Friday, August 5, 2016
Inventory Trends reports from the National Propane Gas Association (NPGA), available at npga.org/inventorytrends, confirm that U.S. propane stocks are quickly rising from their March bottom, this despite pressure from exports early in the year. That pressure came after the commissioning of Enterprise Products’ Houston Ship Channel terminal expansion. Nonetheless, propane is now continuing its seasonal rise this summer. Further, mid-July inventory data from the Energy Information Administration (EIA) shows that higher stock levels are indeed the new normal, NPGA asserts.
“The market has gained wisdom over the past several months and realized that greater inventory needs to be held to ensure adequate days of demand as exports grow,” notes the association. “Inventories in mid-July are at levels similar to those seen last year, and again are near record highs for the summer season. Market acceptance of higher inventory being the new normal has manifested itself in propane prices strengthening versus crude.”
George Koloroutis, chairman of NPGA’s Propane Supply and Logistics Committee, emphasizes that propane days of demand is a critical measurement that all marketers should have in their focus. “In the Inventory Trends report this important indicator forecasts the number of days — at each month’s rate — that primary inventories would satisfy demand. Higher demand requires higher levels of inventory to be held to maintain the days ahead,” he explains.
The ThompsonGas executive vice president and COO outlines that the calculation for the Trends Report is done on a macro level, considers all inputs and outputs, and computes what eventual days of demand are for primary inventories. “And in the new export environment this is something we should all look at monthly,” he says. “But let me also point out the fact that this exercise can also be done at a more micro level. In fact, some propane marketers I know perform this calculation on their own to determine the days of demand they have at each of their storage locations. It can be as simple as adding up loads — trucks or railcars — that you have scheduled to be delivered in a given month and then netting your daily sales — deliveries to customers — against that number. This is smart supply management and it can prompt a marketer to take the correct action — adding or canceling deliveries — before something goes wrong.”
Debnil Chowdhury, director at IHS Markit and manager of the consultancy’s North American natural gas liquids service, adds, “The new normal moving forward — to keep prices in line with historical ratios to crude — will be to hold more inventory to maintain days of supply. If we ever reach inventory levels near the historical norms, prices most likely will be very high during that time period as the market will be tight.” And he underscores that most of the nation’s high propane volumes are in the Gulf Coast, since that is the region where the majority of new export capacity is located. “This is important to note, because even though inventory appears to be high as a whole compared to historical five-year values, most of this is due to PADD 3. A cold winter could lead to a situation where we appear to be well stocked when looking at the U.S. numbers as a whole, but have shortages in the Midwest or Northeast, which would put upward pressure on prices.”
NPGA’s Trends Report comments that while propane exports grew slightly in April, they remained well below the high volumes witnessed during the first two months of the year due to weak arbitrage and maintenance at the Enterprise terminal. Data released in July by the U.S. Department of Commerce shows May exports rising 31.8% over April to reach 27,711,170 bbl, up 6,688,304 bbl month on month. For the year, exports jumped 53.3%, or by 9,637,928 bbl, compared to May 2015. Nevertheless, NPGA reports IHS Markit Waterborne data shows that exports are expected to remain lower over the summer months as arbitrage remains weak, adding that regional arbitrage had closed and seven or more export cargos had been deferred in July. In addition, pressure from lower freight rates due to a well-supplied fleet and the opening of the Panama Canal expansion June 26 have helped keep arbitrage between the U.S. and Japan low. As well, Europe and Japan are reported to be well supplied.
“Moving into the winter months, exports are expected to increase as demand sees its seasonal growth in Asia and the Phillips 66 terminal begins operations in October,” says NPGA. “It is expected that if the pace of production slows, exports will continue — albeit at lower rates than earlier in the year — at the expense of petrochemical cracker demand.”
Phillips 66 is scheduled to bring its Freeport, Texas LPG export terminal online in the second half of this year as part of its Sweeny Hub initiative. The new facility will provide 4.4 MMbbl a month of export capacity, the equivalent of eight very large gas carriers (VLGCs). The terminal is located on the site of a crude oil import marine terminal and utilizes existing Phillips 66 midstream transportation and storage infrastructure. Export terminal infrastructure includes a 550,000-bbl refrigerated propane storage tank, LPG salt dome storage, and four refrigeration trains. There are two LPG-capable loading docks and two loading arms per dock. Two ships can be loaded simultaneously at a rate of up to 36,000 bbl an hour.
Meanwhile, gas plant production data, courtesy of IHS, shows a reversal for the propane production declines seen in December and January. NPGA reports gas plant propane production is expected to grow in 2016, despite the decline in rig counts. The association explains the contradiction is due to increasing production of NGLs from drilled, but uncompleted, wells (DUCs). However, the production growth rate will be much slower than that witnessed during the shale boom.
IHS expects the bottom for rig counts to be set in the second quarter this year. Thereafter, higher crude prices should provide the incentive for redeployment of wells. “This should help ensure continued propane supply, but may lead to a flattening of production as the DUC inventory declines. This phenomenon, combined with export pressure due to the startup of the Phillips 66 terminal, may lead to lower days of supply than witnessed last year.”
“We expect gas plant production to grow slightly in 2016 versus 2015 — 4.3% in the latest inventory report,” says Chowdhury. “This is a slowdown from the growth we have seen during the shale boom. Refinery production in 2016 is expected to be higher than 2015. Although run-rates are about the same as last year, stronger prices led to less internal burning of propane within refineries starting in March of 2016. We expect this to be the case for the rest of the year unless crude prices fall substantially again, leading to [refinery] power-generation economics favorable to propane and encouraging internal burning.”
NPGA recounts that, with the exception of PADD 5 (the West Coast, Alaska, and Hawaii), all other PADDs exited winter 2015-2016 with healthy propane inventories. PADD 5 should see stocks rise now that PBF Energy’s 155,000-bbld Southern California refinery in Torrance is back online. Koloroutis’ view is that those robust end-of-winter inventories within most PADDs were due to a combination of strong production, stalled exports, and warm weather. He adds, “Marketers are supply-planning better thanks to the educational steps taken by NPGA. If last year was cold, there would have been regional outages and transportation asset shortages — trucks and railcars. But for those that planned accordingly, they would have been in good shape.”
Koloroutis says there were lessons learned from winter 2015-2016. “In my mind it validated the importance of the three following points: Actively manage your supply plan and keep your storage topped off. Things can change fast today. Be prepared. Second, read the Trends Report. Learn to read it, and if you don’t know how to, ask someone on the PS&L (Propane Supply and Logistics) Committee. I am happy to help anyone, by the way. And don’t limit your attention to your PADD or region only. Look at the other PADDs because it will ultimately have an impact on you if another PADD’s inventory levels move down or up dramatically. Third, make sure you have a win/win relationship with our suppliers. You each share the same objective as you each want to sell as much propane as possible.”
On the infrastructure side, Koloroutis observes that many projects have stalled in the new “lower for longer” crude oil price environment. “This has slowed exports as well. I think keeping your eye on crude oil prices, if not daily, then at least weekly, is something that should earn the attention of a marketer. Obviously, low prices slow infrastructure growth and high prices increase infrastructure growth and production. At some point, OPEC will grow weary of keeping prices down, and I can assure you the rest of the world already has. There will be a surge in crude pricing again, but the million-dollar question is: When? I don’t know the answer, but I have a feeling it is not too far away.”
Chowdhury characterizes the biggest stall in propane infrastructure as under-utilization of burgeoning export capacity. “Phillips 66 coming online in October of 2016 will make that problem worse. It appears that we are OK with gas processing capacity and fractionation capacity for the next several years. Over the next two to three years there may need to be some investments in pipeline capacity to allow Marcellus/Utica production to find its way down to the Gulf Coast.”
NPGA’s Trends Report notes that, although not a huge concern in the past, it is important for the global and domestic propane markets to now closely monitor the hurricane season. “As the U.S. has gone from being a small player in the export market to being the largest, the world depends on it for supply. One major hurricane can greatly affect export capacity and have ripple effects on global propane supply and pricing.”
The association, eyeing other weather trends, comments that the latest forecast calls for the likelihood of a La Niña condition to develop this fall, replacing El Niño, but the odds have been dropping. Effects for the two normal weather patterns vary according to the severity of the events. However, generally La Niña conditions favor a more active storm track, above-normal precipitation, and cooler weather over a wide area of the Pacific Northwest. Precipitation anomalies could also extend through the Intermountain West and across sections of the North Plains and into the Great Lakes region. The South could experience something different from the El Niño condition that now exists. Drier and milder weather conditions could extend from the Four Corner states across the South and Central Plains all the way to Florida.
NPGA reports that weather forecasters gain additional accuracy toward the winter months, which may lead to more aggressive propane demand forecasts and tighter markets. “A cold winter could lead to a situation where the overall U.S. market appears to be well supplied on a cursory level, but regional shortages, especially in PADD 2, occur, leading to sharp rises in price differentials,” says the association. “Well, if La Niña happens, which we all hope it does, there could be some regional tightening of propane supply and transportation assets,” Koloroutis adds. “But at this point we are in a wait-and-see position as we move closer to the crop drying peak season and closer to our demand season.”
Northeast
RBN Energy (Houston) wrote in June that the U.S. Northeast now produces all the propane and butane it needs on an annual basis, but because of the seasonal nature of demand in the region, and what it described as “a dearth of in-region storage,” a lot of NGL production needs to be railed to storage elsewhere during the warmer months, then be moved back to meet wintertime needs. “This propane/butane back-and-forth raises costs and reduces producer netbacks. Surely there is a better way,” the consultancy commented.
Citing EIA statistics, RBN Energy observed that NGL production in the wet Marcellus and Utica shale plays has been rising steadily. In 2012, production in PADD 1 from natural gas processing plants averaged less than 50,000 bbld, but by March 2016 it had risen to 321,000 bbld, including 115,000 bbld of ethane, 118,000 bbld of propane, 37,000 bbld of normal butane, 17,000 bbld of isobutene, and 34,000 bbld of pentanes-plus, or natural gasoline. Ohio, part of PADD 2, adds to the regional totals. “The boom in Northeast NGL production has posed a real challenge to producers and midstream companies as demand for propane and butane swing sharply between summer and winter with heating demand for propane and motor gasoline blending demand for normal butane—and there is only a limited amount of NGL storage capacity in the region,” RBN points out.
Part of the storage solution may come from Denver-based Mountaineer Storage LLC, which has concluded a successful open season for its proposed salt dome storage near Clarington, Ohio. The open season resulted in requests for more than three times the amount of initial planned capacity, sponsors report. The project should break ground in early 2017 with a planned in-service date of early 2018. The Mountaineer project calls for offering up to 2 MMbbl of initial storage capacity with more than 40,000 bbld of load-in and load-out. The facility will store ethane, propane, butane, and Y-grade products for the growing number of gas processors, producers, and commodity traders interested in the burgeoning wet-gas production from the Marcellus and Utica shales.
David Hooker, managing director of Mountaineer NGL Storage, said that scaled development began in late May. “We’ll begin the permitting process for LPG storage, initiating a 3-D seismic shot over the property, drilling a test well, and coring the salt to confirm its suitability for LPG storage,” he said. “We’re pleased to see that the support of this project in the heart of the Marcellus/Utica wet gas shale play is as strong as it is. The Mountaineer NGL Storage project is strategically placed to provide service to the expanding network of pipelines, rail, truck, and barge infrastructure that is currently being built to transport Marcellus and Utica natural gas liquids throughout the Northeast and Mid-Atlantic.”
The planned facility is located along the Ohio River and will utilize the Salina salt formation in the Ohio River Valley. The formation is about 6300 to 6700 feet below the surface and has been used for NGL storage in other parts of the U.S. The project will be constructed in phases and it is anticipated there will be multiple caverns. The project initially is expected to have truck and rail facilities, with future design capabilities for pipeline and river barge transportation.
RBN Energy says it is likely the best use of additional NGL storage in the Northeast would be for propane and butane. Ethane, although also lacking adequate storage, can still be cleared through rejection into the natural gas stream when there is surplus for cracker demand. It can also be transported out of the region on the Mariner East pipeline to the Marcus Hook, Pa. export terminal, on the Mariner West pipeline to the Sarnia petrochemical complex, or on the ATEX Pipeline to Mont Belvieu.
During any given year, propane demand in the region can swing from 100,000 bbld during the spring and summer months to nearly 400,000 bbld or higher during cold winter months, notes RBN. More than 80% of the propane demand in PADD 1 comes from the residential and commercial sectors. “If EIA did track rail and truck movements for propane between PADDs, you would see significant volumes of propane leaving PADD 1 during the spring and summer months due to lack of storage capacity and insufficient demand. Most of those rail movements have been via relatively expensive manifest or partial trainload shipments,” RBN reports, adding that at least one unit train was scheduled in March.
But if more storage was available locally, product wouldn’t necessarily have to leave the region at all. As well, after the Mariner East 2 pipeline expansion to Marcus Hook comes online, “more propane will be able to move directly from Marcellus/Utica producers to international customers. That is planned for mid-2017, though we keep hearing about the possibility of more delays.”
RBN concludes that “while the Northeast has become a hydrocarbon-production powerhouse, the economic benefits of that triumph are being watered down by the need to shuttle large volumes of propane and butane out of the region, and back in, rather than storing it close to where it is produced and close to where it will ultimately be consumed. The Mountaineer NGL Storage project seems to offer at least a partial fix. But at current levels of production, and with future growth possible, even more NGL storage capacity in the region is warranted.”
Panama Canal
EIA observes that June 26 marked the day the Panama Canal Authority opened a third set of locks that allow the transit of larger ships, the first such expansion since the canal was completed in 1914. However, because of the economics of shipping, trade patterns, and the types of ships used to transport crude and petroleum products, the latest expansion is expected to have limited effects on most petroleum markets.
However, it is recognized that the new canal expansion could be expected to improve the logistics of U.S. propane exports. Previously the canal’s size restrictions required ship-to-ship transfers, which created bottlenecks for U.S. exports to Asian markets. The new, larger Panama locks will allow a majority of VLGCs, the type of ship that carries most propane and other hydrocarbon gas liquids, to transit, likely reducing or perhaps eliminating the need for ship-to-ship transfers.
EIA comments that U.S. propane exports have increased significantly over the past three years, but only after market participants overcame several challenges in transporting propane to their customers. After largely overcoming the first challenge — building sufficient export capacity — the next challenge involves economically transporting large volumes of propane over long distances. The recent, although likely temporary, solution has resulted in import and export data abnormalities affecting U.S. propane exports to Asian countries.
Asia, the largest regional destination for U.S. propane, imported 220,000 bbld of U.S. propane in 2015, or slightly more than one-third of the total U.S. propane exports. Most of those exports originated from the Gulf Coast and traveled through the Panama Canal or on long, more expensive routes that go across the Atlantic Ocean and then through the Suez Canal, or around Africa’s southern tip to destinations in Asia.
Transporting large quantities of propane over long distances requires specifically designed refrigerated ships. The largest, most economical class of these ships are VLGCs. Only a limited number of VLGCs with narrower, more upright hull designs were able to pass through the original Panama Canal lock dimensions. This changed when the new larger set of locks opened.
One method used to cut voyage times and costs within the constraints imposed by the old canal involved a ship-to-ship transfer, where the propane cargo of a larger vessel was transferred to a smaller ship that could transit. Once through the canal, the small ship would either continue on to Asia or transfer the cargo back to a larger vessel. The additional cost associated with using multiple ships was mitigated by cost and time savings from transiting the canal rather than taking longer, alternative routes that avoided the canal.
EIA reports this cargo transfer activity likely affected trade data. Much of the agency’s energy export data is based on information from the U.S. Customs and Border Patrol, which collects the final destination of an export, if known. Despite this requirement, some of the propane cargos exported from the U.S. that underwent a ship-to-ship transfer cited the jurisdiction of the transfer, not the cargo’s actual final destination. U.S. export data showed increased propane exports to countries in the Caribbean and Central America where the ship-to-ship transfers were taking place, but these countries do not have sufficient demand for, nor the infrastructure to store and distribute, such large quantities of propane.
For example, based on trade data, the U.S. exported 31,000 bbld of propane to Panama in 2014 and 23,000 bbld in 2015. However, the National Energy Secretariat of Panama reports total national propane consumption of only 1671 bbld in 2014 and 1736 bbld in 2015. Similarly, Aruba, an island nation of about 100,000 people with no major source of demand such as a petrochemical facility or propane-fired power plant, reported 23,000 bbld of propane imported from the U.S. in 2015.
This discrepancy, EIA maintains, affected import data in Asian countries. Both China and Japan have begun to report propane imports from Panama, even though Panama does not produce any propane. Therefore, these propane volumes were likely U.S.-sourced propane that underwent ship-to-ship transfers in Panamanian waters. But not all cargos that underwent ship-to-ship transfers were necessarily destined for Asia. The ports and territorial waters of Central American and Caribbean countries were also likely locations for large cargos of propane to break-bulk, where large cargos are divided into several smaller ones to better accommodate regional demand.
The new, larger Panama Canal locks allow the majority of the world’s VLGC fleet to transit, which will likely reduce or end the practice of ship-to-ship transfers of U.S. propane designed for Asian markets. That outcome will reduce discrepancies between import and export statistics, providing greater clarity on the major markets for increasing U.S. propane exports.
Lower-Cost Drilling
Upstream, in what may be a boon in the longer term to rig counts, research indicates there is significant upside potential for U.S. oil and gas operators to apply lower-cost unconventional drilling and completion technologies to boost production from tight conventional reservoirs. The analysis by IHS Markit is based on the assessment of nearly 46,000 U.S. horizontal wells completed between 2010 and 2015. It studies how unconventional drilling and completion technologies could be applied to the redevelopment of conventional wells in the top 39 established U.S. tight conventional plays where the major shale plays are also being developed.
The key plays identified that have the potential to better leverage horizontal technologies include the Rocky Mountain region’s Williston, Powder River, and Denver basins; the Permian Basin and Eagle Ford play in Texas; and the Mid-Continent region, including the Anadarko Basin. According to IHS Markit, the average global recovery factor for a conventional oil reservoir is 34%, with two-thirds of the oil still left behind in the ground. Many tight conventional oil reservoirs, however, demonstrate recovery factors of only 15% or less, which is substantially lower than the average recovery factor for conventional reservoirs.
“Our research indicates that there are significant potential benefits of applying some of the same drilling and completion techniques that have been used so successfully in the U.S. shale oil plays to increase recovery in these tight, U.S. conventional plays,” says Steve Trammel, director of North America well and production content at IHS Markit Energy. “We identified tight conventional plays that were tested with horizontal wells during the last five years, and in our study, which analyzed nearly 46,000 U.S. horizontal wells completed between 2010 and 2015, average initial potential (IP) test rates for the leading tight conventional plays compare favorably with the IPs of established shale oil plays. However, of the horizontal wells we analyzed, just 10% of the horizontal wells drilled were in tight U.S. conventional plays, so there is considerable potential here for operators.”
Trammel adds that leveraging these technologies is attractive to operators because the overall break-even costs to develop these projects are much lower and delivery infrastructure is already in place. “These tight conventional resources are in reservoirs with older vertical wells that can be reentered by horizontal drilling. The rock properties do not require the size and cost of a hydraulic frack job needed for an unconventional zone, and therefore these are much more economic for operators in the current low-oil-price environment.”
He explains that leveraging horizontal wells to further test tight conventional plays in these areas has led to the establishment of stacked plays with huge resource potential. “The plays in the Rocky Mountain region, in particular, have the majority of the highest-ranking tight conventional plays of those we studied in our IHS Markit Energy report, but tight conventional plays in Texas, including the Permian Basin and the Eagle Ford Fairway, also fared well in terms of potential for redevelopment.”
And the analysis includes an unexpected bonus for operators. “Our analysis identified 25 tight conventional sleeper plays that have been tested with only a few horizontal wells, but have average IP rates greater than 200 barrels of oil equivalent per day,” Trammel says. “In addition, shallow conventional plays may also offer opportunities for operators to leverage these unconventional technologies in the current oil price environment.”
—John Needham
“The market has gained wisdom over the past several months and realized that greater inventory needs to be held to ensure adequate days of demand as exports grow,” notes the association. “Inventories in mid-July are at levels similar to those seen last year, and again are near record highs for the summer season. Market acceptance of higher inventory being the new normal has manifested itself in propane prices strengthening versus crude.”
George Koloroutis, chairman of NPGA’s Propane Supply and Logistics Committee, emphasizes that propane days of demand is a critical measurement that all marketers should have in their focus. “In the Inventory Trends report this important indicator forecasts the number of days — at each month’s rate — that primary inventories would satisfy demand. Higher demand requires higher levels of inventory to be held to maintain the days ahead,” he explains.
The ThompsonGas executive vice president and COO outlines that the calculation for the Trends Report is done on a macro level, considers all inputs and outputs, and computes what eventual days of demand are for primary inventories. “And in the new export environment this is something we should all look at monthly,” he says. “But let me also point out the fact that this exercise can also be done at a more micro level. In fact, some propane marketers I know perform this calculation on their own to determine the days of demand they have at each of their storage locations. It can be as simple as adding up loads — trucks or railcars — that you have scheduled to be delivered in a given month and then netting your daily sales — deliveries to customers — against that number. This is smart supply management and it can prompt a marketer to take the correct action — adding or canceling deliveries — before something goes wrong.”
Debnil Chowdhury, director at IHS Markit and manager of the consultancy’s North American natural gas liquids service, adds, “The new normal moving forward — to keep prices in line with historical ratios to crude — will be to hold more inventory to maintain days of supply. If we ever reach inventory levels near the historical norms, prices most likely will be very high during that time period as the market will be tight.” And he underscores that most of the nation’s high propane volumes are in the Gulf Coast, since that is the region where the majority of new export capacity is located. “This is important to note, because even though inventory appears to be high as a whole compared to historical five-year values, most of this is due to PADD 3. A cold winter could lead to a situation where we appear to be well stocked when looking at the U.S. numbers as a whole, but have shortages in the Midwest or Northeast, which would put upward pressure on prices.”
NPGA’s Trends Report comments that while propane exports grew slightly in April, they remained well below the high volumes witnessed during the first two months of the year due to weak arbitrage and maintenance at the Enterprise terminal. Data released in July by the U.S. Department of Commerce shows May exports rising 31.8% over April to reach 27,711,170 bbl, up 6,688,304 bbl month on month. For the year, exports jumped 53.3%, or by 9,637,928 bbl, compared to May 2015. Nevertheless, NPGA reports IHS Markit Waterborne data shows that exports are expected to remain lower over the summer months as arbitrage remains weak, adding that regional arbitrage had closed and seven or more export cargos had been deferred in July. In addition, pressure from lower freight rates due to a well-supplied fleet and the opening of the Panama Canal expansion June 26 have helped keep arbitrage between the U.S. and Japan low. As well, Europe and Japan are reported to be well supplied.
“Moving into the winter months, exports are expected to increase as demand sees its seasonal growth in Asia and the Phillips 66 terminal begins operations in October,” says NPGA. “It is expected that if the pace of production slows, exports will continue — albeit at lower rates than earlier in the year — at the expense of petrochemical cracker demand.”
Phillips 66 is scheduled to bring its Freeport, Texas LPG export terminal online in the second half of this year as part of its Sweeny Hub initiative. The new facility will provide 4.4 MMbbl a month of export capacity, the equivalent of eight very large gas carriers (VLGCs). The terminal is located on the site of a crude oil import marine terminal and utilizes existing Phillips 66 midstream transportation and storage infrastructure. Export terminal infrastructure includes a 550,000-bbl refrigerated propane storage tank, LPG salt dome storage, and four refrigeration trains. There are two LPG-capable loading docks and two loading arms per dock. Two ships can be loaded simultaneously at a rate of up to 36,000 bbl an hour.
Meanwhile, gas plant production data, courtesy of IHS, shows a reversal for the propane production declines seen in December and January. NPGA reports gas plant propane production is expected to grow in 2016, despite the decline in rig counts. The association explains the contradiction is due to increasing production of NGLs from drilled, but uncompleted, wells (DUCs). However, the production growth rate will be much slower than that witnessed during the shale boom.
IHS expects the bottom for rig counts to be set in the second quarter this year. Thereafter, higher crude prices should provide the incentive for redeployment of wells. “This should help ensure continued propane supply, but may lead to a flattening of production as the DUC inventory declines. This phenomenon, combined with export pressure due to the startup of the Phillips 66 terminal, may lead to lower days of supply than witnessed last year.”
“We expect gas plant production to grow slightly in 2016 versus 2015 — 4.3% in the latest inventory report,” says Chowdhury. “This is a slowdown from the growth we have seen during the shale boom. Refinery production in 2016 is expected to be higher than 2015. Although run-rates are about the same as last year, stronger prices led to less internal burning of propane within refineries starting in March of 2016. We expect this to be the case for the rest of the year unless crude prices fall substantially again, leading to [refinery] power-generation economics favorable to propane and encouraging internal burning.”
NPGA recounts that, with the exception of PADD 5 (the West Coast, Alaska, and Hawaii), all other PADDs exited winter 2015-2016 with healthy propane inventories. PADD 5 should see stocks rise now that PBF Energy’s 155,000-bbld Southern California refinery in Torrance is back online. Koloroutis’ view is that those robust end-of-winter inventories within most PADDs were due to a combination of strong production, stalled exports, and warm weather. He adds, “Marketers are supply-planning better thanks to the educational steps taken by NPGA. If last year was cold, there would have been regional outages and transportation asset shortages — trucks and railcars. But for those that planned accordingly, they would have been in good shape.”
Koloroutis says there were lessons learned from winter 2015-2016. “In my mind it validated the importance of the three following points: Actively manage your supply plan and keep your storage topped off. Things can change fast today. Be prepared. Second, read the Trends Report. Learn to read it, and if you don’t know how to, ask someone on the PS&L (Propane Supply and Logistics) Committee. I am happy to help anyone, by the way. And don’t limit your attention to your PADD or region only. Look at the other PADDs because it will ultimately have an impact on you if another PADD’s inventory levels move down or up dramatically. Third, make sure you have a win/win relationship with our suppliers. You each share the same objective as you each want to sell as much propane as possible.”
On the infrastructure side, Koloroutis observes that many projects have stalled in the new “lower for longer” crude oil price environment. “This has slowed exports as well. I think keeping your eye on crude oil prices, if not daily, then at least weekly, is something that should earn the attention of a marketer. Obviously, low prices slow infrastructure growth and high prices increase infrastructure growth and production. At some point, OPEC will grow weary of keeping prices down, and I can assure you the rest of the world already has. There will be a surge in crude pricing again, but the million-dollar question is: When? I don’t know the answer, but I have a feeling it is not too far away.”
Chowdhury characterizes the biggest stall in propane infrastructure as under-utilization of burgeoning export capacity. “Phillips 66 coming online in October of 2016 will make that problem worse. It appears that we are OK with gas processing capacity and fractionation capacity for the next several years. Over the next two to three years there may need to be some investments in pipeline capacity to allow Marcellus/Utica production to find its way down to the Gulf Coast.”
NPGA’s Trends Report notes that, although not a huge concern in the past, it is important for the global and domestic propane markets to now closely monitor the hurricane season. “As the U.S. has gone from being a small player in the export market to being the largest, the world depends on it for supply. One major hurricane can greatly affect export capacity and have ripple effects on global propane supply and pricing.”
The association, eyeing other weather trends, comments that the latest forecast calls for the likelihood of a La Niña condition to develop this fall, replacing El Niño, but the odds have been dropping. Effects for the two normal weather patterns vary according to the severity of the events. However, generally La Niña conditions favor a more active storm track, above-normal precipitation, and cooler weather over a wide area of the Pacific Northwest. Precipitation anomalies could also extend through the Intermountain West and across sections of the North Plains and into the Great Lakes region. The South could experience something different from the El Niño condition that now exists. Drier and milder weather conditions could extend from the Four Corner states across the South and Central Plains all the way to Florida.
NPGA reports that weather forecasters gain additional accuracy toward the winter months, which may lead to more aggressive propane demand forecasts and tighter markets. “A cold winter could lead to a situation where the overall U.S. market appears to be well supplied on a cursory level, but regional shortages, especially in PADD 2, occur, leading to sharp rises in price differentials,” says the association. “Well, if La Niña happens, which we all hope it does, there could be some regional tightening of propane supply and transportation assets,” Koloroutis adds. “But at this point we are in a wait-and-see position as we move closer to the crop drying peak season and closer to our demand season.”
Northeast
RBN Energy (Houston) wrote in June that the U.S. Northeast now produces all the propane and butane it needs on an annual basis, but because of the seasonal nature of demand in the region, and what it described as “a dearth of in-region storage,” a lot of NGL production needs to be railed to storage elsewhere during the warmer months, then be moved back to meet wintertime needs. “This propane/butane back-and-forth raises costs and reduces producer netbacks. Surely there is a better way,” the consultancy commented.
Citing EIA statistics, RBN Energy observed that NGL production in the wet Marcellus and Utica shale plays has been rising steadily. In 2012, production in PADD 1 from natural gas processing plants averaged less than 50,000 bbld, but by March 2016 it had risen to 321,000 bbld, including 115,000 bbld of ethane, 118,000 bbld of propane, 37,000 bbld of normal butane, 17,000 bbld of isobutene, and 34,000 bbld of pentanes-plus, or natural gasoline. Ohio, part of PADD 2, adds to the regional totals. “The boom in Northeast NGL production has posed a real challenge to producers and midstream companies as demand for propane and butane swing sharply between summer and winter with heating demand for propane and motor gasoline blending demand for normal butane—and there is only a limited amount of NGL storage capacity in the region,” RBN points out.
Part of the storage solution may come from Denver-based Mountaineer Storage LLC, which has concluded a successful open season for its proposed salt dome storage near Clarington, Ohio. The open season resulted in requests for more than three times the amount of initial planned capacity, sponsors report. The project should break ground in early 2017 with a planned in-service date of early 2018. The Mountaineer project calls for offering up to 2 MMbbl of initial storage capacity with more than 40,000 bbld of load-in and load-out. The facility will store ethane, propane, butane, and Y-grade products for the growing number of gas processors, producers, and commodity traders interested in the burgeoning wet-gas production from the Marcellus and Utica shales.
David Hooker, managing director of Mountaineer NGL Storage, said that scaled development began in late May. “We’ll begin the permitting process for LPG storage, initiating a 3-D seismic shot over the property, drilling a test well, and coring the salt to confirm its suitability for LPG storage,” he said. “We’re pleased to see that the support of this project in the heart of the Marcellus/Utica wet gas shale play is as strong as it is. The Mountaineer NGL Storage project is strategically placed to provide service to the expanding network of pipelines, rail, truck, and barge infrastructure that is currently being built to transport Marcellus and Utica natural gas liquids throughout the Northeast and Mid-Atlantic.”
The planned facility is located along the Ohio River and will utilize the Salina salt formation in the Ohio River Valley. The formation is about 6300 to 6700 feet below the surface and has been used for NGL storage in other parts of the U.S. The project will be constructed in phases and it is anticipated there will be multiple caverns. The project initially is expected to have truck and rail facilities, with future design capabilities for pipeline and river barge transportation.
RBN Energy says it is likely the best use of additional NGL storage in the Northeast would be for propane and butane. Ethane, although also lacking adequate storage, can still be cleared through rejection into the natural gas stream when there is surplus for cracker demand. It can also be transported out of the region on the Mariner East pipeline to the Marcus Hook, Pa. export terminal, on the Mariner West pipeline to the Sarnia petrochemical complex, or on the ATEX Pipeline to Mont Belvieu.
During any given year, propane demand in the region can swing from 100,000 bbld during the spring and summer months to nearly 400,000 bbld or higher during cold winter months, notes RBN. More than 80% of the propane demand in PADD 1 comes from the residential and commercial sectors. “If EIA did track rail and truck movements for propane between PADDs, you would see significant volumes of propane leaving PADD 1 during the spring and summer months due to lack of storage capacity and insufficient demand. Most of those rail movements have been via relatively expensive manifest or partial trainload shipments,” RBN reports, adding that at least one unit train was scheduled in March.
But if more storage was available locally, product wouldn’t necessarily have to leave the region at all. As well, after the Mariner East 2 pipeline expansion to Marcus Hook comes online, “more propane will be able to move directly from Marcellus/Utica producers to international customers. That is planned for mid-2017, though we keep hearing about the possibility of more delays.”
RBN concludes that “while the Northeast has become a hydrocarbon-production powerhouse, the economic benefits of that triumph are being watered down by the need to shuttle large volumes of propane and butane out of the region, and back in, rather than storing it close to where it is produced and close to where it will ultimately be consumed. The Mountaineer NGL Storage project seems to offer at least a partial fix. But at current levels of production, and with future growth possible, even more NGL storage capacity in the region is warranted.”
Panama Canal
EIA observes that June 26 marked the day the Panama Canal Authority opened a third set of locks that allow the transit of larger ships, the first such expansion since the canal was completed in 1914. However, because of the economics of shipping, trade patterns, and the types of ships used to transport crude and petroleum products, the latest expansion is expected to have limited effects on most petroleum markets.
However, it is recognized that the new canal expansion could be expected to improve the logistics of U.S. propane exports. Previously the canal’s size restrictions required ship-to-ship transfers, which created bottlenecks for U.S. exports to Asian markets. The new, larger Panama locks will allow a majority of VLGCs, the type of ship that carries most propane and other hydrocarbon gas liquids, to transit, likely reducing or perhaps eliminating the need for ship-to-ship transfers.
EIA comments that U.S. propane exports have increased significantly over the past three years, but only after market participants overcame several challenges in transporting propane to their customers. After largely overcoming the first challenge — building sufficient export capacity — the next challenge involves economically transporting large volumes of propane over long distances. The recent, although likely temporary, solution has resulted in import and export data abnormalities affecting U.S. propane exports to Asian countries.
Asia, the largest regional destination for U.S. propane, imported 220,000 bbld of U.S. propane in 2015, or slightly more than one-third of the total U.S. propane exports. Most of those exports originated from the Gulf Coast and traveled through the Panama Canal or on long, more expensive routes that go across the Atlantic Ocean and then through the Suez Canal, or around Africa’s southern tip to destinations in Asia.
Transporting large quantities of propane over long distances requires specifically designed refrigerated ships. The largest, most economical class of these ships are VLGCs. Only a limited number of VLGCs with narrower, more upright hull designs were able to pass through the original Panama Canal lock dimensions. This changed when the new larger set of locks opened.
One method used to cut voyage times and costs within the constraints imposed by the old canal involved a ship-to-ship transfer, where the propane cargo of a larger vessel was transferred to a smaller ship that could transit. Once through the canal, the small ship would either continue on to Asia or transfer the cargo back to a larger vessel. The additional cost associated with using multiple ships was mitigated by cost and time savings from transiting the canal rather than taking longer, alternative routes that avoided the canal.
EIA reports this cargo transfer activity likely affected trade data. Much of the agency’s energy export data is based on information from the U.S. Customs and Border Patrol, which collects the final destination of an export, if known. Despite this requirement, some of the propane cargos exported from the U.S. that underwent a ship-to-ship transfer cited the jurisdiction of the transfer, not the cargo’s actual final destination. U.S. export data showed increased propane exports to countries in the Caribbean and Central America where the ship-to-ship transfers were taking place, but these countries do not have sufficient demand for, nor the infrastructure to store and distribute, such large quantities of propane.
For example, based on trade data, the U.S. exported 31,000 bbld of propane to Panama in 2014 and 23,000 bbld in 2015. However, the National Energy Secretariat of Panama reports total national propane consumption of only 1671 bbld in 2014 and 1736 bbld in 2015. Similarly, Aruba, an island nation of about 100,000 people with no major source of demand such as a petrochemical facility or propane-fired power plant, reported 23,000 bbld of propane imported from the U.S. in 2015.
This discrepancy, EIA maintains, affected import data in Asian countries. Both China and Japan have begun to report propane imports from Panama, even though Panama does not produce any propane. Therefore, these propane volumes were likely U.S.-sourced propane that underwent ship-to-ship transfers in Panamanian waters. But not all cargos that underwent ship-to-ship transfers were necessarily destined for Asia. The ports and territorial waters of Central American and Caribbean countries were also likely locations for large cargos of propane to break-bulk, where large cargos are divided into several smaller ones to better accommodate regional demand.
The new, larger Panama Canal locks allow the majority of the world’s VLGC fleet to transit, which will likely reduce or end the practice of ship-to-ship transfers of U.S. propane designed for Asian markets. That outcome will reduce discrepancies between import and export statistics, providing greater clarity on the major markets for increasing U.S. propane exports.
Lower-Cost Drilling
Upstream, in what may be a boon in the longer term to rig counts, research indicates there is significant upside potential for U.S. oil and gas operators to apply lower-cost unconventional drilling and completion technologies to boost production from tight conventional reservoirs. The analysis by IHS Markit is based on the assessment of nearly 46,000 U.S. horizontal wells completed between 2010 and 2015. It studies how unconventional drilling and completion technologies could be applied to the redevelopment of conventional wells in the top 39 established U.S. tight conventional plays where the major shale plays are also being developed.
The key plays identified that have the potential to better leverage horizontal technologies include the Rocky Mountain region’s Williston, Powder River, and Denver basins; the Permian Basin and Eagle Ford play in Texas; and the Mid-Continent region, including the Anadarko Basin. According to IHS Markit, the average global recovery factor for a conventional oil reservoir is 34%, with two-thirds of the oil still left behind in the ground. Many tight conventional oil reservoirs, however, demonstrate recovery factors of only 15% or less, which is substantially lower than the average recovery factor for conventional reservoirs.
“Our research indicates that there are significant potential benefits of applying some of the same drilling and completion techniques that have been used so successfully in the U.S. shale oil plays to increase recovery in these tight, U.S. conventional plays,” says Steve Trammel, director of North America well and production content at IHS Markit Energy. “We identified tight conventional plays that were tested with horizontal wells during the last five years, and in our study, which analyzed nearly 46,000 U.S. horizontal wells completed between 2010 and 2015, average initial potential (IP) test rates for the leading tight conventional plays compare favorably with the IPs of established shale oil plays. However, of the horizontal wells we analyzed, just 10% of the horizontal wells drilled were in tight U.S. conventional plays, so there is considerable potential here for operators.”
Trammel adds that leveraging these technologies is attractive to operators because the overall break-even costs to develop these projects are much lower and delivery infrastructure is already in place. “These tight conventional resources are in reservoirs with older vertical wells that can be reentered by horizontal drilling. The rock properties do not require the size and cost of a hydraulic frack job needed for an unconventional zone, and therefore these are much more economic for operators in the current low-oil-price environment.”
He explains that leveraging horizontal wells to further test tight conventional plays in these areas has led to the establishment of stacked plays with huge resource potential. “The plays in the Rocky Mountain region, in particular, have the majority of the highest-ranking tight conventional plays of those we studied in our IHS Markit Energy report, but tight conventional plays in Texas, including the Permian Basin and the Eagle Ford Fairway, also fared well in terms of potential for redevelopment.”
And the analysis includes an unexpected bonus for operators. “Our analysis identified 25 tight conventional sleeper plays that have been tested with only a few horizontal wells, but have average IP rates greater than 200 barrels of oil equivalent per day,” Trammel says. “In addition, shallow conventional plays may also offer opportunities for operators to leverage these unconventional technologies in the current oil price environment.”
—John Needham
