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.
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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.
Permian natural gas markets felt a cold shiver this week, but not a meteorologically induced one of the types running through other regional markets. Gas marketers braced as prices for Permian natural gas skidded toward a new threshold: zero! That’s not basis, but absolute price, a long-anticipated possibility that became reality on Monday. The cause is very likely driven, in our view, by continued associated gas production growth poured into a region that won’t see new greenfield pipeline capacity for at least 10 months. What happens next isn’t clear, but expect Permian gas market participants to be a little excitable or jittery over the next few months. Today, we review this latest complication for Permian natural gas markets.
The planned implementation date for IMO 2020 is still more than a year away, but this much already seems clear: even assuming some degree of non-compliance, a combination of fuel-oil blending, crude-slate shifts, refinery upgrades and ship-mounted “scrubbers” won’t be enough to achieve full, Day 1 compliance with the international mandate to slash the shipping sector’s sulfur emissions. Increased global refinery runs would help, but there are limits to what that could do. 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 discuss Baker & O’Brien’s analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more.
Developers are scrambling to advance the next round of liquefaction/LNG export projects, primarily along the U.S. Gulf Coast. Earlier this month, LNG marketing behemoth Total SA signed initial agreements with Sempra Energy that would support Sempra’s efforts to add more liquefaction capacity at its Cameron LNG project in southwestern Louisiana and to build a liquefaction plant at its Energía Costa Azul LNG import terminal in Mexico’s Baja California state. A few days later, Total, Mitsui & Co., and Tokyo Gas signed heads of agreements for the entire capacity of the Mexican liquefaction project, propelling that project to the fore. Sempra also continues to pursue a third project: Port Arthur LNG. Today, we continue our series on the next round of liquefaction/LNG export terminals “coming up” with a look at Phase 2 of Cameron LNG, as well as Energía Costa Azul and Port Arthur LNG.
Natural gas markets in the U.S. Northwest have been in turmoil ever since a rupture on Enbridge’s BC Pipeline system over a month ago (on October 9) disrupted Canadian gas exports to Washington State at the Sumas border crossing point. Service on the affected line has been restored but at a reduced operating pressure for now, and Canadian gas deliveries to Sumas remain at about half of their pre-outage levels, creating supply shortages in the region. Spot natural gas prices at the Sumas, WA, trading hub have been volatile, soaring well above Henry Hub and rocketing to a record outright price of nearly $70/MMBtu late last week. The outage has reverberated across the Western U.S. gas market, sending regional prices reeling as gas flows adjusted to help offset supply shortages. Today, we examine the knock-on market effects of the outage on Western gas flows and prices, and potential implications for the winter gas market.
During the summer of 2018, crude oil inventories at the trading hub in Cushing, OK, dropped to extreme lows. With estimated tank bottoms around 14.6 MMbbl, Cushing stockpiles hit 21.8 MMbbl for the week of August 3. Traders’ alarm bells were ringing, and upstream and downstream observers were wondering if low storage levels were going to cause significant operational issues. But just when it seemed tanks were nearing catastrophic lows, inventories reversed course and started to climb. Since August, crude stocks have increased by 13.6 MMbbl, or nearly 60%, and there is now talk of potentially too much crude en route to Cushing, maxing out capacity there. There are many contributing factors to this most recent inventory swing, with increased domestic production and the tail end of refinery turnaround season being two of the bigger fundamental drivers. But the main catalyst has been the shift from a backwardated forward curve to a contango forward curve in the WTI futures market. Today, we continue our Cushing series with a snapshot of recent contango markets and the impact those prices have had on stockpiles at the central Oklahoma hub.
The race is on and here comes WTI up the backstretch. On November 5, CME Group launched a Houston WTI futures contract, challenging a similar trading vehicle from Intercontinental Exchange (ICE) that started up in mid-October. Ever since crude flows to the Gulf Coast took off five years ago, the crude market has been clamoring for a trading vehicle that would accurately reflect pricing in the region that dominates U.S. demand from refineries, imports and exports. Now there are two. But their features are quite distinct. ICE’s contract reflects barrels delivered to Magellan East Houston, while CME’s contract is based on deliveries into Enterprise’s Houston system. The specs are different, as are the physical attributes of the two delivery points. Will both survive? Probably not. Futures markets tend to concentrate liquidity — trading activity — into a single vehicle that best meets the needs of the market. So, which of these will come out on top? That’s what the crude oil market wants to know. In today’s blog, we delve into the differences between the two new futures contracts for West Texas Intermediate (WTI) crude delivered to Houston and ponder the market implications of these new hedging and trading tools.
Between new sanctions on Iran and the potential for more escalation in the trade war with China, oil exports from the U.S. have been changing their flows dramatically in the past few months. China from October 2017 through July 2018 rivaled Canada as the largest buyer of U.S. crude; in June, when total U.S. exports hit a record 2.2 MMb/d, nearly one-quarter of those volumes flowed to China. But since trade tensions between the two nations intensified, not a single barrel of U.S. crude has arrived in China since July. Thankfully, the U.S. has found ways to fill the Chinese void by increasing the volumes sold to South Korea and India, two historically prominent buyers of Iranian oil. Today, we lay out the reasons why U.S. sanctions on Iran are helping the U.S. continue to sell crude to Asia, even as relations with China have chilled.