The Florida natural gas market will soon have access to another supply source. In June 2017, the Sabal Trail Transmission natural gas pipeline project is expected to begin service, bringing the market one step closer to connecting Marcellus/Utica natural gas to demand markets on the increasingly gas-thirsty Florida peninsula. The project will increase gas supply options for growing power generation demand in the Sunshine State while effectively also increasing gas-on-gas competition between producers in the Northeast, Gulf Coast and Midcontinent. Today we provide an update on Sabal Trail and its related projects.
After spending the past few years on the backburner with declining production volumes, the Haynesville Shale natural gas play, which straddles the Northeast Texas-Louisiana border, is back in the headlines. Rig counts in the region have doubled in the Haynesville in the past six months or so. Exco Resources—which has four rigs operating there currently—last week said it is divesting its Eagle Ford assets in favor of boosting drilling investment in the Haynesville. At the same time, there’s a new crop of operators in the play dedicated specifically to drilling in the Haynesville. While total basin production volumes have yet to take off, all signs point to a Haynesville resurrection of sorts. But there are also early clues that much has changed since the first go-round and the drilling profile of today’s Haynesville is likely to look much different than it did nearly 10 years ago. Today we begin a look at RBN’s latest analysis of production economics in the Haynesville Shale.
The 21 oil-focused U.S. exploration and production companies examined in our Piranha! market study are planning an average 47% increase in their 2017 capital expenditures and expecting a 7% increase in production. The 47% boost in capex is huge, but due to draconian cuts in 2015 and 2016 this year’s total is still off 58% from 2014’s—an indication of the big hole the sector is still climbing out of. The Permian Basin continues to attract more capital—no surprise there—but capex in the Bakken is also on the rise after a few lean years. Today we continue our Piranha! series on upstream spending in the oil and natural gas sector, this time zeroing in on E&Ps that focus on crude.
Energy Transfer’s latest Texas-to-Mexico natural gas pipeline project—the 1.4-Bcf/d Trans-Pecos Pipeline—began service a little over a week ago (on March 31, 2017). It’s the third Tejas-to-Méjico gas transportation project to come online in the past six months, following the expansion of ONEOK’s Roadrunner Gas Transmission pipeline in October 2016 and the in-service of Energy Transfer’s Comanche Trail Pipeline in January 2017. The three projects have added a total of nearly 3.0 Bcf/d to pipeline export capacity since last October, all originating in the Permian Basin at the Waha gas trading hub in West Texas. A game-changer, right? Well, the reality is not so simple. These expansions on the U.S. side are largely reliant on takeaway capacity on the Mexico side of the border as well as the growth of power demand downstream to support flows, not all of which is coinciding with capacity additions on the U.S. side. Today we look at the latest export pipeline capacity additions and prospects for near-term export demand growth along the Texas-Mexico border.
Rising natural gas exports from South Texas and increasing production of “associated” gas in the Permian Basin are driving the development of several new gas pipelines from West Texas to the Agua Dulce gas hub and nearby Corpus Christi. The age-old questions apply: How much new pipeline capacity will be needed, and how soon? The construction of these new pipelines also raises the question of how a potential flood of new gas supply from the Permian to the South Texas coast might affect plans by others to flow gas down the coast from Houston. Today we continue our look at proposed gas pipelines from the Permian to Agua Dulce and Corpus Christi with a review of two more projects and their potential impact.
At this time last year, the U.S. natural gas market was exiting an extremely bearish winter, the gas storage inventory was nearly 500 Bcf higher, and prompt month prices for the CME/NYMEX Henry Hub natural gas futures contract were more than $1.00/MMBtu lower. The question on our minds then was how far would production have to decline or how much demand was likely to show up to prevent storage capacity constraints by fall. In either case, the overarching sentiment was that prices would have to remain relatively low to balance the market. Now we’re exiting an almost equally mild winter, but a combination of lower production and higher exports has drawn down storage to well below year-ago levels, and the question occupying the market is more along the lines of, just how bullish could the market get this year? Today, we wrap up our look at injection season storage scenarios for the next seven months.
In connection with 2016 earnings releases, U.S. exploration and production companies (E&Ps) have announced a surge in capital spending for 2017 after slashing investment by an average 70% from 2014-16. Our “Piranha” universe of 43 E&Ps is budgeting a 42% gain in organic capital outlays with a strong focus on the major U.S. resource plays. Despite crude prices languishing at an average of ~$47/bbl since January 2015, most of the upstream industry has weathered the crisis remarkably well, primarily through the “high-grading” of portfolios, impressive capital discipline, and an intense focus on operational efficiencies. Today we review the overall outlook for 2017 upstream capital spending and oil and natural gas production, and take an initial look at expectations for our group of companies.
The combination of rising production of “associated” natural gas in the Permian Basin and rising exports of pipeline gas to Mexico—and soon, LNG on ships out of planned South Texas export terminals—is driving the need for new gas pipelines from the Permian to the Corpus Christi area, including the all-important Agua Dulce gas hub in Nueces County, TX. Yesterday (Monday, April 3), NAmerico Partners unveiled plans for Pecos Trail, a proposed 468-mile, 1.85-billion-cubic-feet-a-day pipeline aimed squarely at linking emerging gas supply with emerging gas demand. Pecos Trail joins two other projects announced within the past few weeks that target the same opportunity. Today we look at the gas side of the need for new takeaway pipelines out of the U.S.’s hottest shale play, and NAmerico’s newly announced plan to address it.
After exceptionally mild weather nearly derailed the U.S. natural gas market earlier this year, the gas supply/demand balance is set to end the 2016-17 withdrawal season relatively bullish compared to last year. Storage is finishing the season more than 400 Bcf lower than last year, albeit still 260 Bcf/d above the 5-year average. In addition, gas exports are continuing to ratchet higher. The April 2017 CME/NYMEX Henry Hub natural gas futures contract expired Wednesday (March 29) at $3.175/MMBtu, nearly $1.30 (67%) higher than the April 2016 contract settlement of $1.90/MMBtu and also about 55 cents higher than the March 2017 contract settlement. Yet, with the storage inventory still higher than the 5-year average and production growth on the horizon, the market remains susceptible to downside risk if incremental demand doesn’t show up. In today’s blog, we look at potential supply/demand scenarios for injection season.
Adapting to a new era of low crude oil and natural gas prices, U.S. exploration and production companies, have been reconfiguring their portfolios to focus on a small group of shale plays whose production economics can hold up even through tough times. Among the largest producers, no company is a better example of this trend than Anadarko Petroleum, which has sold over $12 billion in assets since the beginning of 2014—including properties that generated one-third of its 2016 production—to focus 80% of its capital investment on just three U.S. plays. Since year-end 2013, Anadarko has lowered its net debt by 16%, or $8 billion, and it exited 2016 with over $8 billion in liquidity. The company forecasts 15% compound annual production growth through 2021 at current prices, with the liquids weighting of output increasing from 44% in 2015 to 65% in 2021. Today we zero in on one of the 43 E&Ps whose new-era strategies are detailed in RBN’s new Piranha! market study.
U.S. crude oil production is back above where it was this time last year—at 9.1 MMb/d, 700 Mb/d over the low point last summer. Nearly 400 Mb/d of that surge has been since end-November when the OPEC deal was announced. So, in less than four months, U.S. producers have already taken one-third of the 1.2 MMb/d market share OPEC gave up. No doubt about it: The U.S. E&P sector is back. But not because prices are above $60 or $70/bbl. Instead, this recovery is being driven by rising productivity in the oil patch. And that makes it a whole different kind of animal than we’ve seen before, with implications for upstream, midstream, downstream and just about anything that touches energy markets. That’s the theme for our upcoming School of Energy—Spring 2017—“Back in the Saddle Again—Market Implications of the 2017 U.S. Oil and Gas Recovery” that we summarize in today’s blog.
Despite OPEC’s production cuts, crude oil prices are still hovering just below $50/bbl, and there are certainly no guarantees that they won’t fall back to $40 or lower (at least for a while). So the survival of many exploration and production companies continues to depend on razor-thin margins, meaning that E&Ps need to trim their capital and operating costs to the bone. Lease operating expenses—the costs incurred by an operator to keep production flowing after the initial cost of drilling and completion—are a go-to cost component in assessing the financial health of an E&P. But there’s a lot more to LOEs than meets the eye, and understanding them in detail is as important now as ever. Today we continue our series on the little-explored but important topic of lease operating expenses.
U.S. oil and natural gas exploration and production companies, anticipating continuing low crude oil and natural gas prices, have been reshaping their portfolios to focus on a half-dozen top-notch resource plays whose production economics can hold up even through the roughest of patches. The biggest of these asset purchases and sales grab the headlines, but countless other, smaller deals are having profound effects too. Taken together, this piranha-like devouring of E&P assets in the Permian Basin, SCOOP/STACK and other key production areas is transforming who owns what in the plays that matter most, and positioning a select group of E&Ps for success. Today we review highlights from “Piranha!” —a just-released market study from RBN.
Cheniere Energy last Friday announced it has signed precedent agreements (firm capacity deals) with foundation shippers for its 1.4-Bcf/d Midship Pipeline project, which is targeted for an early 2019 in-service date. The announcement marks the latest milestone for midstream companies looking to move natural gas production from the SCOOP/STACK shale plays in central Oklahoma to growing demand markets in the Southeast and along the Texas Gulf Coast. Production from SCOOP and STACK grew by 1.0 Bcf/d, or 60%, in the past three years to 2.7 Bcf/d in 2016 and is expected to grow by another 1.5 Bcf/d by 2021. Besides Midship, there are other projects vying to move SCOOP/STACK gas to market. But how much capacity is really needed and by when? Today we look at the Midship project and its role in alleviating potential takeaway constraints.
South Texas is emerging as the newest premium destination for natural gas supply in the U.S. Demand in the area is expected to grow much faster than local production, creating a supply shortage in the region by early 2018. New pipeline capacity will be needed to move incremental supply into South Texas. There are several projects planned to facilitate southbound capacity on pipelines running along the Gulf Coast Industrial Corridor. Today we examine the planned pipeline capacity and whether it will be enough to serve the coming demand.