Dan Lippe
Petral Consulting Co.
Houston
In the 30-year period of 1975-2005, NGL production from US gas processing plants was constant at 1.6-1.8 million b/d, with production remaining within that range during the first 5 years (2005-09) of this article series. In 2010-19, gas plant NGL supply increased 2.35 million b/d (141%), reaching 5.1 million b/d in January 2020.
For the next 2 years, however, evaluation of the COVID-19 pandemic’s impacts on the midstream industry will supersede other topics as the focus shifts to how operators will adapt to fundamentally different market and economic circumstances.
Uncharted territory
Since 2000, the global community, at least twice, dodged potential viral pandemics, both of which are members of the coronavirus family. The first of these was severe acute respiratory syndrome (SARS), which originated in the Asia Pacific in late 2002. A decade later, Middle East respiratory syndrome (MERS), originating in Saudi Arabia, flared up. Both viruses, however, remained contained in their regions of origin.
Sometime in fourth-quarter 2019, millions of ordinary citizens in China’s Hubei Province were exposed to COVID-19, a new variant of the coronavirus that caused the 2002-03 SARS outbreak and MERS in 2012.
In January-February 2020, COVID-19 was a problem that seemed likely to be contained within China and neighboring countries. The US Centers for Disease Control (CDC) and World Health Organization (WHO) initially did not anticipate a global pandemic. Instead, the medical community expected the impact of this coronavirus variant would be limited to Hubei Province. At the time, none of the experts realized the COVID-19 outbreak began sometime in November, with the virus already spreading internationally due to extensive travel into and from China. The irreversible countdown to Pandemic 2020 had started, with acknowledgement in early March merely formal recognition of this fact. Given extensive global travel for winter holidays throughout the world, timing of the COVID-19 outbreak could not have been worse. Confirming data for these factors finally emerged during February and March.
In first-half March 2020, for the first time in modern history, most of the world’s nations ordered all nonessential businesses shuttered to limit person-to-person contact. Most—but not all (i.e., Brazil, Sweden)—nations also ordered all nonessential members of the workforce to stay home until further notice. These directives were based on preliminary mortality estimates on the same order of magnitude as the 1918-20 flu epidemic.
The global response to COVID-19 resulted in a major but temporary decline in demand for gasoline, diesel fuel, jet fuel, and marine bunker fuel, the four products accounting for at least 98% of refined products supply from US refineries.
Since January, the magnitude of collapsing demand for refined products has been the subject of substantial speculation from multiple sources. But in a global economy that depends almost exclusively on petroleum fuels for personal, commercial, and government transportation, the US Energy Information Administration (EIA) is the only government agency providing current data on crude oil production, refinery operating rates, and refined products production.
Until the last week of March and first week of April, EIA weekly statistical reports showed almost zero impact on US demand for gasoline and diesel, with only limited impact on jet fuel demand. If impacts on refined products demand outside North America had been as severe as some estimates suggested, the surge in crude and gasoline inventories in US storage facilities would have started much sooner than the last week of March.
Perception of the demand-decline severity—not the underlying reality—led to intense pressure on Russia and the Organization for Petroleum Exporting Countries (OPEC) crude oil producers to drastically reduce production. OPEC+ met in Vienna on Mar. 5-6 to confirm Saudi Arabia’s proposal that the production curtailment agreement be extended and production be further reduced by 2 million b/d. Russian oil companies, however, balked at Saudi Arabia’s insistence that they reduce production by an additional 500,000 b/d.
Without Russian participation, Saudi Arabia abruptly adjourned the meeting, announcing its intention to increase production from 9.5 million b/d to maximum production capacity (12.5-13.0 million b/d). United Arab Emirates and other Arab countries in the Persian Gulf region followed Saudi Arabia’s lead and announced their intentions to increase production. Since Saudi Arabia had agreed to reduce production to 8.5 million b/d, Russia’s decision to end its participation in OPEC+ compounded the impact of sharply dropping global demand for refined products with the promise of 4.5-6.0 million b/d of additional oil production.
The typical very large crude carrier (VLCC) can carry 2 million-bbl. For each additional 2 million b/d of crude oil exports, Middle East producers must arrange for at least 1 additional VLCC per day of round-trip transit. According to data from Ports.com, the distance between Ras Tanura, Saudi Arabia, and Chiba, Japan, is 8,003 nautical miles. At a speed of 12 knots, a VLCC will make each leg of the round trip in about 28 days. Including 3-5 days for loading and unloading, each VLCC is at sea or in port for 59-61 days. To accommodate 4 million b/d of additional crude oil exports, Middle East producers will require 118-122 additional VLCCs.
Despite major constraints and limitations, the market’s initial reaction to COVID-19 was instantaneous and extremely bearish. Spot prices for key global price benchmarks (West Texas Intermediate-Cushing, Dubai-Oman, and Brent) fell $10-16/bbl (30-50%) during the last 10-12 trading days of March. Spot prices in West Texas fell much more sharply ($19-22/bbl, 60-70%), with prices hitting lows of $7-10/bbl in the final trading days of March. Comparison with global price benchmarks suggests extensive short-selling activity in the WTI market. This summary of crude oil prices globally and locally is critical to this article’s emphasis on outlook rather than documentation of yesterday and today.
Crude oil, NGL production
Crude oil production in all major US basins except Oklahoma increased in second-half 2019. EIA statistics showed crude oil production in New Mexico and Texas was 5.8 million b/d in first-half 2019 and 6.2 million b/d in the second half. First and second-half 2019 production in North Dakota was 1.36 million b/d and 1.44 million b/d, respectively. These three states accounted for 84% of growth in US crude oil production. Many industry observers, discounting the importance of the number of drilled but uncompleted wells (DUC), focused on the decline in the number of drilling rigs in oil-directed service. These observers were, no doubt, surprised when production in New Mexico-Texas in fourth-quarter 2019 increased 302,000 b/d from the previous quarter. Production in Colorado-Wyoming, North Dakota, and the Appalachian basin (Ohio-Pennsylvania-West Virginia) also exceeded expectations.
The decline in prices in 2014-16 was insufficient to restore OPEC’s ability to manage the global market balance and simultaneously support prices at $60-75/bbl. Perhaps Saudi Arabia, Russia, and other key members of OPEC have realized the organization no longer can maintain a tight supply-demand balance as long as prices are strong enough to allow hundreds of US independent oil companies to drive production from oil-prone shale plays ever higher.
Regardless of OPEC’s intent, the demand crash in March-April 2020 was enough to trigger a major decline in oil prices for at least a few quarters. Saudi Arabia, however, took advantage of the opportunity to prevent any large rebound in oil prices for at least a few years. OPEC may have limited power to sustain prices at higher levels, but Saudi Arabia has demonstrated the group has power to impose a hard cap on prices indefinitely.
The strategic landscape for US midstream companies for the next 3-5 years has changed radically when compared with second-half 2019 and the previous 10 years. Despite a 13% decline in the Permian basin oil-directed rig count, however, the production increase in fourth-quarter 2019 was only 10% less than first-half 2019.
The only relevant historical comparisons that serve as guidance for US oil production in 2020-22 are trends in rig counts and crude production in 2015-16. In third-quarter 2014, oil prices were $95-105/bbl. When Saudi Arabia pulled the plug on oil prices in October 2014, prices fell 35-40% during the fourth quarter and continued declining in first-quarter 2015. As expected, Eagle Ford production began to decline in second-quarter 2014 and Bakken production in the third quarter. In the Permian basin, however—despite the oil-directed rig count declining in lock step with Eagle Ford and Bakken—production growth did not decline or even hold steady but accelerated. By yearend 2016, production had increased 400,000 b/d (37%).
Using production in fourth-quarter 2014 as the basis, Petral Consulting calculated a production index for Eagle Ford, Bakken, and Permian basins (Fig. 1). Eagle Ford production fell to 69.5% of the basis value in third-quarter 2017 and was only 81% of the basis value in second-quarter 2019. Similarly, Bakken production fell to 83.2% of the basis index in third-quarter 2016. In contrast to Eagle Ford, Bakken production growth resumed in fourth-quarter 2016 and exceeded the basis index volume in second-quarter 2018, rising to 16.5% above the basis index in second-quarter 2019. Permian basin production, however, never declined in 2015-16. Production in fourth-quarter 2016 was 25.9% more than the basis volume and 235.4% more than the basis volume in second-quarter 2019.
As was true in 2014, a sampling of views on US oil production indicates most analysts and producers are bearish on production for the next year or two. Permian basin oil production was the most important driver for US gas plant NGL production in 2015-16 and the basin will remain the most important for the next 3-5 years.
But the current downturn really is different based on examination of the facts, such as US oil-directed rig counts (Fig. 2). The Permian basin rig count in third-quarter 2014 was 554 and fell to 139 in second-quarter 2016 for a cumulative decline of 415 (75%). During the same period, the rig count declined 87% in Eagle Ford and 86% in Bakken. One reasonable explanation may be differences in the quality of the resource base. The quality of the shale plays in the Permian basin is better than in Eagle Ford. The number and variety of shale formations and sheer size of shale plays in the Permian basin are other reasonable explanations.
For purposes of evaluating the near-term outlook for the midstream industry, assume Permian basin oil production will probably decline by 10-20%. In mid-April, three major producers announced voluntary production curtailments totaling 730,000 b/d. A forecast showing declining oil production in Eagle Ford and Bakken is a much easier call, and a 20-40% reduction for two to four quarters is reasonable.
Production from the shale plays in Colorado (Niobrara) and Oklahoma (Cana-Woodford) did not have a bounce in fourth-quarter 2019. Production, most likely, continued to decline in first-quarter 2020, and decline rates will accelerate in the second and third quarters.
The linkage between crude oil production and NGL supply (excluding ethane) is very strong and very consistent. Petral Consulting’s midstream forecast methodology is based on crude oil production trends as the principal driver and single most important variable for gas plant NGL supply for forecast time horizons of 2-3 years. The linkage, as determined by a simple ratio of propane+ vs. crude oil, varies from region to region.
Fig. 3 shows historic trends in NGL production by region (see accompanying box for PADD regions). Fig. 4 shows trends in the ratio of propane+-crude production.
NGL raw-mix production
By 2016, US gas plant NGL production (ethane+) had already doubled from the historic average of 1.7 million b/d for 1990-2005. Production increased by 200,000-600,000 b/d annually in 2016-19, raw-mix supply reaching a peak of 5.1 million b/d in January 2020. As crude oil production (especially in West Texas) declines in second and third-quarters 2020, however, propane+ supply will also decline. Based on the propane+-crude oil ratio for the Permian basin, propane+ supply will fall at least 240,000 b/d in second-quarter 2020 and by 360,000 b/d or more if crude oil production is 1.1 million b/d less by June. US NGL production will be 4.0-4.2 million b/d in second-quarter 2020 and 4.3-4.6 million b/d in the third quarter.
Table 1 summarizes quarterly trends in US gas plant NGL plant production between 2015-20. Table 2 shows the propane+-crude oil production ratio from second-half 2018 through 2019.
A reduction in gas plant propane+ supply in the 240,000-360,000 b/d range will have a large impact on domestic and international LPG markets. Based on trends in NGL inventory in US Gulf Coast storage (2015-19), US midstream companies had an accumulated inventory surplus of 52 million bbl (minimum inventory in early 2019) to 92 million bbl (maximum inventory in late 2019). When we exclude ethane inventory, however, the accumulated surplus of propane+ inventory was 27 million bbl (monthly minimum for 2019) to 61 million bbl (monthly maximum for 2019). In 4-6 months, based on reduced gas plant production in West Texas alone, surplus inventory will be completely liquidated. Since gas plant NGL production in other basins (Colorado-Wyoming, Kansas-Oklahoma-North Dakota) will also decline, inventory surpluses in USGC storage will probably be depleted 1 month sooner.
Gas plant NGL production in the Appalachian basin (Ohio-Pennsylvania-West Virginia) is the wild card for the balance of 2020. In contrast to production ratios for the western basins, propane+-crude oil ratios for the Appalachian basin are notably higher than in West Texas. Because of the lack of pipeline distribution systems for crude oil-condensate production in the Appalachian basin, however, netback values to producers are much lower (zero to negative in mid-April 2020), and the percentage of production that will be shut in will be much higher.
At full recovery, propane production from US gas plants is 270,000-275,000 b/d and 18,000-20,000 b/d from refineries. In the “shut-in condensate production” scenario, gas plant supply will drop to 80,000-100,000 b/d, while refinery supply will fall to 12,000-15,000 b/d. Waterborne exports are likely to be only 40-50% of 2019 volumes in second and third-quarters 2020, with inventory build rates 65-75% of 2019 volumes. Propane wholesalers and retailers in northeast and upper US Midwest markets have a lot of uncertainty to work through before winter begins in fourth-quarter 2020.
Ethane recovery, rejection
Ethane production at full-recovery volumes has been chronically surplus to demand (domestic and international) since 2012 (Fig. 5). In 2019, ethane recovery varied within a range of 1.7-1.9 million b/d, while ethane rejection varied within a range of 0.6-1.0 million b/d (Fig. 6). In August through January, ethane rejection was 980,000 to 1-million b/d (Table 3).
In the Rocky Mountains, ethane rejection in second-half 2019 was 65% of estimated full recovery volumes vs. 55% in the first half of the year. In Williston basin (Bakken)—another high-cost ethane supply source—ethane rejection was 70% in second-half 2019 vs. 72% during the previous 6 months. In Ohio, ethane rejection in second-half 2019 was 86% vs. 91% in the year’s first half. The combined volumes of ethane rejection in high-cost basins was 675,000 b/d in second-half 2019.
As gas plant throughput rates fall, ethane recovery and rejection will decline but market supply will be sufficient to meet domestic demand, with the decline in market demand likely to offset the decline in production. If not, ethane rejection in low-cost basins (New Mexico-Texas, Kansas-Oklahoma) will decline enough to meet demand and exports.
Ethane rejection by gas plants in high-cost regions (Rocky Mountains, North Dakota, Ohio-Pennsylvania-West Virginia) was 425,000-450,000 b/d in third-quarter 2018 and 325,000-350,000 b/d in the following quarter. Ethane recovery costs in winter 2018 were 40-45¢/gal for Rocky Mountain gas plants and 60-68¢/gal for gas plants in Marcellus-Utica. Recovery costs for gas plants in North Dakota were 55-60¢/gal. All costs are based on full pipeline tariffs and fractionation fees in Mont Belvieu, Tex.
NGL market overview
Three markets account for more than 90% of US NGL demand:
- Petrochemical feedstock.
- Gasoline blending.
- International exports.
Export to a variety of international markets is the largest end-use for US propane and butane, and chemical feedstock markets (ethylene, propane dehydration, specialty chemicals based on isobutane feed) remain the largest volume market for total US NGL supply (ethane, LPG, and natural gasoline). All five NGL components are used as feedstocks in petrochemical production. Normal butane, isobutane, and natural gasoline are used in gasoline blending.
NGL exports were 1.82 million b/d in 2019, 853,000 b/d (88%) more than in 2015. Ethane exports increased to 280,000 b/d in 2019 but were 16% of total demand. LPG exports (propane, butane) were 1.37 million b/d in 2018, almost three times more than exports in 2014. Natural gasoline exports in 2019 were 168,000 b/d. Natural gasoline was the only NGL product for which exports in 2019 were less than in 2017-18.
The overview of domestic end uses focuses on chemical feedstock markets and refinery purchases (butanes, natural gasoline) for gasoline blending.
Petrochemical feedstock demand
Petral Consulting determines monthly ethylene production and feedstock demand by conducting an independent monthly survey of plant operating rates and feed slates to track consumption of purity ethane, ethane-propane mix, ethane, and propane contained in refinery offgas, purity propane (HD5), normal butane, natural gasoline, refinery-sourced naphtha, and gas oil.
US ethylene capacity reached 85 billion lb/year in first-quarter 2020. Nameplate capacity at yearend 2019 was 23 billion lb more vs. yearend 2015. Of this increase, most new plants were designed to run with 100%-purity ethane feed. During this period, producers in the USGC also retrofitted several multifeed plants to enhance purity ethane use.
Feedstock demand for NGL feeds (ethane, propane, normal butane, and natural gasoline) was 1.92 million b/d in 2019, reaching 1.96 million b/d in the fourth quarter. Ethane accounted for 79% of demand for all NGL feeds, with LPG accounting for 19% and natural gasoline only 1%. In 2015, ethane accounted for 69% of demand for NGL feeds, LPG 29%, and natural gasoline 2% (Fig. 7, Table 4). Demand and share of fresh feed were based on 190 million lb/day of ethylene production.
In response to changes in variable production costs for ethane vs. all other feeds, ethylene producers began adjusting feed slates in February-March 2020. Since ethane prices varied within a narrow range of 12-15¢/gal, variable production costs were 4-5¢/lb. Variable production costs for propane fell to 1.5¢/lb in March from 4.0¢/lb in January. Similarly, production costs for normal butane were negative (-1.5¢/lb) in March vs. 10¢/lb in January. Variable production costs for natural gasoline and similar light naphtha feeds fell to 3¢/lb in March from 24¢/lb in January.
In response to the emerging global economic recession, ethylene producers are likely to reduce operating rates to 75-80% of nameplate capacity for one or two quarters. During this period, total feedstock demand will decline, and ethane demand will fall more than its fair share due to sharp declines in spot prices for LPG and light naphtha feeds.
For as long as LPG and naphtha feeds yield lower production costs, ethylene producers will increase demand for these feeds, reducing ethane’s share of their feed slates. Developments in economic relationships between and among the various feeds will challenge USGC ethylene producers to test how much impact ethane retrofit projects had on practical feedstock flexibility of multifeed plants.
Petral Consulting expects total demand for all feeds will average 2.0-2.1 million b/d. If producers were able to run industry capacity at 90-92% of nameplate capacity, demand for fresh feed would increase to 2.5-2.6 million b/d. The difference between production rates of 170-190 million lb/day and 90-92% of nameplate capacity is 25-40 million lb/day (equivalent to 3-4.5 worldscale ethylene plants, each with a 3.3 billion-lb/year nameplate capacity).
Refinery butane demand
By mid-March 2020, US refiners were well into shifting to summer-grade gasoline production, and RVP-blending demand for gas-plant normal butane and refinery butane was nearing seasonal minimum volumes. In response to the extreme drop in refined products demand in domestic and international markets, refineries reduced operating rates, with gasoline production falling 3.1 million b/d during the last week of March and the first 2 weeks of April. During this 3-week period, gasoline production fell 3.7 million b/d (39%), while distillate fuel oil production in the second week of April was 208,000 b/d (4.4%) more than in the previous 4 weeks. As expected, US refineries demonstrated their capability to maintain smooth operations and simultaneously adjust their product mix to the drastic shift in demand for gasoline and jet fuel.
Refineries will continue to operate at reduced rates during second-quarter 2020 and perhaps during the third quarter as well. Consequences for butane markets will be substantial but will not impact refinery demand for normal butane, as demand would have fallen to minimum seasonal volumes anyway. Instead, refinery butane production during second and third-quarters 2020 will be 20-30% less than average. (Previously, a large fraction of refinery butane was simply transferred to merchant storage facilities for recycle in the following winter to meet the seasonal surge in RVP-blending demand.) This year, gas-plant normal butane and refinery butane supplies also will fall short of past years. The seasonal inventory build will be well below historic averages, and butane supply for RVP blending in winter 2020 also will be less than in the preceding 5-8 years.
Based strictly on reduced gasoline production, isobutane demand will be 20-30% lower than average in second and third-quarters 2020. Isobutane demand, however, also depends on octane-blending values as well as severity and operating rates for reformers and FCC units. Since by-product butane yields vary with operating and severity rates, a summer of weak demand for premium-grade gasoline may undermine typical octane values.
Astute NGL marketers for small midstream companies may resist their normal impulses to sell 100% of daily production and accumulate a war chest to take advantage of stronger prices in October-February 2020.
Near-term outlook
As always, Petral Consulting’s paramount objective is to reduce the fog of uncertainty that influences decisions to proceed and capitalize on some opportunities and defer others. This year will probably confuse historians for decades to come. We may never get answers to some important questions, while official answers to other questions will always be unsatisfactory. Survivors of the turmoil of 2020, however, will be those who succeed in navigating their organizations through the fog despite the uncertainties. Petral Consulting will provide more quantitative analysis of COVID-19’s full impact on demand for refined products in its next midstream article to be published Nov. 2, 2020.
Geopolitical events and financial crises have sparked periods of market turmoil and spikes in crude oil pricing volatility on a regular basis nearly every 3-5 years since 1983. Petral Consulting’s assessment of the spike in price volatility for 2020-21 is reminiscent of the spike in price volatility during the 2008-09 global financial system crash but less like the spike in 1990-91 when Iraq invaded Kuwait. In truth, we have no historic experience with the current global collapse in refined products demand alongside the accompanying collapse in crude oil and refined products prices.
The year 2020 marks 100 years since the last viral pandemic of the Kansas flu (better known as the Spanish flu epidemic), which took 675,000 US lives. Common sense tells us national political leaders today hardly want to be remembered by historians for a death toll that could be orders of magnitude higher than in 1918-20. The short-term pain of sharply reduced economic activity and demand for refined products is, most likely, worth avoiding the alternative. For those of us in the business of analyzing black-swan events, the unprecedented happenings of 2020 will be discussed—and all future black-swan events compared to—for the next 50-100 years.
One question will influence short-term marketing plans and longer-term strategic and capital budget plans: how long Russia and Saudi Arabia remain committed to rebuilding their respective shares of the global market for crude oil exports. For almost 50 years, the key members of OPEC shared the common objective of limiting crude oil production and defending a hard floor for benchmark crude prices. In 2014, despite accelerating growth in US crude production, Saudi Arabia declined to lead OPEC members to curtail production and sustain benchmark prices at $90-100/bbl. The objective, stated or unstated, was to halt growth in US crude oil production.
After prices fell to a low of $30/bbl in first-quarter 2016, various OPEC member countries increased pressure on leadership of Saudi Arabia’s royal family, members of which resisted this pressure until Russia and Iran jointly encouraged the OPEC leader to return to its historic role as the organization’s most important swing supplier.
Those who manage day-to-day production, distribution, and marketing functions at their companies may be excused for concluding that Saudi Arabia’s leadership had reverted to the tried-and-true objectives and tactics of the previous 45 years. Others with longer-term responsibilities, however, have no such excuses, though very few of us could have expected a new virus would become a pandemic capable of pushing the global economy into its worst—and almost instantaneous—collapse.
For the next 5-10 years, many of us will now consider the prospect that OPEC’s new objectives are to make crude oil supply plentiful, manage the global supply-demand balance to create a hard cap on prices, and limit the likelihood of prices increasing to levels that erode market share for the world’s major exporting countries. As we weather the storm of the current crisis, however, nothing is certain. As Sheik Zaki Yamani—Saudi Arabia’s oil minister from 1962-86—warned at a final press conference following his termination, “The Stone Age did not end for lack of stone, and the Oil Age will end long before the world runs out of oil.”
The author
Daniel L. Lippe ([email protected]) is president of Petral Consulting Co., which he founded in 1988. He has expertise in economic analysis of a broad spectrum of petroleum products including crude oil and refined products, natural gas, natural gas liquids, other ethylene feedstocks, and primary petrochemicals.
Lippe began his professional career in 1974 with Diamond Shamrock Chemical Co., moved into professional consulting in 1979, and has served petroleum, midstream, and petrochemical industry clients since. He holds a BS (1974) in chemical engineering from Texas A&M University and an MBA (1981) from Houston Baptist University. He is an active member of the Gas Processors Suppliers Association.
