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.
Daily Energy Blog
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.
In the five years since the U.S. flipped from a net LPG importer to net LPG exporter, the vast majority of those exports have gone out from Gulf Coast marine terminals. That makes perfect sense. After all, Mont Belvieu, TX is North America’s main fractionation and storage center—most of the natural gas liquids produced in the U.S. are piped there to be fractionated into propane, butane and other “purity products.” But what’s also true is that a growing share of NGLs are produced and fractionated in the Northeast, that increasing export volumes are moving out of Sunoco Logistics Partners’ Marcus Hook, PA marine terminal, and that NGL pipeline capacity from the “wet” Marcellus and Utica production areas to Marcus Hook is about to increase significantly. Today we continue our review of the LPG export data with a look at propane and butane exports from East Coast marine terminals.
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.
On Friday, TransCanada finally secured a Presidential Permit for the U.S. portion of its Keystone XL pipeline, and the company committed to pursuing the state approvals it still needs to build the project. But three hard truths—crude oil prices below $50/bbl, the high cost of producing bitumen and moving it to market, and more attractive energy investments available elsewhere—have thrown a wet blanket on once-ambitious plans to significantly expand production in Western Canada’s oil sands, the primary source of the product that would flow through Keystone XL. Today we begin a series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines.
According to Energy Information Administration data, the 26 refineries in the Midwest/PADD 2 region processed an average 3.6 MMb/d of crude oil in 2016—up 300 Mb/d from the 3.3 MMb/d refined in 2010. Over the same six-year period, production of light oil production in the region shot up by over 1 MMb/d, mostly from the prolific Bakken formation in North Dakota. Yet Midwest refiners did little to take advantage of the sudden abundance of “local” production, increasing instead their appetite for imported heavy crude from Western Canada by nearly 1 MMb/d—from 800 Mb/d in 2010 to 1.8 MMb/d in 2016. Today we explore the trend for PADD 2 refineries to run more heavy crude even as shale output surged in their backyard.
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.
The ability to increase the capacity of existing and planned crude oil pipelines with minimal capital expense has genuine appeal to midstream companies, producers and shippers alike. Enter drag reducing agents: special, long-chain polymers that are injected into crude oil pipelines to reduce turbulence, and thereby increase the pipes’ capacity, trim pumping costs or a combination of the two. DRAs are used extensively on refined products pipelines too. Today we continue our look at efforts to optimize pipeline efficiency and minimize capex through the expanded use of crude-oil and refined-product flow improvers.
Five years ago, the U.S. was a net importer of propane and butanes, those products collectively called LPG, or liquefied petroleum gasses. Back then, demand from residential, commercial, refining and chemical markets slightly exceeded supply for the products. But then came shale, and LPG production from natural gas processing more than doubled, from 0.8 Mb/d to 1.7 Mb/d. Suddenly the U.S. was a net exporter—a very big exporter at that. Last year roughly half of all LPG from U.S. gas processing plants was exported, with the vast majority shipped to overseas markets. All those exports are now having an outsized impact on pipeline flows, inventories and prices. Consequently, it is increasingly important to keep close tabs not only on export volumes but on which export terminals are handling all these volumes, and where the LPG is heading. Today we discuss the current state of the LPG export market and insights on it from RBN’s most recent NGL Voyager Report. Warning, today’s blog includes a subliminal promo for the report.
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.
