With the opening of the Panama Canal Extension in June, larger ships with new commodities have begun passing through the canal.

Genscape Vesseltracker™ AIS data confirmed that the Maran Gas Appollonia was the first LNG ship to pass through the newly expanded Panama Canal. The 19th export from Sabine will bring another first to the revolution taking place within the North American gas market. The Maran Gas Appollonia (3.43 Bcf) left the afternoon of July 20 and was progressing through the newly constructed gates at the Panama Canal on the afternoon of July 25.

North American LNG exports are expected to bring a “new world order” to global gas and power markets, setting global gas prices and power margins for years to come. With that, it’s important to understand where exports are going, how they are getting there, and when they’re expected to arrive.

There is no single data set that will say which large gas carriers are likely to transit the Panama Canal, however, by using gas carriers with known destinations and estimated times of arrival, routes can be calculated to determine whether it’s likely that a ship will route through the canal.

According to the Panama Canal Authority's press release on July 25, “A second LNG carrier, BP’s British Merchant, is expected to pass through the Panama Canal on [July 26], followed by a third cargo in early August.” Using AIS data, Genscape can infer these vessel routes, determine whether ships are likely to pass through the canal, and confirm when they do. Checking the British Merchant on Vesseltracker, for example, one can see it set its destination as Manzanillo on July 21 with an ETA of August 2, meaning that it must have had to go through the Panama Canal to arrive to that port on that date. Genscape Vesseltracker AIS data confirms that it moved through the canal on July 26. For future cargos Vesseltracker can be used keep an eye on vessels entering the region and checking their details.

Adding to this analysis, Genscape analysts can compare the time it takes to get from any one location to another; in the case of LNG specifically, the time it takes to go from any liquefaction terminal to the four regasification terminals on the west coast of the Americas, or the time it takes to get from Port Arthur in the U.S. to any of the Asian regasification terminals. The trip from Point Fortin (Trinidad and Tobago) to Quintero (Chile) changes from 14.2 days to 7.9 days when ships route through the Panama Canal, shortening their voyage by exactly 6.3 days. The trip from Port Arthur, TX to Sodeguara (Japan) changes from 47.3 days (assuming it goes through Suez Canal) to 29.9 days, shortening the voyage by 17.4 days. (Note: both comparisons assume a speed of 20 knots).

It’s also important to take into consideration the cost of a voyage. Currently, charter rates for spot LNG are approximately $25,000, down from $100,000 or more per day. If canal fees are high enough, and the cost to charter a ship and fuel it is be low enough, then the long haul through the South Atlantic to India or Chile might be a more favorable route. For example, Genscape has recently observed that the Suez Canal has been bypassed recently in favor of longer voyages, due to the low shipping and fuel costs.

Genscape’s North American LNG Supply & Demand product (coming soon) provides proprietary, real-time monitoring of the LNG supply chain, including information from Genscape Vesseltracker, from the commissioning process through startup and continuing operations, and allows users to watch new supplies of LNG come online in real time. To learn more about the service, please click here. Additionally, Genscape's Global LNG Monitor provides real-time monitoring of LNG cargoes, terminals, and routes with state-of-the-art predictive algorithms.

Genscape Vesseltracker provides the tools to monitor the changing trade patterns with a combination of ship schedules containerized ships and traffic analysis tools for monitoring other current and historic traffic. Genscape Vesseltracker currently runs one of the largest privately owned AIS receiver networks on the planet, combined with the largest AIS Satellite constellation currently available, over 144,000 vessels are tracked daily in near real-time. To learn more or request a free trial of Genscape Vesseltracker, please click here.

U.S. gasoline demand in June and July eclipsed 2015 seasonal summer consumption, according to Genscape Supply Side Analyst data. But, associated market fundamentals have veered from typical summer driving season movements, as gasoline stocks increased, prices fell and so far in July gasoline rack activity has declined from June.

On a monthly average basis, total U.S. motor gasoline rack activity grew 6 percent in June relative to the year-ago month, or 379,000 bpd to 6.659mn bpd, according to Genscape. As of July 24, total U.S. gasoline rack activity has increased 2.9 percent year-on-year, or 184,000 bpd, to 6.513mn bpd. Total U.S. gasoline rack activity increased an average of 4.75 percent each month from January to May, relative to the same period in 2015.

U.S. East Coast and Midwest rack activity climbs, but July slows relative to June

Most of the year-on-year summer rack activity growth was focused in PADD 1 (East Coast) and PADD 2 (Midwest). In June, PADD 1 and PADD 2 gasoline demand increased 7.2 percent and 8.3 percent, respectively, compared to the same month in 2015. As of July 24, PADD 1 and PADD 2 gasoline activity increased 3.6 percent and 2.3 percent, respectively, relative to July 2015.

Rack activity during U.S. holiday summer weekends, a widely used barometer for gasoline demand, was particularly strong relative this year compared to last year. Total gasoline rack activity for Memorial Day weekend 2016, defined as May 27 to May 30, was 6.223mn bpd, 6.75 percent above Memorial Day weekend 2015 (May 22 to May 25), according to Genscape.

The Fourth of July weekend 2016 (July 1 to July 4) gasoline rack activity averaged 6.389mn bpd, 13.9 percent more than the same holiday weekend in 2015 (July 3 to July 6). 

But, an analysis of Genscape data showed that year-on-year and month-to-month U.S. gasoline rack activity growth appeared to slow during the remainder of July 2016. Typically, gasoline demand is higher in July and August than June.

Month-to-date July 2016 total U.S. gasoline rack activity, as of July 24, averaged 6.513mn bpd, 2.2 percent lower than June of this year. In addition, July 2016 activity has averaged 2.9 percent higher than July 2015, while June 2016 activity was over 6 percent higher than June 2015. Despite the continued year-on-year growth, gasoline rack activity has slowed in July following the robust Fourth of July weekend. 

Gasoline stocks withstand increased rack demand

While 2016 summer U.S. gasoline rack activity remained strong compared to 2015, stocks have reached historically high levels thanks in part to a nationwide refined products glut.

For the week ending July 15, total U.S. gasoline stocks were 241mn bbls, according to the U.S. Energy Information Administration. This was 4mn bbls, or 1.6 percent, higher than the lowest level in June (237mn bbls for the week ending June 10) and 24.7mn bbls, or 11.4 percent, above the same week in July 2015. U.S. Gasoline stocks have grown steadily since June 10, with a small draw of 100,000 bbls for the week ending July 1, according to the EIA.

The same trend has emerged in New York Harbor gasoline stocks, according to Genscape. NYH gasoline stocks increased nearly 2mn bbls to 18.8mn bbls between June 3 and June 24. Inventories on June 24 were 6.4mn bbls higher than the same week in 2015 and 7.2mn bbls higher than the same week in 2014. NYH gasoline stocks fell 1.2mn bbls between June 24 and July 8 due to strong regional gasoline demand but increased to 17.8mn bbls on July 15.

Despite recent declines, NYH gasoline stocks for the week ending July 15 were 4.9mn bbls higher than the same week in 2015.

Stock surplus creates unseasonable price structure

The stock surplus, in turn, kept gasoline prices relatively weak and created a contango market structure in the forward curve, meaning prompt prices are lower than forward prices.

A contango forward curve structure is highly unusual in the summer for gasoline prices. Typically, the combination of strong demand and inventory draws push prompt prices higher than forward prices to create a backwardated forward curve.

Front-month CME Group RBOB futures fell to $1.355/gal on July 21, the lowest levels since March, amid the surplus in gasoline inventories. On that day, the front-month RBOB futures contract was $0.0064/gal below the second-month. This contango structure in the front two months has generally been in place since November 30. By comparison, the front-month RBOB futures contract reached a premium as wide as $0.0959/gal to the second-month contract in July 2015.

Gasoline production remains robust

This year, robust gasoline production levels contributed to the stock surplus and muted the impact of growing demand. U.S. finished gasoline production averaged 10.061mn bpd over the past four weeks, 1.5 percent higher than the same time period in 2015, when production was 9.92mn bpd, according to the EIA.

The recent decline in RBOB futures prices could curb the gasoline production boom, as the CME 3:2:1 refining crack spread fell to $12.38/bbl on July 21, the lowest level since February. The 3:2:1 crack spread was as high as $18.91/bbl on May 20. The crack spread is a common measure of refining profitability.

Meanwhile, expected and recent cuts in refinery production could help taper storage builds and allow the apparent growth in demand to eat away at gasoline inventories. Delta Air Lines cut production at their 185,000 bpd Trainer, PA, refinery by 16 percent, Reuters said on July 5. A news story published by Reuters the following day said that Philadelphia Energy Solutions cut rates at their 335,000 bpd Philadelphia refinery by 10 percent. PES declined to comment on the reduced rates at their Philadelphia refinery. 

Genscape's Supply Side Analyst and Supply Side Monitor provide analysts and traders with daily or hourly volumes and prices for regular gasoline, midgrade gasoline, premium gasoline, jet fuel, kerosene, and diesel. Supply Side Analyst and Supply Side Monitor cover roughly 90 percent of all wholesale racks in the United States. Click here to request a free trial. 

Plains All American’s forthcoming Cushing, OK,-to-Longview, TX, pipeline is on schedule to begin line fill in the third quarter with operations expected to start in the fourth quarter, according to Genscape’s July 17 flight of the pipeline right of way. Several work crews were observed along the right of way, with piping still exposed and significant stretches undergoing excavation.

During the flight, Genscape observed two new external floating roof storage tanks at a small existing Plains’ facility adjacent to the pipeline right of way in Carter County, OK. The tanks were nearly complete, and construction on the two tanks appeared to have made significant progress since February, the last month that publicly available satellite imagery is available.

As of December 2015, construction on the tanks had not started, according to publicly available satellite imagery.      

Plains, the sole owner and operator of the pipeline, has owned the facility since at least 2010, according to Carter County property records. The company was granted initial approval by the Oklahoma Department of Environmental Quality to construct and operate the new tanks in September 2013.

During the flight, Genscape also observed additional pumping capacity being installed at the Carter County facility. Aside from the origin point in Cushing, the Carter County facility contained the only pumps observed during the flight that were likely associated with the Cushing-to-Longview pipeline. As recent as February, publicly available satellite images showed that no pumping capacity existed, but land was being cleared for that purpose.

The right of way for the Cushing-to-Longview pipeline traverses a similar route to Plains’ existing 22,000 bpd Red River pipeline, but the new pipe has additional connectivity to Plains’ Cherokee 18,000 pipeline system and potentially Plains’ 450,000 bpd Basin pipeline. Plains began acquiring easements for Cushing to Longview’s right of way in August 2015, according to county property records.

The Cushing-to-Longview pipeline will have an initial capacity of 125,000 bpd, and is expandable up to 150,000 bpd subject to additional shipper demand, according to Plains. Line fill for this pipeline is approximately 450,000 bbls.

As a part of the project, Plains is also expanding an existing system from Longview to Shreveport, LA. From there, crude will either be transported to Shreveport refineries or connect to the 100,000 bpd Permian Longview and Louisiana Extension (PELA) to Anchorage, LA. According to a recent U.S. Federal Energy Regulatory Commission filing, PELA was able to begin operating as early as July 1, though it is not clear whether flow has started on the pipeline. Plains currently has 55,000 bpd minimum volume commitments from refineries in Shreveport, according to a Plains investor presentation from May.

Once operational, Cushing-to-Longview will increase total pipeline capacity from Cushing to about 2.691mn bpd from 2.566mn bpd, compared to 3.547mn bpd of existing incoming pipeline capacity (which includes the addition of the 340,000 bpd Saddlehorn-Grand Mesa in September).

At the end of 2016, the Cushing hub net pipeline balance should be 856,000 bpd, with incoming volumes outpacing outgoing. The only additional Cushing-connected pipeline proposed at this time is the 200,000 bpd Diamond pipeline from Cushing to Valero Energy’s 195,000 bpd Memphis, TN, refinery. That pipeline is expected to be operational in late-2017.

Genscape's Mid-Continent Pipeline Service provides total visibility into what's driving the U.S. and Canadian crude oil markets, with insight into critical pipelines supplying storage hubs and refineries. To learn more or request a free trial, please click here. 

Several Western Canadian oil storage and pipeline infrastructure projects have been delayed or indefinitely put on hold while crude prices remained relatively weak but Oil Sands production increased.

Between January 2011 and June 2014, West Texas Intermediate prices scarcely dropped below $80/bbl, leading to announcements of major infrastructure projects, many of which were expected to be put into service by the end of 2016. But, as the price of oil began to fall throughout the second half of 2014 and most of 2015, companies such as Enbridge and TransCanada put projects on hold, despite increasing production.

Alberta Bitumen crude production in December 2015 averaged 1.541mn bpd, according to the Alberta Energy Regulator, which was within 1 percent of Genscape’s Canadian production forecast of 1.528mn bpd for the same month and year. Production in December 2015 was up 17.9 percent from December 2014 levels of 1.307mn bpd, according to the AER. This trend has continued into 2016, aside from the month of May, where production drastically fell due to the Alberta wildfires, according to data showed on the Government of Alberta’s Economic Dashboard.

Production pushes forward, expansions push back

Though Western Canadian crude production has increased in recent years a decline in shipper demand has caused infrastructure construction schedule changes. A low crude price environment has coupled with a narrowing of the price spread between WTI and Western Canadian Select spot prices to cause a decline in economic arbitrage opportunities for crude shippers.

In January 2013, the price discount of WCS to the WTI Calendar Month Average was $32.65/bbl, and averaged $22.40/bbl through 2014. From January 2015 to June 2016, it averaged $13.22/bbl and never exceeded $20/bbl, according to Energy Information Administration and Alberta Energy data.

According to the Alberta Energy Regulator, Western Canadian Bitumen crude production averaged 1.111mn bpd from January 2013 through December 2014, and averaged 1.406mn bpd in 2015.

A weaker WTI price may discourage infrastructure investment, as the revenue that commercial shippers receive is derived from this price. However, when transporting crude from northern Alberta, shippers also have to consider the price of WCS. In a typical scenario, shippers pay the cost of the WCS crude as well as the cost of transportation to Cushing, OK, where they sell it relative to the WTI benchmark price. If the costs become greater to ship WCS to the United States than the WCS discount to WTI, investments may be discouraged because of a lack of willing contract shippers. 

Typically, before a pipeline or tank farm is built, shippers will sign binding long-term contracts with oil companies called take-or-pay contracts. Under these contracts, shippers must pay a fixed amount to the oil companies whether they choose to ship any oil or not. This ensures revenue for the midstream companies, but also gives shippers some degree of influence as to when a project commences.

Enbridge delays Athabasca Twin Pipeline to 2017

In a 2015 annual report filed with the SEC, Enbridge said that the price environment had affected shippers on Enbridge’s pipelines, who reacted to the low prices by “reducing investment in exploration and development programs for 2015.” Additionally, it has caused some sponsors of oil sands development programs to “reconsider the timing of previously announced upstream development projects.”

These comments are reflected in the delay of Enbridge’s Athabasca Twin Pipeline, a 450,000 bpd expansion of their Athabasca Mainline that traverses from the Oil Sands region to Enbridge’s tank farm in Hardisty, AB, where volumes can connect to their mainline system. Originally scheduled to be in-service by 2015, the project was delayed to 2017 in the second half of 2014 “at the request of Enbridge’s shippers,” according to Enbridge. To further consolidate, Enbridge decided to combine the expansion with their Wood Buffalo Extension, another pipeline expansion in the Oil Sands area, which would increase the capacity of ATP to 800,000 bpd and deliver “significant toll savings” to their shippers.

TC Terminal, Heartland Pipeline delayed indefinitely: TransCanada

Similarly, TransCanada said in a 2015 annual report filed with the SEC that changes in the price environment may lead shippers to choose to “accelerate or delay certain new [production] projects,” which could “impact the timing for the demand of transportation services and/or new liquids pipeline infrastructure.” TransCanada has had multiple project delays in the past year.

In 2013, TransCanada announced the TC Terminal and Heartland Pipeline projects. The TC Terminal would consist of six crude storage tanks, increasing the overall capacity in the Alberta Heartland region by 1.9mn bbls. The Heartland Pipeline would connect the terminal to Edmonton, AB, and Hardisty, and would have an estimated capacity of 900,000 bpd, according to TransCanada. The Heartland Pipeline progress has been affected by regulatory permitting delays of the Keystone XL and Energy East projects, which would connect to the Heartland Pipeline, according to TransCanada’s President of Liquids Pipelines Paul Miller during a financial results conference call on July 31, 2015. However, TransCanada said in the annual report that the projects would be delayed indefinitely, saying that “the in-service date for the projects will be determined and aligned with industry conditions and customer’s requirements.”

TransCanada’s Grand Rapids Pipeline project has also been delayed, with a new in-service date for part of the project to be issued when there is “subject to sufficient market demand,” according to TransCanada’s 2015 fourth quarter earnings report. The project will be built as a dual pipeline system, a 20-inch, 330,000 bpd diluent and crude line and a 36-inch, 900,000 bpd blended crude line. Phase one of the project consists of the entire 20-inch line extending from the Oil Sands region to Edmonton and a section of the 36-inch pipeline between Edmonton and Fort Saskatchewan, near the Alberta Heartland region. Phase two will see the construction of the remainder of the 36-inch line and a reversal of the 20-inch line, allowing it to transport diluent up to the Oil Sands region.

In the second half of 2015, TransCanada entered into an agreement with Keyera Corp. to deliver diluent from Keyera’s Edmonton terminal to TransCanada’s Heartland Terminal, where TransCanada is constructing a 350,000-bbl crude blend tank and a 150,000-bbl diluent tank, which have also been delayed. Originally with an in-service date of 2016, phase one was set back to 2017, with phase two delayed indefinitely.

Heartland, Oil Sands infrastructure expansions expected in 2017

Despite recent delays, 2017 infrastructure demand is on track. However, this could be subject to change dependent on future crude oil prices, as was the case with projects expected to come online in 2015 and 2016.

Enbridge’s Norlite Pipeline will transfer 130,000 bpd of diluent from Enbridge’s Heartland terminal up to the Oil Sands region in the second quarter of 2017, according to Enbridge. It is also expected have connectivity to other diluent terminals in the area, such as Pembina’s Canadian Diluent Hub, which also has an expected in-service date of 2017. The hub will provide an additional 500,000 bbls of aboveground storage to an existing 500,000 bbls of underground storage.

Storage expansions in 2017 should increase diluent storage capacity by 650,000 bbls and crude capacity by 350,000 bbls in the Alberta Heartlands region. The commissioning of the pipelines will have the capacity to create an additional 1.13mn bpd of volume flowing south from the Oil Sands region, and 130,000 bpd of diluent flowing north, along with the 330,000 bpd of diluent flowing between Edmonton and the Heartland region. 

Access the most detailed, comprehensive oil production forecast across the significant oil producing regions in Canada with Genscape's Canadian Crude Oil Production Forecast. Genscape's approach includes detailed well and project-level production data from major oil producing areas in Canada, including unconventional/conventional oil production, oil sands in-situ project and upgrader level analysis. Likewise, the forecast is stacked against pipeline takeaway capacity, pipeline production receipts and rail transport to give a detailed analysis of how the crude is getting to market. Click here to learn more about Genscape's Canadian Crude Oil Production Forecast. 

Genscape's soon-to-launch Canadian Pipeline Service will provide unprecedented insight into critical crude oil pipeline flows traversing the Canada-United States border. Market participants can use the data to gain insight into U.S. crude imports by pipeline from Canada, as well as crude flows from the U.S. By providing transparency in this area, Genscape has altered the trading landscape, offering market participants an unmatched platform for use in trading and hedging strategies. To may learn more about this product or register your interest here. 

Up to seven days before the National Oilseeds Processors Association (NOPA) report is released, Genscape releases its Soybean Crush Report, which uses proprietary monitoring and data to provide an estimate on what it will show. Genscape’s national NOPA estimate for July 2016 is 147.7 million bushels, which reflects an average processing rate of 4.76 million bushels per day. June’s national NOPA statistic indicated 4.84 million bushels per day. Based on Genscape’s estimate, the processing rate decreased about 0.7 percent from June to July.

Released up to three weeks ahead of the NASS report, Genscape’s national NASS estimate for July 2016 is 157.4 million bushels. This reflects an average processing rate of 5.08 million bushels per day nationally, down from June’s NASS statistic of 5.14 bushels per day.

Genscape’s National NOPA & NASS Estimates

Genscape monitored facilities represent about 22 percent of the total U.S. soybean crush population and 24 percent of the NOPA population. A new monitored facility in Illinois was added in July.

With Genscape’s extensive monitoring, clients receive near-real-time alerts of plant outages that can have significant impacts on soybean production. For example, Genscape monitors found that AGP’s Mason City, IA plant had been down since early July, but resumed processing around 4:00PM ET on Monday, August 8.

The National Oilseed Processors Association (NOPA) Crush Report provides a look at the U.S. soybean crush numbers based on its membership. The U.S. Department of Agriculture’s National Agricultural Statistics Service (NASS) provides an estimate on soybeans processed based on a survey of the U.S. population as a whole.

With proprietary, real-time monitoring of a strong statistical sample of the U.S. soybean crushing population, Genscape composes its national outlook based on physical observations from key soybean processing facilities. The plant processing rates form the foundation for national outlooks. Genscape's R-squared correlations to the NOPA and NASS national statistics are both 0.99.

Genscape’s Soybean Crush Report provides insight with proprietary, real-time monitoring of a strong statistical sample of the U.S. soybean processing. The report is available up to seven days ahead of the NOPA report, and up to 30 days ahead of the NASS report, providing timely, impactful data that assists our clients in making better-informed decisions. To learn more about the report, or to request a copy of the full report for this month, please email sales@genscape.com.

Oil facility operations in Louisiana appeared to be mostly unfazed Aug. 16 by recent historic, deadly flooding.

Only two units were affected by the flooding: a 110,000 bpd crude distillation unit at Exxon’s 502,500 bpd Baton Rouge, LA, refinery and the 45,000 bpd hydrocracker at Motiva’s 230,000 bpd Covent, LA, refinery, which was previously shut. The Baton Rouge CDU was shut Aug. 16 as flooding disrupted operations at an associated LPG storage facility, according to Reuters. Flooding was reported around the Convent hydrocracker on Aug. 12 in conjunction with clean-up efforts following a fire at the unit on Aug. 11, according to Reuters. All other monitored units at the Convent and Baton Rouge refineries operated normally Aug. 16, according to Genscape.

No other refinery units monitored by Genscape were known to be affected by flooding as of Aug. 16. 

Most of the oil facilities in southeast Louisiana are located in 500-year floodplains, which have a 0.2 percent chance of flood hazard, according to the U.S. Federal Emergency Management Agency's National Flood Hazard Layer.

The unprecedented flooding, that began late last week in some parts of Louisiana, resulted in the deaths of 10 people, ABC News said in an article on Aug. 16. On Aug. 12, Louisiana Gov. John Bel Edwards declared a state of emergency for the state of Louisiana due to flooding, according to the state’s website. A spokesman for the Governor’s Office of Homeland Security and Emergency Preparedness was not immediately available to comment.

No crude-by-rail deliveries were received at St. James, LA, terminals Aug. 12 to Aug. 14, according to Genscape. However, three-day periods of inactivity are not uncommon. A unit train unloaded at the NuStar facility on Aug. 15, according to Genscape.

Crude flows on the Marathon-operated 1.2mn bpd Capline Pipeline originating in St. James were also unaffected.

St. James waterborne shipments were also seemingly unhampered by high water. Between Aug. 12 and Aug. 15, three vessels loaded about 1.185mn bbls from St. James, and four vessels delivered about 1.284mn bbls into the crude hub. 

Access the most extensive and up-to-date look at the daily status of refinery operations in the United States with Genscape's North American Refinery Intelligence Service. Genscape's approach provides a comprehensive view of refinery utilization by product class across the three most-important geographic regions in the United States. To learn more or request a free trial, please click here.

Gain insight into the market with the industry's most comprehensive crude-by-rail data with Genscape's PetroRail Report. Genscape provides fundamental rail loading and unloading volume data, forward-looking and trend market analysis, and spot assessments for U.S. crude benchmarks. To learn more or request a free trial, please click here.

Make better informed trading decisions with insight into where the marginal barrel of oil is going by referencing Genscape's North American Waterborne Crude Report. Genscape provides a weekly overview of U.S. Jones Act vessel & waterborne crude import volumes moving in the West, East & Gulf Coasts with market analysis & freight cost assessments. To learn more or request a free trial, please click here.

On August 11, 2016 the Northeast experienced significant volatility in the real time markets. The volatility was expected as it was the hottest day in the summer, but there were force majeure events that added to the risk.

New England

The real time prices in New England settled well above the day ahead cleared prices. The highest Mass Hub real time print on August 11 was $2,690.60 at 13:55, when real time demand cleared 24.4 gigawatts (GW). The peak demand for the day was 25.0 GWs, which was the highest so far for this summer. 

The last time New England experienced Mass Hub prices this high was on December 4, 2014 at 16:55, when the real time print settled at $2,661.57 and actual load was 17.7 GWs. 

On August 11, New England cleared 21.8 GW in the day ahead, while the actual demand peaked at 25.0 GW. This meant that New England had to make up 3.2 GW of generation in the real time market.

The market had plenty of supply to meet demand, but at approximately 10:00 ET, New England tripped Millstone 2, a nuclear power plant in Connecticut with a capacity of 875 megawatts (MW). 

This baseload generator trip put New England in a tough position, resulting in a shortage condition and forcing New England ISO to implement contingency processes to manage the grid and work to meet the extreme load conditions. 

New York

New York was also experiencing the hottest weather of the summer, with a peak load of 32.0 GWs. On top of the hot weather in New York, they were exporting energy off to New England and Ontario, but importing from PJM and Hydro-Quebec during the peak hours.

Ontario is an export market as they generally have surplus energy and the relative weakness of the Canadian dollar makes exporting energy from Canada to the US more attractive. Although Ontario is generally an export market, they were importing energy from New York, as they had two nuclear units trip offline. The day ahead OPA cleared flows to New York from Ontario was 40 MW, but real time OPA flows were 80 MW from New York to Ontario.

On top of flowing energy to Ontario, they were also flowing energy to New England. The day ahead on-peak average (OPA) cleared flows to New England were 556 MW, while the real time OPA flows were 665 MW. The day ahead OPA spread between New York and New England was $9.11, while the real time spread averaged $176.22. 

In summary, New England was short energy and saw prices that have not occurred since the polar vortex. Since it was the hottest day of the summer, there was limited amount of generation available from adjacent markets. The Millstone 2 unit tripping in New England pushed New England over the edge, putting them in a tough position. The sequence of events made for an interesting market in both New England and New York.

Genscape’s Market Intelligence team, comprised of 50 analysts, meteorologists, and technologists, picked up on these generator trips and formulated a view on the markets, providing Genscape’s customers with actionable insights. In addition to access to the Market Intelligence team, Genscape’s PowerIQ service also includes daily reports on proprietary electric power data and intelligence to manage risk, minimize cost, and enhance profitability for both buyers and sellers. Click here to request a free trial of Genscape’s PowerIQ service. 

Access proprietary monitoring of transmission and generation facilities across North America with Genscape’s Power Real-Time (RT). Using thousands of patented in-the-field monitors, Genscape provides notifications of generation outages or changes, helping to better inform trading strategies, analyze production, and optimize asset utilization. To learn more or request a free trial, please click here.

Total U.S. Retail Demand Unhindered

Louisiana gasoline rack activity appears to be recovering from a period of low retail demand during a week of historic flooding in the state, particularly in Baton Rouge, LA, according to Genscape Supply Side data. However, the effect of the significant decline in Louisiana gasoline rack activity to total U.S. gasoline demand was likely mitigated by a strong week-on-week demand increase in the U.S. East Coast, Genscape said Aug. 19.  

As of Thursday, Aug. 18, Louisiana gasoline rack demand was just above 120,000 bbls, 13.6 percent below the previous Thursday, Aug. 11 and 10 percent below Thursday, Aug. 4. Baton Rouge gasoline rack demand also recovered to just under 60,000 bbls Aug. 18, 11.2 percent below Aug. 11 and 4.5 percent below Aug. 4.

Closer to the start of the flood event, Louisiana gasoline rack activity was as low as 66,000 bbls on Saturday, Aug. 13, 47 percent below the previous Saturday, Aug. 6. Also on Aug. 13, Baton Rouge gasoline demand retreated to around 18,000 bbls, 70 percent below the previous Saturday. Louisiana and Baton Rouge gasoline rack activity took several days to recover to levels prior to the historic flooding (see charts below). 

The unprecedented flooding, that began late last week in some parts of Louisiana, resulted in the deaths of 13 people, ABC News said in an article on Aug. 18. On Aug. 12, Louisiana Gov. John Bel Edwards declared a state of emergency for the state of Louisiana due to flooding, according to the state’s website. A spokesman for the Governor’s Office of Homeland Security and Emergency Preparedness was not available to comment.

The significant impact of the flooding to gasoline demand, as illustrated by rack activity, may have also suppressed U.S. Gulf Coast rack volumes for the week. For the week ending Aug. 19, PADD 3 gasoline rack volumes averaged 1.073mn bpd, 5.1 percent below the week ending Aug. 12.

But, the historic Louisiana flooding failed to make a dent in total U.S. gasoline rack activity, with rack volumes increasing 0.7 percent from the previous week to 6.723mn bpd for the week ending Aug. 19 thanks to strong growth in the East Coast, up 4.2 percent from the previous week. Genscape estimates that the weekly U.S. Energy Information Administration products supplied level will be 9.858mn bpd for the week ending Aug. 19, up 1 percent from the previous week. The EIA releases the data weekly on Wednesdays.  

Genscape's Supply Side Analyst and Supply Side Monitor provide analysts and traders with daily or hourly volumes and prices for regular gasoline, midgrade gasoline, premium gasoline, jet fuel, kerosene and diesel. Click here to request a free trial.  

Genscape’s soybean processing outlook, released a full week ahead of the National Oilseed Processors Association (NOPA) report, directionally agreed with the NOPA release on Monday, August 15, 2016. The reports indicated a decrease in the crush rate for July compared to June, with the median market expectation for the total soybeans crushed higher than the national statistic. 

On an absolute basis, the NOPA report indicated that Illinois had a substantially greater decline in processing compared to the national average, 17 percent for Illinois versus four percent nationally. Genscape reported outages equivalent to about 290,000 bushels (9,350 bpd) for the month of July at the Incobrasa facility in Gilman, IL. Additionally, there was a seven-day maintenance outage reported by CrushTraders at the Bunge facility in Cairo, IL. 

Even separating these outages from the regular processing activities for Illinois, the decline in processing statewide was still 12 percent based on the NOPA statistics, indicating that there were either some additional outages in Illinois in July or the plants were running at a low level. Based on the NOPA statistics, facilities in Illinois would have been collectively running at the normal processing rate of about 75 percent of a recent high in March, if there were no additional outages. 

The Southeast region of the U.S. also indicated a more substantial decrease in processing than the national rate decline, with a reduction of 12 percent from June to July. However, the Southeast indicated very strong processing rates in June, nearly a nine percent increase over May. This resulted in the processing rates reverting back to levels similar to prior months. 

For analysis purposes, Genscape often separates the “normal” processing rate from outages at plants. Separating the outages from the normal rate creates a basis to assess how the plants are running regionally and nationally based on a statistical sample. For instance, the figure below shows how Genscape’s monitoring in the Indiana NOPA region compares to the reported normal processing rate. 

Genscape uses a combination of remote sensing of individual plants, publicly available information, and other resources to assess outages on a real-time, daily, and monthly basis. Based on Genscape’s end of day outage report from August 25, three plants have been offline for three days or more out of the previous seven days. Two of these plant outages may not be anticipated by the market. Genscape monitoring indicated heavy truck traffic at one of these two facilities, either indicating the ready availability of beans or meal deliveries to support commitments. 

Genscape has a strong representation of soybean processing plants in the Iowa, Indiana, and Minnesota NOPA regions. The product coverage is growing with additional monitoring in Illinois, beginning with the addition of the Incobrasa facility in July. Easements for monitoring have been obtained for two additional facilities in the state, and Genscape also plans to add a monitored facility in Ohio in September. 

The USDA National Agricultural Statistics Service (NASS) soybean crushing statistic for July is scheduled for release on September 1 in the Fats and Oils report. On August 8, Genscape released its national outlook at 157.4 million bushels for July, an average processing rate of 5.08 million bushels per day, which was a decrease from the 5.14 bushels per day reported by USDA for June. No outages were observed from the Genscape-monitored non-NOPA facilities. If the July NOPA statistics are considered directly, the impact would be the outlook would change to 153.4 million bushels, all other things considered the same. This would translate to a national processing rate of 4.95 bushels per day.

Genscape’s Soybean Crush Report provides insight with proprietary, real-time monitoring of a strong statistical sample of the U.S. soybean processing. The report is available up to seven days ahead of the NOPA report, and up to three weeks ahead of the NASS report, providing timely, impactful data that assists our clients in making better-informed decisions. Click here to learn more about the report, or to request a copy of the full report for this month.

Over the last few months, spot power prices in Western Europe have begun to bounce back from a prolonged downward trend partly resulting from a rebound in commodity prices. Brent oil spot prices have risen from 40 $/bbl at the end of March to 50 $/bbl in August. Coal ARA prices rebounded last quarter reaching 51 $/tonne in June and now above 60 $/tonne. Meanwhile TTF natural gas prices have bounced back above 15 €/MWh beyond the November 2016 contract. This increase in commodity spot prices and a mixture of low wind outputs in Germany and The Netherlands combined with nuclear power plant strikes in France, have led to power spot price increases in Western Europe, as detailed in Genscape’s latest Power Market Insight Report.

Since the past quarterly report, Genscape saw a significant rise in forward power prices in Germany – the largest increase in year ahead prices since 2010. This was driven not only by the rise in coal and gas prices, but also by firmer spot prices. Despite the increase in commodity spot prices and a lower than originally expected nuclear availability (due to a postponed restart of reactors under maintenance), German monthly baseload spot power prices were very modest between March and May 2016. By early June, the confirmed rally in coal and gas prices combined with low wind outputs led to a jump in spot power prices which established on average at 27 €/MWh in June 2016. Will we see more substantial gas to coal switching as global coal price continues to rise, or will the smaller but still significant European natural gas price rise offset this?

While French spot prices were as expected for March and April 2016,  the spot prices were 2-5 Euros above expected in May and June. At the time of the Spring Report, the French forward curve was quite depressed on the back of consistently low spot prices through Q1 2016 due to mild weather and low demand. Since then, Genscape has seen a significant forward curve rally of about 25 percent as the market has priced in a more ‘usual’ risk premium reflecting price levels closer to 2014 and 2015. As seen in the chart below, it seems that the rally in Q4 2016 and Q1 2017 has risen faster than the fundamentals support, as forward prices are significantly above our latest quarterly report scenario for this period, although the remainder of the forward curve looks well priced.

The recent rebound in power forward prices is also in part due to the announcement by the French Energy Ministry that France will implement unilaterally a carbon price floor in the power sector (the final carbon price proposal was delivered on July 11). The latest information suggests that this carbon price will only apply to coal-fired units as a generic application to all the thermal units could threat the French security of supply.

The application details of this carbon floor will be presented with France’s next budget law in September. It should correspond to a penalty equivalent to 30 €/tCO2 to the French coal-fired units from 2017. Due to all the uncertainties around this new law, it has not been implemented in our base scenario, though its impact has been analyzed in a variant. The application of such a carbon floor would have a significant impact on power prices which could reach 40 €/MWh during the coldest months of the year, very much in line with the latest forward prices.

The impact on the total French CO2 emissions – the main objective of the law – is expected to be significant for the French power sector, illustrated in the chart below. The question remains as to what will be the final detail of the policy. And will other governments follow the British and French example?

The highlights presented in this blog post have been taken from the 11th issue of Genscape’s EPSI Quarterly Market Report. This report utilizes the EPSI Platform to analyze key topics in European power markets and provide an overview of recent market events and updated scenario results for Germany, France, and The Netherlands. The current issue also includes a special focus on the Hungarian power market. If you are interested in receiving this report, please contact genscapesales@genscape.com.

Genscape's European Power Market coverage is enhanced with the EPSI Platform, which uses a combination of market insight, thorough data research, relevant data streams, and rigorous quality control to provide unparalleled depth and quality of data focused on the fundamentals of the European power markets. To learn more about the EPSI Platform or to request a call, please click here.

During the second quarter 2016 earnings update, the Lower 48 independents increased their CAPEX guidance for the year by $517.65 million versus Q1 2016 earnings update. The expansion in CAPEX is mostly concentrated in increasing drilling activities by rig additions in areas like Permian, SCOOP & STACK, and Appalachia. Also, several companies decided to expand completions activities in the 2H 2016 compared to their previous plan. A rise in CAPEX guidance has led to a modest increase of about 371 MMcfe/d, or 62 Mboe/d, in production guidance for 2016 suggesting that the bulk of the rise in CAPEX is geared towards 2017 production growth. 

Since the end of Q2'16 to the end of August, producers in the Lower 48 have added about 77 oil rigs and 11 gas rigs. At the end of the earnings season, about 27 different E&P companies (in Genscape's coverage universe) decided to increase their active rig counts and two companies decided to cut their active rig counts bringing the aggregate of 52 rigs being added in the 2H 2016, which is in accordance with Genscape’s rig forecast. From the end of June 2016 to December 2016, Genscape's forecast suggests an increase of about 160 oil rigs and 40 gas rigs in the Lower 48. According to Genscape's Equity Insight sample data, almost 50 percent of the 52 rigs are being added to the Permian Basin, with Pioneer Resources leading the chart with five new rigs. After the Permian, Appalachia is next up in the rig addition chart. Leading the rig scoreboard in Appalachia is Gulfport, who has decided to keep their three rigs for the rest of the year and add another one, versus initially dropping all their rigs. According to our weekly rig count numbers by company by region, at the end of June 2016, these 28 companies had an active aggregate rig count of 62 in their respective regions. With an addition of 52 rigs, the total rig count will be 114. (Source: RigData)

Even though most companies are starting to talk about adding, we do see some still dropping rigs. For example, we have seen Hess in Bakken dropping two of their four rigs. Hess said, "We plan to drop to two rigs in August and will begin to increase activity when oil prices approach $60 per barrel." Along with Hess, PDC also decided to drop one rig in DJ Basin but primarily due to improved drilling efficiency.

Genscape's Equity Insight tracks CAPEX guidance and production guidance of about 70+ E&P companies who have operations in the Lower 48. Our E&P coverage universe represents about 40 percent of the total natural gas production and 38 percent of the total crude oil production and a very large percentage of publicly traded E&P companies. In addition, Genscape's Equity Insight tracks daily volumes by company by region for 27 E&P companies and 5 Midstream companies in our coverage universe, which we continue to expand. To learn more, or request a free trial, please click here.

After filing for financial protection and being banned from calling at U.S. ports, troubled container carrier Hanjin could be releasing berthing slots at most of the largest container ports in the U.S. and around the world. This raises the question for clients as to what happens to the cargos already in transit on Hanjin ships and scheduled to be delivered into the U.S. 

While it operates less than five percent of the global TEU capacity, Hanjin is still the largest Korean container carrier, and its demise would leave a gap in the Korean market. Hanjin accounts for more than 20 percent of services at each of the Korean container ports, including the largest, Busan.

Hanjin lists 36 ships as owned by the company, with a total capacity of 274,000 TEU. However, latest liner schedules for global container operators indicate 51 ships scheduled under the Hanjin name with capacity of about 300,000 TEU. Clearly charter leases have been lapsing as the company’s financial problems have been escalating. 

Monitoring Activity of the Hanjin Fleet

The activity and schedules of the Hanjin fleet can be easily monitored through Genscape Vesseltracker.

Using the Genscape Vesseltracker tools, it is easy to add the fleet to a personal list of ships and then monitor them on the cockpit display.

Zooming to Long Beach shows one Hanjin ship now anchored and one approaching, though reports indicate that it may not be allowed to enter the port.

By adding the Hanjin vessels to a list, one can review their current positions and destinations.

Email alerts may also be setup to send emails or SMS messages when ships enter specific regions, port areas, or custom areas drawn on a map.

Genscape Vesseltracker provides the tools to monitor the changing trade patterns with a combination of ship schedules, containerized ships, and traffic analysis tools for monitoring other current and historic traffic. Genscape Vesseltracker currently runs one of the largest privately owned AIS receiver networks on the planet, combined with the largest AIS Satellite constellation currently available, with over 144,000 vessels tracked daily in near real-time. To learn more or request a free trial of Genscape Vesseltracker, please click here. 

The November ICE Brent futures contract price declined following a Genscape notice released on September 7 regarding the recent restart of BP’s 1.15 million bpd Forties Pipeline System. The pipeline’s outage contributed to a price increase on September 6.

The system was shut for about two days, while all the processing trains at the Kinneil fractionation terminal were down from about 9:01 p.m. (GMT) on September 4 to 11:26 p.m. (GMT) on September 6, according to Genscape. Barrels on the Forties pipeline system flow to the fractionation terminal were stabilized for consumption. Genscape detected that Forties pipeline flow can be affected by issues at the terminal’s gas fractionation trains. 

By 3:40 p.m. (GMT) on September 7, the ICE Brent price decreased by $0.73/bbl to $46.97/bbl, which followed Genscape noticing that the Kinneil Train 1 and 2 fractionation units were restarted and Forties pipeline flow had resumed at 12:21 p.m. (GMT). Flow rose to about 586,000 bpd on September 9 and remained above 450,000 bpd on September 14.

Prior to the restart alert, Brent increased about 1.5 percent or $0.72/bbl to $47.89/bbl at 4:55 a.m. (GMT) on September 6 from when Genscape alerted subscribers that all processing trains at the Kinneil fractionation terminal were shut on September 4. News of the pipeline shutdown, along with a weaker U.S. Dollar helped par losses from changing OPEC production freeze rhetoric. “The U.S. Dollar Index declined by a tad over 1 percent September 6 providing some positive support for the oil complex on a day when the Saudi Energy Minister said there was no need to freeze crude oil output for now, even though they signed a pact with Russia the day before to cooperate in world oil markets," said Dominick Chirichella of Energy Management Institute on September 6. 

Additionally, a one-month maintenance is scheduled for the Buzzard oilfield beginning September 17, reducing Forties output. According to Reuters, several cargos were delayed or dropped due to lower than expected supply. The Buzzard oilfield is the main constituent to Forties pipeline flow. 

The Forties Pipeline System has an oil processing capacity of 1.15 million bpd and flows from the Forties Unity platform to the Kinneil crude stabilization plant. From there, stabilized oil is delivered either directly to ship at Hound Point, to tank at Dalmeny, or to the refinery at Grangemouth.

Access Genscape's Forties Supply Chain Service to receive timely insightful alerts. They not only highlight variations in the real-time pipeline flow, but also underline events that affect the key operating units at Kinneil and Grangemouth. The daily snapshot of oil storage, pipeline, shipment, and refinery activity provides a valuable overview of Forties exiting the system. Genscape has an extensive in-the-field network of high-tech, proprietary monitors that provide real-time tracking and measurements of production levels, cargo shipments, outages, and other key factors. To learn more, or request a free trial of Genscape's Forties Supply Chain Service, please click here.

Here at Genscape we place tremendous value on our Internship Program. We view this as an opportunity to contribute to the development of the next generation of talent. By providing our interns with the opportunity to develop their skill set and expand their knowledge, we are helping them launch their career.

ARA gasoil stocks increased to a record high of 6.416mn MT the week ending September 9 after a 175,000 MT build. This marked the  highest stock level since Genscape began monitoring the area in August 2012. Storage levels are likely to continue to build in ARA with a net increase of 639,805 MT of gasoil predicted to enter the area in the next few weeks, according to Genscape shipping data. 

The rise in stocks the week of September 9 was the second consecutive weekly increase for ARA gasoil stocks, with storage levels up 337,000 MT between August 26 and September 9. The record high the week of September 9 was 93,000 MT higher than the previous record high of 6.323mn MT reached week ending July 15.

During the release time of Genscape’s weekly gasoil inventory report at 8 a.m. (GMT) on September 14, the ICE Low Sulphur Gasoil Futures contract price traded near $417.75/MT. Following the data release, the ICE Low Sulphur Gasoil Futures contract declined $7.75/MT in six hours to near $410/MT by 2 p.m. (GMT).  

On September 9, the ICE Low Sulphur Gasoil 12-month spread was $46.50/MT, the widest since August 11 when the spread was $63/MT. Since the week ending August 26, the spread widened $8.25/MT, and gasoil storage levels increased 337,000 MT. Between August 22 and September 15, the ICE Brent Crude Oil front month contract did not close above the $50/bbl-mark. On September 1, the price closed at a low of $45.45/bbl. 

Genscape monitored a similar stocking pattern in previous years. In 2015, stocks built 2.573mn MT to 5.976mn MT between March 13, 2015 and September 4, 2015, the highest level recorded at that time. Due to the recent oversupply of oil and relatively mild winter this year, gasoil supplies did not fall as significantly as in previous years, and therefore did not have as strong of a building pattern. Between March 11 and September 9, 2016, gasoil stocks increased 419,000 MT, leaving storage levels on September 9, 415,000 MT higher than the same week one year prior.

The recent continuous build of gasoil stocks can likely be attributed to low demand during the summer months as terminals stock up for the upcoming colder months. In addition, a net increase of 102,420 MT of gasoil entered the ARA area the week of September 9, likely contributing to the record high. According to Genscape shipping data, the majority of the gasoil entered through Rotterdam, with 205,160 MT of gasoil discharged in the area. 

On September 9, the ARA terminals utilized 71 percent of the gasoil capacity, up one percent from one-week prior and just below the record high capacity utilization of 76 percent reached on October 16, 2015. Out of the 33 locations holding gasoil in ARA, 20 had capacity utilization rates above 70 percent the week of September 9.

Out of the 746 tanks monitored in ARA holding gasoil, only 76 out of 669 operational tanks, or 11 percent, utilized less than 15 percent of the tank’s capacity. Of those operational tanks, 413, or 62 percent, utilized over 80 percent of the tank’s capacity. In comparison to the previous record high on July 15, 419 out of 630 operational tanks, or 67 percent, utilized more than 80 percent of the tank’s capacity.

Following the most recent International Energy Agency data release on September 13, Genscape weekly gasoil inventory data was tracking at a 98 percent correlation. 

Receive accurate and timely fundamental data to gain insight into the most critical component of the European oil supply with Genscape’s ARA Refined Product and Crude Storage Reports. These reports measure tank-by-tank physical inventories for gasoline and naphtha, jet fuel, crude oil, and gasoil. To learn more, or request a free trail of Genscape’s ARA Refined Product and Crude Storage Reports, please click here.

New report estimates U.S. motor gasoline demand two days before the Energy Information Administration’s Weekly Petroleum Status Report

September 20, 2016, Houston, TX - Genscape recently began publishing on Mondays an estimate for the previous week’s total U.S. gasoline demand, giving subscribers a preview of similar U.S. Energy Information Administration data published Wednesdays.

Genscape’s Weekly Gasoline Demand Report furthers the company’s footprint as a provider of refined products fundamentals and offers essential retail gasoline demand data two days before it is published in the EIA’s Weekly Petroleum Status Report.

The EIA’s Total U.S. Motor Gasoline Products Supplied estimate of gasoline demand drives trading decisions on gasoline futures. Through analysis of actual transactions at the gasoline rack level, Genscape predicts the EIA demand figure within an average of 1 percent difference on Monday. The Genscape gasoline demand number is derived from the company’s Supply Side Monitor hourly rack-city data.

“In 2009, Genscape revolutionized crude oil industry fundamental data with the launch of the Cushing Storage Report, giving traders and analysts exceptional transparency into market fundamentals with advance notice storage data for the industry’s most-watched hub a full two days ahead of the EIA survey,” said Suzanne Evans, Director, Products and Pricing Assessments Development, “This year, Genscape is pushing the envelope when it comes to fundamental data for refined products markets with its Weekly Gasoline Demand Report and Supply Side rack-level data products.”

The Weekly Gasoline Demand Report, published via email at 10:30 AM Eastern Time each Monday, is available only to subscribers to Genscape’s Supply Side Monitor and Analyst products. The Supply Side products provide analysts and traders with daily and hourly volumes and prices for regular gasoline, midgrade gasoline, premium gasoline, jet fuel, kerosene, and diesel across 400 rack cities. Both products allow subscribers to leverage the industry’s only insight into PADD and rack-city-related volumes and average prices for wholesale transactions of refined products.

To learn more or request a free trial of Genscape’s Weekly Gasoline Demand Report, visit genscape.com/gasoline-demand-report-launch or watch this short video on the report here: genscape.com/gasoline-demand-report-video

To view the full press release, visit: Genscape Launches Weekly Gasoline Demand Report

About Genscape

Genscape is the leading global provider of real-time data and intelligence for commodity and energy markets, driven to improve market transparency and efficiency. With thousands of patented monitors strategically deployed worldwide, Genscape is unique in its ability to collect and report proprietary market fundamentals in real-time or near real-time. Genscape delivers innovative solutions across a number of asset classes including: Oil, Power, Natural Gas and LNG, Agriculture, Petrochemical and NGLs, Maritime, and Renewables. Genscape clients often gain important insights, improve risk management, or increase operational efficiency. For more information, please visit: www.genscape.com

For all press inquiries please contact:

Nicola Segal
Marketing Specialist
Office: + 1 617 790 0935
nsegal@genscape.com

Colonial Pipeline’s Line 1 outage has slashed gasoline rack activity in several key cities in the southeastern U.S., according to Genscape’s Supply Side data. Various media reports of unbranded racks shuttering in Colonial Pipeline-supplied cities were supported by Genscape daily rack level gasoline data. 

Several states in the southeastern U.S. were affected by the Line 1 outage, including Georgia, Tennessee, and North and South Carolina (see graph). Line 1, a 1.3 million bpd line, carries gasoline from Pasadena, TX, to Greensboro, NC. The effects of the outage on rack cities supplied by spurs off Colonial’s Line 1 appear to be more pronounced. 

Colonial Pipeline shut parts of Line 1 September 9 due to a 252,000 gallon (6,000 barrels) leak, affecting deliveries in Alabama, Tennessee, Georgia, North Carolina, and South Carolina, the company said in a bulletin to shippers viewed by Genscape. Colonial said it expects the line to resume service next week. The company is pumping gasoline on Line 2, typically a distillate line, it said.

Rack activity in Georgia appeared to recover during the weekend. Atlanta, GA rack activity was only down two percent Sunday, September 18 from the previous week. By comparison, Atlanta rack volumes Thursday, September 15 and Friday, September 16 were 26 percent and 19 percent below the previous week. This recovery was likely thanks to waterborne deliveries into Savannah, GA, and Colonial allowing gasoline to move on Line 2, a 1.1 million bpd distillate line that twins Line 1.

Genscape tanker data showed that the Ohio, a Jones Act clean products tanker, was diverted from New York into Savannah last week. It loaded on Sunday, September 12 at Valero's Texas City, TX, refinery and partially discharged (about 275,000 barrels) at the Colonial Oil Terminal in Savannah on Sunday, September 18, before heading to Charleston, SC.  The cargo was reported to be gasoline, according to market sources.

Activity in other Georgia rack cities that are supplied by Colonial – Athens, Bainbridge, Columbus, and Macon – also showed significant recovery over the weekend. On Saturday, September  17 and Sunday, September 18, Athens total gasoline rack volumes were up 47 percent and 42 percent, respectively, week-on-week. On Friday, September 16, Athens rack activity was down 10 percent from the previous week.

However, the Colonial outage still affected total gasoline rack activity in Tennessee, North Carolina, and South Carolina. Nashville, TN, rack activity was the hardest hit with Saturday, September 17 and Sunday, September 18 volumes 69 percent and 62 percent below week-ago levels. In Chattanooga, total gasoline rack activity over the weekend was 50 percent (Saturday) and 38 percent (Sunday) below levels seen the previous week. Most Tennessee rack cities depend on gasoline supply from spur lines off Colonial Pipeline’s Line 1 mainline and Kinder Morgan’s Plantation pipeline. Nashville, however, does not have Plantation connectivity.

In South Carolina, North Augusta was affected the most by the outage, with Saturday, September 17 and Sunday, September 18 gasoline rack activity 73 percent and 74 percent below the previous week. North Augusta does not have access to Plantation; it only has connectivity to Colonial’s Line 1 via a spur from Belton, SC.

Also, the Colonial Line 1 outage continued to affect rack activity in North Carolina, where Lines 1 and 2 terminate at Greensboro and the northern-origin Lines 3 and 4 begin. In Selma, total gasoline rack volumes were 30 percent (Saturday) and 48 percent (Sunday) below the previous week. Greensboro rack activity Saturday, September 17 was as much as 43 percent below week ago levels, but slightly recovered Sunday, September 18 to 16 percent below the previous week. On Saturday, September 17, Fayetteville gasoline rack activity was more than 40 percent below the previous week, but recovered Sunday, September 18 to 35 percent above the previous Sunday.

Colonial Pipeline's Line 1 outage also affected total U.S. rack activity for the week ending September 16. Average total gasoline rack activity fell to 6.406 million bpd, the lowest level since the week of April 29, according to Genscape Supply Side data.

Genscape's Supply Side Analyst and Supply Side Monitor provide analysts and traders with daily or hourly volumes and prices for regular gasoline, midgrade gasoline, premium gasoline, jet fuel, kerosene and diesel. To learn more, or request a free trail of Genscape's Supply Side Analyst and Supply Side Monitor.

Summer 2016 featured above normal temperatures across much of the contiguous United States. In the East and Southwest warm anomalies were strongest, which drove strong cooling load. The majority of the key U.S. power markets experienced stronger year-over-year peak demand. According to NOAA, population-weighted cooling degree days (PWCDDs) totaled at 1,030, 25 percent stronger than average.

Overview:

The dissipation of El Niño marked an important transition in the climate regime. Combined with very warm waters in the Atlantic, this new pattern played in key role in driving strong temperatures throughout the summer. Starting with June, a strong upper ridge developed across the Northern Plains and Rockies that delivered intense heat from Kansas City west through Denver. By July and August, the strongest ridging and most pronounced warm anomalies became focused across the eastern U.S. August registered as the warmest on record for the Northeast climate region with an average temperature anomaly of +4.7°F. Meteorological summer registered at the fifth warmest on record, tied with 2006 with an average temperature anomaly of +2.12°F!

East Coast:

June 2016 featured marginally above normal temperatures across NYISO, ISO-NE, and PJM. Despite the warmth, the lack of  sustained heat to kick-start cooling load, as well as frequent thunderstorm activity across PJM, caused demand to verify below month expectations. After the slow start, hot and humid conditions started to build during July before peaking in August. This caused cooling demand to soar to the highest levels since 2013, with summer demand peaks occurring in August for the first time since 2009. 

Midwest and Lower Mississippi:

The summer season featured a fair amount of variability month-to-month, but as a whole the Midwest and Lower Mississippi Valley saw warmer than average conditions. The above average warm temperatures were in line with the forecast signal, although the peak summer temperatures were slightly weaker than anticipated. Peak demand occurred in late July, in line with a typical cooling load season. June featured warm anomalies focused to the west, while August featured warm anomalies focused east, including several of the major Midwest demand centers. Above average precipitation was a feature for both the Midwest and Lower Mississippi Valley, helping to maintain humidity levels but at times blunted peak cooling load. 

Plains:

Summer got off to a strong start across the Central and Northern Plains, driving strong energy demand across the SPP footprint during June. Temperatures verified four to six degrees above normal from Tulsa northward into Omaha, with several days featuring peak highs in the middle to upper nineties. Progressing into July, seasonal temperatures were noted across the Central Plains. Meanwhile, above normal temperatures were focused in Texas, driving a consistently strong ERCOT demand. Despite near seasonal temperatures for Texas, an impressive stretch of heat the week of  August 8 propelled ERCOT to a new all-time demand record of 71.2GW on August 11, within 200 MW of our summer peak forecast. Temperatures in June and August verified near expectations for the Central and Northern Plains with slightly warmer than expectations in Texas.

West:

Despite the bullish start to the summer, demand fell shy of our summer peak load forecast of 47 GW in CAISO. Weak La Niña coupled with drought feedback led to southern California temperatures verifying five to seven degrees Fahrenheit above average through June. Anomalous June warmth in Southern California drove SCE to see its highest demand (23,564 MW) in the past five years. While temperatures in the Pacific Northwest verified in line with Genscape’s forecast for June, higher frequency of low pressure troughing in the Pacific Northwest through July prompted temperatures to trend slightly below average in eastern Washington and Oregon. July demand got off to a bearish start in California driven by slightly cooler than average temperatures, but hot late July temperatures led to peak demand in CAISO. Widespread warmth continued across the Western footprint through August, with persistent high pressure in the eastern Pacific focusing the warmest anomalies (+3ᵒ to +4ᵒ) along the Northern California and Oregon coasts.

Genscape's Power Market Services provides access to accurate and timely data on capacities, flow, and utilization of power. Weather can have a large impact on power demand and generation, especially with the seasonal extremes seen across the U.S. in these summer months. Industry insight on significant weather events can forecast future patterns, helping market participants make more informed trading or business decisions. Click here to learn more about the full range of Genscape's Power Market services.

Construction activity appeared to progress September 8 on Energy Transfer Partners' 470,000 bpd Dakota Access crude pipeline, according to Genscape aerial images. The flight was a day before federal agencies issued a joint statement stopping work on a portion of the pipeline that will originate in North Dakota and terminate in Illinois.

On September 9, the U.S. Department of Justice, the U.S. Department of the Army, and the U.S. Department of the Interior halted construction beneath as well as within 20 miles east or west of Lake Oahe. The large reservoir connected to the Missouri River in North Dakota supplies drinking water to the Standing Rock Sioux Tribe, which filed a civil suit against the U.S. Army Corps of Engineers and Dakota Access LLC on July 27. The U.S. Court of Appeals for the District of Columbia scheduled oral arguments on the emergency injunction on October 5, said a court order on September 21.

In June, Iowa state officials withdrew another stop-work order that had been imposed at the Big Sioux River on the Iowa/South Dakota border because tribal representatives objected to disrupting American Indian land which includes burial grounds. The order was lifted after Dakota Access, LLC, agreed to use special boring equipment to locate the pipeline 85 feet beneath the river, according to the Des Moines Register.

The Dakota Access pipeline will transport crude from six terminals in the Bakken region of North Dakota (Stanley, Ramberg, Epping, Trenton, Watford City, and Johnson’s Corner) to the Patoka storage field in southern Illinois. The pipeline will be served by a total of three main pumping stations in North Dakota, South Dakota, and Iowa, according to schematics released by Energy Transfer Partners. Once operational, the pipeline, which is expandable to 570,000 bpd, should lower volumes of crude transported by rail from the Bakken region. It is anticipated that Dakota Access will supply the Energy Transfer Crude Oil Pipeline (ETCOP), providing long-haul service from Patoka to Nederland, TX, and is expected to be operational by the end of 2016, according to the company.

Dakota Access, LLC stated pipeline construction is greater than 60 percent complete, which is consistent with Genscape aerial imagery. Much of the pipeline right-of-way (ROW) consists of intermittent stretches of completed and cleared ROW. Significant stretches of cleared ROW include strung piping material yet to be installed. Additionally, “trenching” activity beneath road intersections and waterways was visible along much of the ROW, including at the Mississippi River and the Big Sioux River on the South Dakota/Iowa border, where special boring equipment is required. Trenching precedes “stringing” pipeline along the ROW, which occurs in preparation of connecting the piping material.  

Three main pumping stations are being constructed: at the trunk-line origin in Johnson’s Corner, ND, in eastern South Dakota, and in central Iowa north of Des Moines. At Johnson’s Corner, two storage tanks are near completion but neither has pipeline connectivity. Completed ROW leads to and from the Spink station in South Dakota, but pipeline adjacent to both sides of the facility were exposed at the time of the flight. Three pumps at the station are nearly complete. Construction crews and material were observed on site at the time of the flight. Construction of the Story facility north of Des Moines is also advancing as three pumps are nearly finished. Only minimal construction material and no construction crew were visible. Strung pipeline was observed within the cleared ROW leading to and from the station, which is adjacent to Interstate 35. Trenching remains to be completed beneath the interstate. Construction also remains at the aforementioned Bakken terminals, where storage tanks, pumps, and piping material remain to be installed.

Beginning nearly 22 miles northwest of the contested ROW at Lake Oahe, pipe stringing ends and only land clearing has been completed. Land clearing ceases roughly two miles from Lake Oahe. No construction crews were observed within this two mile segment northwest of the lake. Immediately southeast of the lake, cleared land resumed as clearing equipment and a small amount of piping material were spotted.

A large staging area for piping material was observed approximately 98 miles northwest of the storage field at Patoka, IL. A significant amount of piping remains at the site. Buried but exposed pipeline was spotted at a road intersection adjacent to Patoka. Another staging area for piping material was observed at Patoka, where exposed pipeline was visible within the storage area, indicating pipeline connection to delivery tanks is nearly complete.

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In August, Hanjin Shipping Co. filed for bankruptcy protection and was banned from calling at U.S. ports. Since then, the carrier’s troubles have only continued to grow. The question remains, however, of what will happen to its fleet. Recent reports speculate that Hanjin will likely begin to sell some of its most valuable ships soon as the company head towards liquidation. 

During this interim period ahead of these sales, understanding the location and status of Hanjin’s fleet is important, especially for those whose cargoes are on board. Since June, there has been a steep decline in the number of port calls for ships in the Hanjin fleet, as they have been banned from calling at several ports around the world, including the U.S. Here is a quick snapshot of a sampling of Hanjin’s container ships from Genscape Vesseltracker, including their long-term tracks since September 1, positions, and declared destinations:

Hanjin Africa, U.K., Container Ship, IMO: #9502910

Hanjin Algecrias, Malta, Container Ship, IMO: #9443047

Hanjin America, U.K., Container Ship, IMO: #9502946

Hanjin Ami, Hong Kong, Container Ship, IMO: #9630391

Hanjin Aqua, Panama, Container Ship, IMO: #9632480

Hanjin Argentina, Singapore, Container Ship, IMO: #9632765

Hanjin Asia, U.K., Container Ship, IMO: #9502867

Hanjin Europe, U.K., Container Ship, IMO: #9502908

After the departure from Eurogate the unloaded "Hanjin Europe" dropped anchor off Heligoland with supplies for 17 days left, adjacent to the fully loaded "Hanjin Harmony", which left out the calls at Antwerp and Rotterdam, but could not enter the port of Hamburg.

Hanjin Gdynia, Panama, Container Ship, IMO: #9389409

Hanjin Greece, Liberia, Container Ship, IMO: #9484948

Among the first Hanjin ships to berth at U.S. ports in September after weeks of idling in the water, the "Hanjin Greece" was expected to berth on September 21 at the Port of Oakland. For the sake of customers with cargo on those ships, we’re glad this day has finally come,” said Port of Oakland Executive Director Chris Lytle in a statement. “Businesses can’t operate with products stuck at sea.” The Hanjin Greece will unload about 450 loaded import containers in Oakland, according to the port. 

Hanjin Miami, German, Container Ship, IMO: #9290476

Container ship "Hanjin Miami" was waiting to unload at Maher Terminals LLC in Elizabeth and finally received authority to dock on September 22. The ship is loaded with televisions, computers, and other merchandise headed for retailers.

Hanjin Milano, Marshall Islands, Container Ship, IMO: #9431680

Hanjin Shipping has ordered its container ship "Hanjin Milano" to drop anchor outside the heads at Patrick Stevedores Container Terminal in an attempt to prevent authorities seizing the vessel under the order of creditors.The stranded crew are thought to have around two weeks of food supplies. 

Hanjin Scarlet, Panama, Container Ship, IMO: #9624287

The "Hanjin Scarlet" which had been unloading Port of Prince Rupert, British Colombia, was arrested on September 14 in the afternoon, while preparing to leave port bound for Seattle. The vessel was arrested by terminal operator DP World that is claiming $1.6m in unpaid bills from Hanjin ships. The "Hanjin Scarlet" had been calling at DP World’s Fairview Terminal after a deal had been struck with the terminal operator and CN Rail to offload boxes.

Genscape Vesseltracker provides the tools to monitor the changing trade patterns with a combination of ship schedules, containerized ships, and traffic analysis tools for monitoring other current and historic traffic. Genscape Vesseltracker currently runs one of the largest privately owned AIS receiver networks on the planet, combined with the largest AIS Satellite constellation currently available, with over 144,000 vessels tracked daily in near real-time. To learn more or request a free trial of Genscape Vesseltracker, please click here.