Tropical Storm Barry Threatens Key Gulf Export Infrastructure

Tropical Storm Barry Threatens Key Gulf Export Infrastructure

Tropical Storm Barry is forecast to become the first hurricane of the 2019 season.  The storm is already affecting offshore operation and will soon begin to impact energy infrastructure onshore as well.  As projected storm paths appear to be shifting east, Barry is moving away from the heavy energy export infrastructure in the Port Arthur area.  However, the storm still poses a threat to energy infrastructure in the Louisiana area. Indeed, Phillips 66 announced that preparing to shut its 253,600 barrel per day Alliance refinery.  Other refineries in southern Louisiana may soon follow.

Barry’s cone of uncertainty has it passing by some of the largest oil and gas producing platforms in the Gulf of Mexico.  As of 11:30 CDT on Wednesday 07/10/2019, the storm had already led to the evacuation of 15 production platforms with 602,715 barrels of oil per day shut in and 496.2 mmcfd of gas shut-in according to the Bureau of Safety and Environmental Enforcement.  Since the EIA leverages BSEE’s outage monitoring as it’s only real-time component in Lower 48 production, that drop will appear in next week’s EIA report.

Although the storm is currently affecting supply, the impact of hurricanes on the US energy picture has drastically shifted over the past several years.  US oil production has grown substantially with most of those new barrels are coming from onshore in the Permian Basin of Texas and New Mexico and other shale plays such as North Dakota’s Bakken.  In natural gas, a similar situation has occurred and production from the Gulf of Mexico has waned in relative importance. The concern over Gulf of Mexico as a supply hub for production and waterborne imports has fallen. This has been replaced by a demand driven concern about the ability to load tankers for export. Though it appears Barry’s path is going to be favorable, Barry’s could still impact some of the major LNG and oil exporting terminals in the Gulf Coast.

The first terminal likely to be impacted by the storm is the Louisiana Offshore Oil Port (LOOP), which now falls within Barry’s cone of uncertainty.  LOOP, the only facility on the Gulf Coast capable of fully loading or unloading a VLCC is still used for imports, but as the chart below illustrates, that is happening far less frequently.

Crude Imports to Morgan City, LA (LOOP)

Source: US Customs & Border Patrol, DrillingInfo

With less of a need to import barrels, LOOP has been more actively loading tankers for export.  AIS data shows that the VLCC Aral, capable of holding more than 2 million barrels of crude departed the terminal on July 6th and is now headed for South Korea.  However, due to the timing of this storm, it does not appear that planned LOOP crude exports will be impacted.  The vessel Atlantic Dawn arrived with a crude cargo from Mexico on July 10.  With the need to bring that oil to shore, the terminal would not have been able to move oil out to the terminal anyways.

While LOOP is the only US offshore loading terminal, the Gulf of Mexico plays a key role in the reverse lightering operations that transfer US crude exports from the smaller vessels able to load at US inshore terminals onto the larger vessels that ultimately carry the crude to it’s destination.  These activities will likely need to halt given high seas as the storm is expected to travel through many of these designated lightering areas which are shown on the map above in light blue.

As the storm moves towards closer to shore, it’s projected to make landfall in Louisiana between the Mississippi river and Lake Charles.  South of Lake Charles lies the new Cameron LNG export terminal.  The most recent departure from the terminal was the LNG tanker Gaslog Sydney which departed on July 8th.  The Diamond Gas Sakura is in the Gulf of Mexico with a destination of Lake Charles and will likely end up at Cameron.  However on July 7th, prior to Barry’s development, the vessel changed the ETA it was signaling from July 18th to August 2nd, so it is unlikely to be impacted by the storm.   That delay could be due to reports of challenges with the cooling system at Cameron as it comes online.  Upriver of Cameron, Lake Charles is home to 2 refineries, Phillips 66 and Citgo, but like imports through LOOP, both of those refineries now require lower levels of supply via the water than they have in the past.  While they aren’t as reliant on waterborne shipments, those refineries could still be impacted by flooding or a loss of power.

Crude Imports to Lake Charles, LA (LOOP)

On the Mississippi river, the storm could impact St. James area oil terminals.  The river is already running high due to significant precipitation across the Midwest and this storm will likely exacerbate that situation.  Heightened river levels could prevent vessels from being able to safely load or unload cargoes.  The St. James area terminals are involved in the growing crude export business, but they have not seen as much growth as have the crude export terminals in Texas.  As the table below illustrates, Nustar’s St. James terminal is handling much of the crude export activity taking place in the area.

Likely Crude Export Activity at St. James Crude Terminals (Capacity in Barrels)

Source: VesselTracker, DrillingInfo

Overall given the storms current path, it seems as though it will spare some of the more important pieces of energy infrastructure on the Gulf Coast.  The biggest threat to exports from this storm would be if it were to shift further west towards the export hub in Port Arthur.  That area features the largest LNG export terminal: Cheniere Sabine Pass, a large LPG and crude export terminal in the Sunoco Logistics Mariner South, as well as other crude export terminals operated by Enterprise Products and Phillips 66.  Even if the storm avoids the area, weather could bring the boarding of tankers by harbor pilots to a halt, preventing vessels from being able to arrive or depart.  Cheniere has had to shut-in for previous storms and given its activity, a slowdown in its exports, would certainly slow demand and back up supply.  As the table below shows, the facility sends out nearly one LNG tanker every day.

LNG Tanker Activity at Cheniere’s Sabine Pass Terminal (Capacity in cubic meters)

Source: VesselTracker, DrillingInfo

For information on some of the capabilities highlighted in this analysis, please contact Bert Gilbert,

The Future Evolution of Demand

The Future Evolution of Demand

Anyone who’s been in the oil business for more than, say, a month, knows how ridiculous it would be to confidently predict where oil and gas prices are headed.

Tensions in the Middle East, growing output from the Permian, offshore adds to reserves in Guyana and Brazil, uncertainty over tariff implementation, pipeline infrastructure buildout timing, tax policy implementation, legacy refinery crude quality limitations, storage builds, price of the dollar—these are just a few of the many drivers that affect wellhead pricing of oil and gas. It’s a thoroughly bewildering set of variables, and probably beyond the analytical capability of most mortals.

More often than not, our discussions and musings about oil and gas prices focus on supply.
So, I’m going to avoid putting on my dunce cap, but I am going to look at the demand side of oil and gas while questioning the assumptions we all make about hydrocarbon demand.

My guess is that most folks, when they think of future demand, envision the rest of the world achieving first-world status like Western economies did—through a drawn out industrialization process that required massive amounts of infrastructure and fuel to power the mobility of goods, services, and people.

We’ve certainly seen this in China and India, but are we considering the ways that technology can bypass the traditional routes to building wealth to “Western” standards?

Looking at cell phone adoption in Africa is instructive.

Over the course of just 12 years, South Africa has nearly tripled the number of its citizens who own a mobile phone, while Uganda increased its usage by a factor of seven!

Moreover, internet access is predominantly by smartphone, and although not yet dominant, smartphone ownership is projected to account for nearly 87% of all connections in sub-Saharan Africa by 2025.
The mobile overprint on the African economy is projected to add $45 billion to sub-Saharan GDP (

Here’s a technology that has leapfrogged the old model of landlines—without needing tens of thousands of miles of copper, hundreds of thousands of poles, and unknown hours, days, and years of trenching—and the power consumption to mine, smelt, transport, and embed the infrastructure.

Not to mention that it’s bypassed the last-mile problem of fiber.

Although cost of ownership is a stretch for many in the region, as is the case with many competitive commodity technologies, the cost of cell phones is dropping in the region.

Fine and good, we might think, but what about the fuel needs across the world to get people from point A to point B, especially in nations with huge populations.

Let’s look at the demographics.

China’s population will start to decrease within seven to nine years, but India’s will certainly pick up the slack. From now until 2058 there will be a net add of approximately 140 million people to the population represented by these two countries over nearly 40 years. That’s roughly 3.5 million people per year.
That’s a lot of added people on our planet, and this addition to world population by itself might make us believe that world demand for fuels would increase inexorably.

African population growth, however, will dwarf the net gain from India, adding more than 1 billion people in the next 25 years, or roughly 40 million people per year.

So, problem solved, right? A developing middle class in China (although dwindling and aging) adds more than 1 billion people in the next couple of decades, and they’ll all need cars to get around, capiche?

Perhaps, but will new third-world miles traveled mimic the American model?

To drive anywhere you need decent roads. Having hitchhiked in 1979 through what is now called the Democratic Republic of Congo, I vividly remember waiting for hours at a washed out portion of the road from Bunia to Bafwasende while trucks lined up on either side of a 15-foot pothole and took turns winching each other through the mud. The distance between the two towns is about 230 miles as the crow flies, or roughly the same distance between Lake Charles, Louisiana, and New Orleans.

The two Google Map images below compare roads in the Congo vs. roads in southern Louisiana.

If the roads are not there to be driven on, the picture that emerges for Africa is a growing population with lagging infrastructure development to support increased mobility. In other words, unfulfilled demand.

Should we be comfortable in assuming that the demand for mobility options is limited to internal combustion vehicles?

Admittedly, EVs (electric vehicles) don’t yet account for huge market share of transportation options, but the trend is growing. Although EV ownership in the U.S. lags ICE (internal combustion engine) ownership, the market share for EVs in the U.S. is forecasted to achieve nearly 22% in six years.

Given that Volvo, Daimler, Volkswagen, Ford, GM, and other vehicle manufacturers are increasing their fleets of both passenger and truck vehicles—including long haul trucks—it’s not unreasonable to speculate that EVs will make up a significant portion of the global vehicle fleet. Even China is directing its domestic auto industry to increase the percentage of EVs in their fleets.

Bloomberg forecasts increases in global EV usage to be about 23% of global vehicle ownership by 2040.

Maintenance cost for EVs are about one-third of those for ICEs, and power costs per mile for an EV are about 50% of fuel costs for ICEs, so the total operating costs for EVs are about 16% of the cost to operate an ICE vehicle. This is significant consideration that no doubt factors into the decision to go EV vs. ICE.

All well and good, but where does the power come from? In poorer countries the availability of power from centralized power generation facilities is often meager.

This is being slowly addressed by sovereign nation investments in power development, such as China’s $46 billion investment in Angola’s Caculo Cabaca Hydropower project, and its $2.5 billion investment in Guinea’s Kaleta hydroelectric facility.

Will less affluent countries need the range we require in the U.S.? Although there has been a pronounced migration of rural populations to dense urban cores in search of employment and wealth, I can envision scenarios where local development powered by better solar and wind power options could occur.

If so, the need for EV range could be significantly curtailed, and the lower the range, the more affordable the vehicle.

Moreover, there are low-cost options. India’s Mahindra e20 vehicle sells for approximately $8,200—affordable, especially if several individuals pool resources.

As far as I’m concerned however, the black swan in the whole picture is our ability to innovate.

The graph below gives a sense of how powerful innovation feeds on itself.

Improvements in battery storage technology, dropping costs of solar, the internet of things, materials research into substances such as graphene, and even 3D printing of houses will be just part of the technological revolution that will unfold, with, as of yet, unforeseeable impacts in how we live our lives—including how we obtain and use BTUs.

The demand side for hydrocarbon fuels is probably stable over the next 10 to 15 years, but after that, I think there’s real chance that world markets will see demand begin to soften.

Disagree? Have an opinion? Please let me know at

Gas Storage Injection In-Line with Expectations, Hurricane Barry Ahead

Gas Storage Injection In-Line with Expectations, Hurricane Barry Ahead

Natural gas storage inventories increased 81 Bcf for the week ending July 5, according to the EIA’s weekly report. This is in line with the expected injection, which was 80 Bcf.

Working gas storage inventories now sit at 2.471 Tcf, which is 275 Bcf above inventories at the same time last year and 142 Bcf below the five-year average.

At the time of writing, the August 2019 contract was trading at $2.466 MMBtu, roughly $0.022 higher than yesterday’s close and $0.20 higher than last week.

Natural gas prices have been gaining traction over the past couple of weeks as weather forecasts have started to show warming temperatures across the lower-48. Prices rallied during expiration of the July contract, as expiration typically does, but then took a downturn to start the month, dropping as low as $2.24/MMBtu. However, the above-average weather forecasts have garnered support for prices, and prices are now trading in the $2.45 to $2.50 range as power demand is expected to increase. Tropical Storm Barry is now expected to become Hurricane Barry by tomorrow and could have a bearish impact on prices during the next couple of days should LNG terminals are shut in, leaving an over-supplied market. The storm will also likely decrease power burn for southern states (Texas and Louisiana) adding additional bearish sentiment to the market in the very short term.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.


This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending July 10, 2019.

Dry gas production saw a decrease of 0.7 Bcf/d. The South Central region saw the largest move, decreasing by 0.47 Bcf/d as production is being shut down ahead of the tropical storm in the Gulf.
Canadian net imports also decline this week, down 0.1 Bcf/d.

Domestic natural gas demand increased 1.1 Bcf/d week over week. Power demand accounted for nearly all the domestic demand increase again this week, gaining 1.4 Bcf/d as temperatures started heating up. Res/Com demand decreased slightly, losing 0.15 Bcf/d, and Industrial demand fell 0.1 Bcf/d.
LNG exports were flat week on week, while Mexican exports gained 0.18 Bcf/d.
Total supply is down 0.7 Bcf/d, while total demand increased 1.3 Bcf/d week over week. With the increase in demand and the decrease in supply, expect the EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 65 Bcf. Last year, the same week saw an injection of 51 Bcf; the five-year average is an injection of 73 Bcf.

Oil Prices Jump on Very Large Crude Draw

Oil Prices Jump on Very Large Crude Draw

US crude oil stocks posted a very large decrease of 9.5 MMBbl from last week. Gasoline inventories decreased 1.5 MMBbl, and distillate inventories increased 3.7 MMBbl. Yesterday afternoon, API reported a large crude oil draw of 8.1 MMBbl alongside a gasoline draw of 0.26 MMBbl and a distillate build of 3.7 MMBbl. Analysts were expecting a smaller crude draw of 3.1 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted a decrease of 3.8 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.

US crude oil production increased 100 MBbl/d last week, per the EIA. Crude oil imports were down 0.3 MMBbl/d last week, to an average of 7.3 MMBbl/d. Refinery inputs averaged 17.4 MMBbl/d (0.1 MMBbl/d more than last week’s average), leading to a utilization rate of 94.7%. The report is bullish and supporting prices due to large and higher than expected crude oil and total petroleum stocks withdrawals. Prompt-month WTI was trading up $1.53/Bbl, at $59.36/Bbl, at the time of writing.

Prices recovered some of their losses from Friday and have been trading in the narrow $57-$58/Bbl range as intensifying geopolitical tensions and OPEC+ production cuts are offsetting the concerns over global economic and demand growth. The tensions between the US and Iran have been supporting prices because the situation also threatens the major oil transportation channel, the Strait of Hormuz. The tensions increased further this past week as Iran threatened to restart its deactivated centrifuges and increase its uranium enrichment, plus the British Royal Marines seized an Iranian crude tanker. In addition to heightened tensions in the Middle East and concerns about disruptions in the Strait of Hormuz, prices are also supported by reports that Russia’s oil production in early July was down to its lowest in nearly three years. Geopolitical tensions, OPEC+ supply cuts and declining production from Venezuela and Iran will continue to support prices; however, the lingering trade disputes between the world’s two largest economies, the US and China, and faltering global economic growth will continue to pressure prices. Although the trade truce between the US and China gave some hope to the market that a deal can be reached between the countries, the existing tariffs and disappointing factory and manufacturing growth from Europe and Asia could potentially further deteriorate demand growth and increase the pressure on prices. Continuously increasing US production is also another catalyst that will keep prices in check, in addition to the gloomy economic and demand growth.

Prices will likely continue to consolidate in the recent range – between $56.00/Bbl and $60.00/Bbl – as the market digests the struggle between the Middle East tensions, the lack of global demand growth and the Fed’s decision on possible interest rate cuts. It is unlikely that the geopolitical tensions and demand concerns will be resolved quickly, and this recent range and the broader range – $50/Bbl to $64/Bbl – may hold prices until the market resolves the competing issues later in the year.

Petroleum Stocks Chart

Wall Street Journal Article on Encana’s Cube: Parent-Child Interaction in the World’s Hottest Shale Play

Wall Street Journal Article on Encana’s Cube: Parent-Child Interaction in the World’s Hottest Shale Play

US production of crude oil has risen dramatically over the past several years, surpassing that of even Russia and Saudi Arabia, making the US the largest global producer according to the EIA. The surge in production has been driven by fracking — more specifically, the combination of hydraulic fracturing and horizontal drilling — allowing US producers to unlock resources that were not previously accessible. Innovation in the shale patch continues to this day as operators continue to increase the productivity of their wells. The two main levers available to producers are increasing lateral lengths and increasing frac intensity. By pulling these levers, the quantity of oil that each well produces has continually increased.

The chart below is from Drillinginfo’s DPR, DI’s take on the EIA’s Drilling Productivity Report.  The purpose of the DPR is to give a short-term (three-month) outlook for oil and gas production from key unconventional plays around the country.  The selected chart shows how the production from the average Permian Basin crude well has risen over time.  As is clear in the chart, well productivity has continuously grown over the past several years.

But as shale plays have continued to be developed and operators begin to drill within the bounds of their existing wells (infill), an obstacle has appeared.  This obstacle, called parent-child interaction, could slow or even reverse the seemingly ever-increasing productivity of shale wells.

The problem of parent-child interaction occurs when operators drill and frac new wells (children) among existing wells (parents).  By fracking the well, operators open cracks in the rock through which hydrocarbons are pushed by pressure.  But if these new cracks encounter existing cracks, the result can be lower pressures for both the new child and the existing parent, reducing the ultimate recoverable amount of oil.  Schlumberger has estimated that these child wells now make up 50% of all wells in the Permian, by far the most productive US shale region.

A recent article from the Wall Street Journal, titled “A Fracking Experiment Fails to Pump as Predicted,” focuses on Encana’s cube project in the Permian Basin.  By drilling and completing many wells in a section or drilling unit in a single massive project, Encana sought to reduce costs while reducing the impact of the parent-child interaction.  Encana deployed this technology at its RAB Davidson lease in the Permian, pictured below.  The finding of the Journal’s article was that Encana was unsuccessful in overcoming the challenges posed by parent-child interaction.

Drillinginfo’s deep database of well-level production data allows users to analyze the performance of the Encana cube wells on their own.  The chart below leverages this data to generate production charts for the wells that made up Encana’s cube experiment in the Permian.  The chart presents the average well in each of the three cube attempts discussed in the article: RAB Davidson 22 (the first RAB Davidson phase), RAB Davidson 27 (the second) and Abbie Laine 30.  The analysis suggests that these wells, completed in 2016 and 2017, initially produced at a higher rate than Encana’s average Midland County vintage 2016 and 2017 wells.   After the initial burst of production, the RAB Davidson wells declined at a steeper rate than the average well.  Encana’s development at Abbie Laine featured wider spacing and showed a greater initial production rate, closer to that of the average 2018 vintage well.  However, it also declined at a steeper rate.  So while cube drilling may have lowered Encana’s cost on a per well basis, the data highlights the threat to future lofty Permian production targets if the parent-child problem cannot be solved.

Interested in more analysis of the parent-child issue?  Please join Drillinginfo on July 15 at 10:00 AM CDT as we focus on how this issue will impact the Permian Basin and answer questions such as:

  • What is the impact of parent-child and infill wells on productivity?
  • What does this imply for well-level economics?
  • How does this translate to volume forecasts for a midstream system? What is the volume risk?
  • How does the lower productivity impact development plans, especially in a world where E&Ps are focused on return to shareholders instead of growth?

To sign up, click here:

Compare Operators’ Drilling Costs and Productivity in Mere Minutes

Compare Operators’ Drilling Costs and Productivity in Mere Minutes

Analysts analyze data. That’s why they’re called “analysts” not “researchers.” When they want to compare different Oil & Gas industry operators, they can become bogged down searching through the enormous volumes of publicly available data. Our docFinder tool makes it quick and easy to search millions of records to compare operator drilling costs and productivity so analysts can spend their time actually analyzing data, not looking for it. 

PLS docFinder is part of the Drillinginfo Market Research portfolio, and you have to see it in action to believe how easy it is to use. We produced a short video showing how we use docFinder to compare operator drilling costs and productivity in the Wolfcamp, and then export key productivity metrics in fewer than three minutes:

Doesn’t sound possible, right? After all, look at number I’ve circled in red on the screen grab below: the docFinder portal provides access to more than two million slides covering the O&G industry over the last 15 years.

In the video you will see we can break that number down by entering “Wolfcamp” into the search bar, selecting “D&C Costs” under the Prospects & Geology category, and setting a date range of the last six months.

Just like that, you have a much more manageable 51 slides to review. Click on the “View Slides” button at the top to start analyzing D&C costs by operator.

You can also look at initial production rates for a specific operator like EOG Resources Inc., for example.  I set a date range of the last two years and was able to view 71 individual slides. If I want to see the entire presentation one slide was drawn from, I simply click on the “Full Document” button at the top left.

That’s it — it will probably take you more time to read this blog post than it will to use docFinder for your next project. Follow this link to watch the video and request a one-on-one demo.