The latest weather forecasts for the second half of December have taken the edge off the U.S. natural gas market and reduced the chance of a true doomsday storage scenario. But U.S. gas storage inventories nonetheless remain at historically low levels, and long-term weather forecasts are notoriously fickle. So this winter could still see a resurgence in volatility before the market finds a balance. And while Henry Hub prices went on a wild ride earlier this month before settling back in below $4/MMBtu, for most of December thus far, Eastern gas prices have traded at levels that make LNG exports from there uneconomic. In today’s blog, we continue our review of the winter U.S. gas market with a closer look at how Cove Point Liquefaction (CPL) might respond to high prices.
RBN Energy
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Feedgas demand at U.S. LNG export terminals has climbed 1.3 Bcf/d, or ~40%, in just three months to an average 4.4 Bcf/d in December to date and hit an all-time single-day high of over 4.6 Bcf/d last Tuesday. The big jump in demand came as U.S. Gulf Coast LNG operators have begun commissioning three new liquefaction trains, including the initial trains at two new export terminals. At the same time, pipeline expansions targeting both existing and newly active terminals have been completed to meet that demand. How are the new trains being supplied and what’s the effect on gas flows? Today’s blog takes a closer look at recent changes in liquefaction and feedgas delivery capacity and their effect on feedgas flows, starting with Cheniere Energy’s Sabine Pass Liquefaction.
Gross production of natural gas in the Niobrara region topped 5 Bcf/d for the fourth consecutive month in November 2018, according to the Energy Information Administration, and it's estimated that regional output this month will hit another record: nearly 5.2 Bcf/d. These production gains, and the concentration of new wells in or near Weld County, CO — the epicenter of the Niobrara’s Denver-Julesburg Basin — are straining the ability of existing gas processing plants to keep up, and spurring the rapid development of new processing capacity. The scale of the build-out in the D-J is impressive: some 2.7 Bcf/d in new cryogenic plants are either under construction or in various stages of pre-construction planning in northeastern Colorado. Today, we continue our review of Rockies crude oil, gas and NGL production and infrastructure, this time focusing on gas-processing needs in the sky-high D-J.
The third quarter of 2018 was a moment in the sun for U.S. exploration and production companies. The 44 major companies we track reported a 35% increase in pre-tax operating income over the previous quarter and seven-fold increase from the year-ago period on rising commodity prices and narrowing differentials in some key regions. Oil-Weighted producers outside the infrastructure-constricted Permian posted generally higher realizations, and a number of Permian-focused E&Ps minimized the impact of takeaway constraints by employing basis hedges, utilizing firm transportation contracts and reducing their operating costs. Diversified producers saw higher quarterly per-unit profits thanks to the tilt of their portfolios toward oil. And as lower Appalachian differentials lifted the realizations of Gas-Weighted producers, portfolio readjustments and the liquids content of production also positively impacted their profitability and cash flow. Today, we analyze third-quarter results by peer group, and discuss the potential impacts of the sudden plunge in oil prices this fall.
The U.S. natural gas market’s supply-demand balance in 2018 has been razor thin, with demand ramping up to match strong production gains. The result has been a large and stubborn storage deficit compared to prior years and price volatility, the likes of which the market hasn’t seen in a decade or more. How will the current storage level affect the winter gas market, and what are the prospects for storage to catch up before the winter is up? Today’s blog considers potential scenarios for the season-ending gas inventory balance.
The IMO 2020 rule, which calls for a global shift to low-sulfur marine fuel on January 1, 2020, is likely to require a ramp-up in global refinery runs — that is, refineries not already running flat out will have to step up their game. Why? Because, according to a new analysis, the shipping sector’s need for an incremental 2 MMb/d of 0.5%-sulfur bunker less than 13 months from now cannot be met solely by a combination of fuel-oil blending, crude-slate changes and refinery upgrades. The catch is, most U.S. refineries are already operating at or near 100% of their capacity, so the bulk of the refinery-run increases will need to happen elsewhere. Today, we continue our look into how sharply rising demand for IMO 2020-compliant marine fuel may affect refinery utilization.
There’s a reason why more than half a dozen midstream companies and joint ventures are clamoring to build deepwater loading terminals on the Gulf of Mexico: because it’s a major pain to load Very Large Crude Carriers (VLCCs) any other way. These days, the standard operating procedure for loading the vast majority of VLCCs along the Gulf Coast involves a complex, time-consuming and costly process of ship-to-ship transfers called reverse-lightering, in which smaller tankers ferry out and transfer crude to VLCCs in specified lightering areas off the coast. Today, we ponder the current dynamics for U.S. crude exports via VLCC.
The build-out of new natural gas pipelines in Mexico has been progressing two-steps-forward, one-step-back, and that’s been a downer for Texas producers eager to access new markets south of the border. Just a few weeks ago, TransCanada very publicly halted construction on part of a major pipeline network it has been building in east-central Mexico, citing social and legal challenges that already had caused long delays and added costs. But there’s good news out there too. Some new Mexican pipelines are finally coming online, and gas flows through them are ramping up, mostly to serve gas-fired power plants. Better yet, some important pipe and generation projects may finally be completed in 2019. Today, we discuss gas flows across the U.S.-Mexico border and zero in on recent flows through the Nueva Era Pipeline, a 630-MMcf/d pipe from the Eagle Ford to the industrial center of Monterrey.
For months, the crude oil market had Canada figured out. Production was growing, bit by bit. Pipelines were maxed out. Railcars were hard to come by but were providing some incremental takeaway capacity. Midwest refineries, a big destination for Canadian crude, went in and out of turnaround season, moving prices as they ramped up runs. Overall, the supply and demand math was straightforward also, tilted towards excess production. Canadian crude prices were going to continue to be heavily discounted for the next year or two, until one of the new pipeline systems being planned was approved and completed. Western Canadian Select (WCS) — a heavy crude blend and regional benchmark — was averaging at a discount to West Texas Intermediate (WTI) near $40/bbl in November, dragging down Syncrude prices with it. As the market was settling in for a long, cold winter in Canada, a bombshell dropped: Alberta’s premier announced on December 2 (2018) that regulators would institute a mandatory production cut, taking 325 Mb/d of production offline, and that the government would invest in new crude-by-rail tankcars. That announcement has had a massive impact on prices, with WCS’s differential narrowing to $18.50/bbl most recently. In today’s blog, we look at several catalysts for the recent swing in Canadian prices, and how the recent governmental intervention will impact differentials.
Reliably low Henry Hub natural gas prices are a primary, long-term driver of U.S. LNG exports. But prices were up as much as 40% during November and, with gas inventories unusually low, Henry prices could spike considerably higher if winter weather continues to come in colder than normal. Which raises the question, how high would gas prices need to go before U.S. liquefaction becomes the lever that balances the U.S. gas market? The short answer is, it depends on where the LNG is headed — and lately, a lot more is bound for Europe. Today, we continue our review of the current gas market with an analysis of LNG variable costs and UK National Balancing Point prices, and how they will help determine LNG export volumes if U.S. gas prices spike.
The planned shift from 3.5%-sulfur marine fuel to fuel with sulfur content of 0.5% or less mandated by IMO 2020 on January 1, 2020, will require a combination of fuel-oil blending, crude-slate changes, refinery upgrades and, potentially, increased refinery runs, not to mention ship-mounted “scrubbers” for those who want to continue burning higher-sulfur bunker. That’s a lot of stars to align, and even then, there’s likely to be at least some degree of non-compliance, at least for a while. So, what’s ahead for global crude oil and bunker-fuel markets — and for refiners in the U.S. and elsewhere — in the coming months? Today, we continue our analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more.
Volatility is back big time in the U.S. natural gas market. The CME/NYMEX Henry Hub prompt natural gas futures contract in mid-November raced up more than $1.00 (28%) in the span of two days to a settlement of about $4.84/MMBtu on November 14, the highest price since February 2014, only to whipsaw back down 80 cents the next day. And, since then it hasn’t been unusual to see daily swings of 20-45 cents in either direction. As of yesterday, the now-prompt January 2019 contract was at about $4.34/MMBtu, down 27 cents on the day. The gas market hasn’t seen quite this level of volatility in a decade or more. Why now and what are the fundamentals behind it? With the coldest, highest-demand months still ahead, today’s blog provides an update of the gas supply-demand balance driving the recent price volatility.
Two months ago, NGL prices and market differentials were soaring, in large part due to fractionation capacity constraints on the Gulf Coast at Mont Belvieu. The constraints have not eased, yet the same prices and differentials have come crashing down from those lofty levels. Why has this happened, you ask, and how long will it last? There are a lot of factors contributing, but two of the most significant are seasonal NGL demand shifts and what’s going on with crude oil. Today, we examine the recent swings in NGL prices and market differentials and what may be around the next corner for these markets.
The sun was shining and wind filled the sails of the 44 major U.S. exploration and production (E&P) companies we track in the third quarter of 2018 as they collectively reported a 35% increase in pre-tax operating income over the previous quarter. It’s been an up-and-down year. Increased efficiency and rising output from the transformation to large-scale, manufacturing-style exploitation of premier resource plays moved the E&P sector solidly into the black in early 2018 after three years of losses. But profits stagnated in the second quarter on a decline in revenues as widening differentials, primarily in the Permian Basin, negated the impact of higher NYMEX prices. Today, we explain how producers overcame the headwinds to resume profit growth in the third quarter, but warn that future returns for certain E&Ps could be jeopardized by the sudden plunge in oil prices.
This summer and fall, more than a half dozen companies and midstream joint ventures have announced plans for new deepwater export terminals along the Gulf Coast that — if all built — would have the capacity to load and send out more than 10 MMb/d, which is notable because the U.S. Lower 48 currently produces 11.2 MMb/d. Most of these projects won’t get built, of course — export volumes may well continue rising, and the economics of fully loading VLCCs at deepwater ports are compelling, but even the most optimistic forecasts suggest that only one or two of these new terminals will be needed through the early 2020s. So, there’s a fierce competition on among developers to advance their VLCC-ready export projects to Final Investment Decisions (FIDs) first. Today, we discuss highlights from our new Drill Down Report on deepwater crude export terminals as well as the export growth and tanker-loading economics that are driving the project-development frenzy.
Crude oil and natural gas production in the Bakken are at all-time highs, as are the volumes of gas being processed in and transported out of the play. The bad news is that for the past few months, the volumes of Bakken gas being flared are also at record levels, and producers as a whole have been exceeding the state of North Dakota’s goal on the percentage of gas that is flared at the lease rather than captured, processed and piped away. State regulators last week stood by their flaring goals, but in an effort to ease the squeeze they gave producers a lot more flexibility in what gas is counted — and not counted — when the flaring calculations are made. Today, we update gas production, processing and flaring in what’s been one of the nation’s hottest production regions.