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.
The NYMEX gas futures curve for 2015 was sitting right at $3.00/MMBtu yesterday (January 27, 2015) as colder weather has halted it’s recent slide. This still puts outright prices in the Northeast gas forward curve in dangerous territory for producers – very close to breakeven levels – through 2015 and not much higher even beyond this year. With NGL prices no longer supporting drilling activity for many producers in the region, the gas forwards market is becoming a bigger factor in signaling producers’ drilling prospects. Today in Part 3 of our Forward Curve Series, we continue our look at Northeast forward curves, with a focus on the Dominion South Point price hub, its historical shape and the fundamentals behind where it stands now.
An ugly combination of sagging overseas demand for liquefied natural gas (LNG), new LNG supply coming online in Asia and cheaper oil dragging down prices has taken some wind out of the sails of U.S. LNG export prospects. After all, the LNG export boom was premised on rising world LNG demand and the pricing of gas at Henry Hub natural gas levels—a welcome alternative to traditional suppliers indexed to what used to be higher cost oil. The question becomes, will these setbacks just slow the pace of new LNG export projects in the U.S., or will the potential market be limited to the projects already locked in? Today, we consider recent developments and what they mean for LNG export projects—and U.S. natural gas producers.
It would be an understatement to say that the worldwide market for liquefied natural gas (LNG) is in flux. LNG production is up and heading higher, oil—and LNG--prices are down sharply from a few months ago, and Japan and other big consumers of LNG are more interested than ever in mitigating price and supply risk. All this comes as Japan, a primary target of prospective U.S. and Canadian LNG export projects, is grappling with the need to restart dozens of idled nuclear units so it can reduce the oil and LNG imports that have hurt its trade balance since the Fukushima disaster nearly four years ago. Today we consider recent developments and how they may affect Japan and its potential LNG suppliers on the North America side of the Pacific.
In the dead of the natural gas winter season when US producers count on strong margins from higher gas prices, the Transco Z6 New York hub is trading on average nearly flat with U.S. benchmark Henry Hub, LA – the delivery point for the CME NYMEX natural gas futures contract. This is a dramatic departure from historical winter norms in the Northeast market, where prices relative to Henry and just about every other gas hub in the Northeast have traditionally carried hefty premiums in the winter. Moreover, the forward curves indicate these basis levels are the new norm for Northeast pricing. The forward curve for Transco Z6 New York shows basis for 2015 barely above Henry Hub for the year, with several months at more than $1.00/MMBtu discount. Today we look at what’s behind major changes in northeast forward curves.
Developing new natural gas pipeline capacity in the Northeast isn’t easy. Environmental rules are tough, local citizens are well-organized, and—in New England in particular—the electricity market structure is not, shall we say, pipeline development-friendly. Still, with gas needs in the region rising, and all that Marcellus gas close at hand, midstream companies are doggedly and creatively pursuing pipeline projects, and making some headway. Today, we update efforts to advance the Constitution Pipeline, the Northeast Energy Direct project, and Access Northeast, all of which are planned to help move Marcellus gas into the heart of New England.
The development of US liquefied natural gas (LNG) export facilities is picking up steam. Four projects—Sabine Pass LNG, Cameron LNG, Cove Point LNG, and Freeport LNG—are now under construction (up from only one this past summer), and Sabine Pass is only a year or so away from liquefying and exporting its first LNG. But what about Western Canada? It’s got tremendous LNG export potential, but project proposals continue to face headwinds from cost concerns, regulatory uncertainty and the most recent hurdle – lower oil prices. Today, we consider the latest news on efforts to move Western Canadian gas to Japan and other overseas markets.
Six months ago, the natural gas forward price for 2021 averaged $5.15/MMBtu. Back then a producer could hedge forward production at that price. Today 2021 is only $4.63/MMBtu, a decline of $0.52/MMBtu even though we are now in the middle of the winter. Today the forward market doesn’t get above $5.00/MMBtu until 2026, certainly a disappointment for many a producer that didn’t hedge last summer. What does the market know about the future that is different from what was known back in June? How do these forward curves work in the first place? In this new blog series on North American natural gas forward curves we will provide background on the mechanics of forward curves, examine the forward curve in each of the major regions in the North American natural gas market, and do a deep dive into natural gas historical trends, major drivers and market expectations as related to forward markets.
The US Environmental Protection Agency (EPA) June 2014 Clean Power Plan (CPP) proposal to reduce greenhouse gas emissions from the power sector 30% from 2005 levels by 2030 would result in a sharp increase in natural gas consumption and potentially major changes in infrastructure to deliver more gas to power plants. The proposal would radically increase the pace at which coal-fired power plants are replaced by gas-fired generation. Today, we consider the proposal and its likely impact on gas demand and the industry.
It’s only natural that high-volume markets like Asia and Western Europe are the focus of most discussions about exporting US liquefied natural gas (LNG) and natural gas liquids (NGLs) like ethane and propane. But the Caribbean, a market much closer to home, is attracting more attention lately, as infrastructure is developed to share America’s hydrocarbon bounty with the outside world. For decades, the Caribbean has been heavily dependent on oil-fired power generation and, as a result, its electric rates are among the highest anywhere. Now, the region is looking at alternative fuels for power generation, including LNG, compressed natural gas (CNG) and believe it or not, ethane. Today we consider the potential for fuel switching in the Caribbean, and the challenges involved.