Higher crude oil and natural gas prices, improved efficiency in drilling and completion and other factors combined to give most U.S-based exploration and production companies (E&Ps) solid financial results in the first quarter of 2017 — a stark contrast to their performance in 2015 and 2016. Better yet, the turnaround is providing E&Ps with the optimism and wherewithal to significantly ramp up their planned capital spending this year and in 2018. It’s also giving them an opportunity to zero in on shale plays with low breakeven costs that will help them maintain profitability even if commodity prices stay flat or sag. Today we analyze the first-quarter financial results of a group of 43 U.S. exploration and production companies.
One of the major target markets for Appalachian natural gas is the U.S. Southeast. More than 32 GW of gas-fired power generation units are planned to be added in the South-Atlantic states by 2020 and LNG exports from the Southeast are increasing. Of the 15.5 Bcf/d of takeaway capacity planned for Appalachia, close to 5 Bcf/d is targeting this growing demand. Despite the need, these pipeline projects designed to increase southbound flows from the Marcellus Shale have faced regulatory delays and setbacks. Today, we provide an update on capacity additions moving gas south along the Atlantic Coast.
For several years now, power generators and other major energy users in the Caribbean have been working to shift from diesel or fuel oil to alternative fuels — mostly natural gas delivered by ship as liquefied natural gas (LNG), but also propane. A few significant projects have advanced, and new infrastructure to receive LNG and propane has been put in place to support additional fuel imports into the region. But other projects have been delayed or even scrapped because of financial or regulatory troubles. Today we update the laid-back region’s efforts to wean itself off diesel- and fuel-oil-fired power.
Rising crude oil production in the SCOOP and STACK oil and NGLs shale plays is driving the development of processing and natural gas pipeline capacity for associated natural gas volumes from the region. Earlier this month (Wednesday, May 3), Enable Midstream announced Project Wildcat, a 400-MMcf/d rich gas takeaway project. On the same day, SemGroup Corp. announced the Canton Pipeline to provide an initial 200 MMcf/d (and up to 400 MMcf/d) of capacity between the STACK play and its processing facility in northern Oklahoma. Enable last month also announced a firm shipper commitment on another of its takeaway projects — the Cana and STACK Expansion (CaSE). At the same time, late last month (on April 27), NextEra withdrew plans for its 1.2-Bcf/d Sooner Trails Pipeline. Today, we provide an update of the various projects vying to move associated gas from the SCOOP/STACK to downstream demand markets.
Since 2013, nearly 3.0 Bcf/d of natural gas pipeline capacity has been added from Appalachia to the heavily populated, hard-to-reach demand centers along the East Coast. And another nearly 3.0 Bcf/d is in the works. The need for gas supply reliability in the heavily populated East, along with producers’ need to move their gas to market, is driving these expansions. But concentrated population centers, along with the geography, geology and regulatory environment of the area, all also make it tough and expensive for upgrading, expanding and developing the gas transportation system. Many of the proposed projects have been delayed or canceled as a result. Today, we provide an update on eastbound pipeline expansions from Appalachia.
Only a few years ago, pretty much all the natural gas flowing through pipelines in the southeastern U.S. was headed north to serve demand in the Northeast and the Midwest. But that’s all been changing — and fast. Gas production in the Marcellus/Utica has soared and now meets the needs of the Northeast and more. And, as LNG exports from the Gulf Coast ramp up and Southeast gas demand for power generation rises, more and more Marcellus/Utica gas is flowing south, raising the question of whether pipes in the Southeast can handle it all over the long term. Today, we discuss the findings of RBN’s work in preparing a study for the American Petroleum Institute (API) on the adequacy of regional gas pipeline infrastructure. RBN’s work discussed here is the current analysis being used to inform and develop stakeholder briefings. We anticipate API will release the final version in report form, after its completion.
For years now, limited natural gas pipeline takeaway capacity has constrained gas production growth in the Marcellus/Utica natural gas shale plays in the Northeast. To fix that, a slew of pipeline projects were planned to relieve the constraints as regional supply began outstripping demand starting in 2014. Now, the region is on the verge of being unconstrained for the first time since the Shale Revolution hit Appalachia. Many of those projects have come online since then, and another 19 expansions totaling 15.5 Bcf/d are planned for completion by late 2019. If all goes as expected, this next round of projects should turn the Northeast market on its head again, as the capacity additions should start to outpace production growth. The problem, though, is that several projects have faced significant challenges in recent months, resulting in either cancellation or major delays. At the same time, Marcellus/Utica production growth has slowed dramatically in the past 18 months or so. In today’s blog, “In a Northeast Minute…Everything Can Change — An Update of Marcellus/Utica Takeaway Projects,” Sheetal Nasta begins a series looking at the status of regional takeaway capacity expansions.
The contiguous U.S. natural gas market is on its way to having its second major LNG export terminal and a new source of demand in the Northeast region by the end of the year. Dominion’s Cove Point liquefaction project, located on the Chesapeake Bay in Calvert County, Maryland, last month received approval from the Federal Energy Regulatory Commission (FERC) to introduce fuel gas, signaling the start of commissioning activities, a precursor to start-up activities for the liquefaction train itself. Dominion also last November applied for permission from the Department of Energy to export up to 250 Bcf of LNG during pre-commercial operations starting as early as fourth-quarter 2017, and is awaiting a response. Once operational, the facility, which is located within just a few hundred miles of the Marcellus/Utica shales — will have access to one of the primary southbound pipeline corridors for Marcellus/Utica takeaway capacity and add nearly 0.8 Bcf/d of demand to the Northeast gas market. Today we provide a detailed look at the Cove Point LNG facility.
The highly attractive production economics of the Permian’s multistacked, hydrocarbon-packed Delaware and Midland basins all but guarantee that the region’s output of crude oil, natural gas and natural gas liquids will continue rising—possibly at an even faster rate than what we’ve seen lately. That raises an all-important question: Will there be sufficient pipeline takeaway capacity in place to keep pace with all that growth? If there isn’t, some Permian producers will suffer from downward pressure on local prices—and that may cause them to have second thoughts about the big bucks they paid to gain access to the best Permian acreage in the first place. A production-growth forecast and a deep-dive assessment of existing and planned pipeline takeaway capacity are at the heart of RBN’s new Drill Down Report on the Permian. Today we provide highlights from the new report.
Natural gas producers in the Canadian province of Alberta have had a heck of a time in recent years. Marcellus/Utica gas production has flooded markets in eastern Canada and the U.S. Northeast and Midwest, squeezing out Alberta gas in the process. Also, Alberta gas producers’ dreams of piping gas west to the British Columbia coast for export to Asia as LNG have been thwarted. Lucky for them, though, gas demand within Alberta is on the rise, thanks to increasing use of gas in the oil sands and a decision by the province’s largest power generator to shift from coal- to gas-fired generation and renewables. Today we update gas output and consumption trends in Canada’s Energy Province.
Natural gas production growth in the U.S. Northeast—the primary driver of U.S. production growth in recent years—has slowed dramatically in the past few months, up no more than 1 Bcf/d year-on-year, compared with growth in increments of 3 and 4 Bcf/d in previous years. Despite the slowdown, the regional balance continues to lengthen, with supply growth outpacing demand. Yet, regional gas prices, specifically at key supply hubs, which previously were struggling under the weight of oversupply coupled with limited access to growing demand markets, are strengthening. Is this the beginning of the end of takeaway constraints and distressed supply pricing in the region? Or will constraints reemerge this summer? Today, we provide an update of Northeast gas supply/demand balance.
As a group, the nine natural gas-focused exploration and production companies that were analyzed in our Piranha! market study are forecasting a 62% increase in capital spending in 2017 compared with 2016, a significantly higher percentage gain than their oil-focused and diversified counterparts. The driver of accelerated investment is the expected completion of natural gas infrastructure that will boost takeaway capacity from the Marcellus and Utica shales, the operational focus of eight of the nine gas-weighted E&Ps. Expanded access to Canadian, Midwestern, Gulf Coast and export markets should significantly boost realizations and margin. Production growth by the nine E&Ps, which slowed to 4% in 2016 after a 19% rise in 2015, is expected to accelerate to 10% in 2017 and to rise rapidly in 2018 and beyond. Today we continue our analysis of U.S. E&P capital spending and production trends by taking a deep dive into the investment strategies of the natural gas-weighted peer group.
In only three years, the international liquefied natural gas (LNG) market has undergone a major transformation. The old order, founded on long-term, bilateral contracts with LNG prices linked to crude oil prices, is being replaced by a more-fluid, more-competitive paradigm. That’s good news for LNG buyers, who are benefiting from a supply glut and lower LNG prices—the twin results of slower-than-expected demand growth in 2014-15 and the addition of several new liquefaction/LNG export facilities in Australia and the U.S. But the new paradigm poses a challenge for facility developers: How do they line up commitments for new liquefaction/LNG export capacity that will be needed a few years from now in a market characterized by LNG oversupply and rock-bottom prices? Today we begin a two-part series that considers the hurdles developers face and which types of projects may have the best prospects.
U.S. LNG exports via Cheniere Energy’s Sabine Pass LNG export facility are poised to be a major demand driver of the domestic natural gas market in 2017. Pipeline deliveries to the terminal have more than tripled since mid-2016 and are set to climb further as more liquefaction capacity ramps up. With two liquefaction trains already operational, the Federal Energy Regulatory Commission last month approved Train 3 to begin operations and also green-lighted the start-up of Train 4 commissioning. Today, we provide an update of Sabine Pass’s export activity and its potential effect on U.S. gas demand this year.
After cutting capital investment 71% between 2014 and 2016, the 13 diversified U.S. exploration and production (E&P) companies examined in our Piranha! market study are planning to increase 2017 capital spending by 30%. While this seems like a lackluster rebound compared to the 47% boost announced by oil-focused E&Ps, the diversified group’s totals are skewed by the pull-back strategy of giant ConocoPhillips. Excluding ConocoPhillips, the 12 other companies are guiding to a 48% increase in 2017 investment—very similar to their oil-weighted peers. Today we continue our Piranha! series on upstream spending in the crude oil and natural gas sector, this time zeroing in on E&Ps with a rough balance of oil and gas assets.