number of gas-fired power plants during the coldest winter days. What’s the answer? Building gas pipeline capacity that will remain largely unused? Relying on oil and LNG as a permanent gas-supply backup for power generators? Or maybe building pipeline capacity to provide not only peak, wintertime service to generators but off-peak service to LNG exporters? Today, we continue our look at a vexing dilemma with major implications for Marcellus gas producers.
Northeast natural gas prices have been flipped upside down over the last couple of years and have shown unprecedented weakness relative to Henry Hub due to capacity constraints preventing booming production reaching new demand markets. New infrastructure projects should relieve this congestion in the next two years but as we explain today, the current market view – expressed in the forward curve - does not appear to reflect that reality.
Will hold-by-production (HBP) drilling by producers acting to preserve their leases for the longer term end up sending U.S. oil and gas production volumes higher when energy fundamentals and prices suggest production should slow down? This has happened before, with one of the highest profile instances in the Haynesville Shale between 2009-13, leading to even lower natural gas prices. Could it happen again in the Marcellus this year? Today we continue our look at HBP lease provisions with a focus on the Marcellus.
The much-discussed shortfall in natural gas pipeline capacity into New England has been largely mitigated this winter because generators—encouraged by low oil prices and incentives to lock in backup supplies of oil and LNG—are ready, willing and able to switch their dual-fuel power plants away from pipeline natural gas and onto oil and LNG-sourced gas if market conditions warrant. But now that prices for those fuels are more attractive, could switching to oil and imported LNG during winter’s coldest days and nights actually be a longer term solution to New England’s pipeline capacity problem instead of just a stopgap until new pipelines are built? Today, we begin a look at the changing economics of burning oil and LNG-sourced gas to help power New England when the region turns arctic, and what they may mean for proposed pipeline expansion projects.
Exports of U.S.-sourced natural gas as liquefied natural gas (LNG) will likely begin within a year’s time, and will ramp up through the 2016-19 period. That much seems certain. What’s less clear is whether the capacity of U.S. liquefaction/export projects will plateau at the roughly 6 Bcf/d in the “First Four” projects now under construction or continue rising higher. Yesterday’s decision by the BG Group to delay it’s commitment to the 2 Bcf/d capacity of the Lake Charles LNG terminal until 2016 certainly casts doubts on those further expansions. Prospects for additional export projects hinge on a few interrelated factors, including the higher capital costs associated with some next-round projects; the costs and challenges of shipping LNG through the expanded Panama Canal; and the possibility of competing LNG export projects being developed elsewhere, including western Canada. Today we consider these factors and handicap the handful of export projects on the cusp of advancing.
The Dominion South Point strip price for the balance of 2015 (March-December) has been settling consistently under $1.90/MMBtu, while Transco Zone 6 in New York is averaging around $2.80/MMBtu in this week’s forwards market. Meanwhile, Northeast and US gas production remain near record levels. The breakeven price environment and looming oversupply leaves producers and the industry vulnerable to the downside. Where and when will prices bottom out? What, if anything, would trigger a rebound? Today Part 4 of our Forward Curve Series, focuses on fundamental factors driving Northeast forward curves over the next few years.
There were—and still are—reasons to be optimistic about the potential for U.S. LNG exports. Worldwide demand for LNG is rising, the U.S. has vast reserves of cheap natural gas, and Asian LNG buyers in particular have been looking to diversify their sources and shift away from oil-indexed LNG pricing. But the collapse in oil prices has shaken the LNG world and undermined confidence in the U.S.’s LNG-exporting future. Today we continue our look at what’s ahead for liquefaction/export projects, given the topsy-turvy nature of today’s energy markets.
Mexico probably has enough shale gas to meet its needs ‘til the vacas—or cows—come home. For technological, security and other reasons, though, it will take years for that now-trapped gas to be tapped on a large scale. In the meantime, Mexico is turning to U.S. gas suppliers, and billions of dollars of new pipelines are being built to transport vast amounts of gas south of the border from the Permian Basin, the Eagle Ford and other plays to run Mexican power plants and factories. Today we consider recent developments in U.S. gas exports to our southern neighbor.