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Last Updated: November 25, 2019
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monthly U.S. crude oil production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, October 2019 and November 2019

The U.S. Energy Information Administration (EIA) revises its U.S. crude oil production forecast in each monthly Short-Term Energy Outlook (STEO) based mainly on two factors: updates to EIA’s published historical data and EIA’s crude oil price forecast. In the November 2019 STEO, EIA increased its forecast of U.S. crude oil production in 2019 by 30,000 barrels per day (b/d) (0.2%) from the October STEO. EIA increased its 2020 crude oil production forecast by 119,000 b/d (0.9%) compared with the October STEO.

The increases in crude oil production forecast in the November STEO were primarily driven by

  • EIA’s upward revision to historical production in the Lower 48 states of about 90,000 b/d for August, based on EIA’s most recent monthly crude oil production survey data
  • A higher initial production forecast for future wells that will be drilled in the Texas Permian region through 2020
  • A slightly higher crude oil price forecast for the November 2019–January 2020 time period than in the October STEO

In the November STEO, EIA increased its U.S. benchmark West Texas Intermediate (WTI) crude oil price forecast by $2 per barrel (b) in November to $56/b and by $1/b in both December and January to $55/b and $54/b, respectively. The slight increase in crude oil prices also contributed to EIA’s increased production forecast for the first half of 2020 because of EIA’s assumption of a six-month lag between a crude oil price change and a production response.

With these changes, EIA now forecasts U.S. crude oil production will increase to 12.3 million b/d in 2019 from 11.0 million b/d in 2018. Output in the Permian region is the primary driver of EIA’s forecast crude oil production growth, and EIA forecasts Permian production will grow by 915,000 b/d in 2019 and by 809,000 b/d in 2020.

Increases in Permian crude oil production in Texas and New Mexico are supported by crude oil pipeline infrastructure expansions that came online earlier this year. These expansions, which helped alleviate transportation bottlenecks and led to increased prices for WTI in Midland, Texas, (the price that producers may expect to receive in the Permian region) relative to prices for WTI-Cushing. The higher relative prices in the Permian region should continue to encourage crude oil production growth in the region.

EIA forecasts that the Bakken region in North Dakota will have the next largest crude oil production growth in 2019. EIA expects Bakken crude oil production will grow by 152,000 b/d in 2019 and 96,000 b/d in 2020. EIA forecasts that production in the Federal Offshore Gulf of Mexico will increase by 138,000 b/d in 2019 and 116,000 b/d in 2020.

monthly U.S. crude oil production by region

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, November 2019

Although EIA forecasts that overall U.S. crude oil production will continue to increase, EIA expects the growth rate will slow largely because of a decline in oil-directed rigs. According to Baker Hughes, active rig counts fell from 877 oil-directed rigs in the beginning of January 2019 to 674 rigs in mid-November, a 23% decline. Rig counts in the Permian region fell 15% during this period, from 487 to 408 rigs.

Because EIA expects WTI-Cushing crude oil prices to stay lower than $55/b until August 2020, EIA anticipates that drilling rigs will continue to decline as producers cut back on their capital spending, resulting in notable slowing in the growth of domestic crude oil production over the next 14 months.

Although U.S. rig counts are declining, improvements in rig efficiency, which allows fewer rigs to drill the same number of wells, partially offsets declining rig counts. In addition, higher initial production from wells (although not necessarily the total estimated ultimate recovery) is offsetting some of the slowdown in rig counts.

production supply forecasts projections STEO liquid fuels crude oil oil petroleum
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TODAY IN ENERGY: Drop in petroleum demand led to rise in crude oil inventories and low refinery utilization

The U.S. Energy Information Administration’s (EIA) latest Petroleum Supply Monthly shows the significant changes in petroleum markets that occurred in April, when most of the United States was under stay-at-home orders to limit the spread of coronavirus. In April, commercial crude oil inventories increased by 46.7 million barrels (10%)—the largest monthly increase in EIA data going back to 1920. U.S. refineries operated at 70% of their capacity, the lowest utilization rate in EIA’s monthly data series dating back to 1985. Demand for finished petroleum products fell to 11.7 million barrels per day (b/d), the lowest level since at least 1981.

April’s crude oil inventory increase is a result of refinery runs falling more quickly than crude oil supply, which is determined by domestic production and imports. U.S. crude oil production in April averaged 12.1 million b/d, a decrease of 669,000 b/d (5%) from March. This decrease represents the largest month-over-month decline since September 2008, when Hurricanes Ike and Gustav hit the U.S. Gulf Coast. U.S. crude oil imports fell by 776,000 b/d (12%) from March to April, further decreasing crude oil supply in the United States.

The combined drop in production and imports was smaller than the decline in gross inputs to refineries, resulting in record increases in crude oil inventories. Based on estimates in EIA’s Weekly Petroleum Status Report, commercial crude oil inventories reached a record high of 541 million barrels in the week ending June 19 and have fallen slightly in the weeks since then.

U.S. product supplied of gasoline, distillate, and jet fuel

Source: U.S. Energy Information Administration, Petroleum Supply Monthly

Changes in travel patterns resulted in the lowest levels of U.S. demand for finished petroleum products (as measured by product supplied) in decades. Transportation fuels have been affected differently by changes in travel: demand for jet fuel and motor gasoline fell much more than distillate fuel, which is primarily consumed as diesel. From March to April, product supplied of finished motor gasoline decreased a record 1.9 million b/d (25%) to 5.9 million b/d, the lowest monthly value since the mid-1970s.

In the span of two months, U.S. demand for jet fuel fell by more than half, from 1.6 million b/d in February to 691,000 b/d in April. Before April, U.S. jet fuel demand had not been less than 700,000 b/d since the mid-1970s.

Distillate demand fell by 408,000 b/d, or about 10%, from March to April. Although the change in distillate demand was less drastic than the changes in motor gasoline and jet fuel demand, distillate consumption in April 2020 was the lowest in more than a decade.

July, 10 2020
U.S. natural gas exports to Mexico set to rise with completion of the Wahalajara system

Exports of natural gas to Mexico by pipeline are the largest component of U.S. natural gas trade, accounting for 40% of all U.S. gross natural gas exports in 2019. EIA expects these exports to increase with the completion of the southern-most segment of the Wahalajara system, the Villa de Reyes-Aguascalientes-Guadalajara (VAG) pipeline. VAG began operations in June 2020, connecting new demand markets in Mexico to U.S. natural gas pipeline exports.

The Wahalajara system is a group of new pipelines that connects the Waha hub in western Texas, a major supply hub for Permian Basin natural gas producers, to Guadalajara and other population centers in west-central Mexico. The Wahalajara system provides U.S. natural gas to meet growing demand from Mexico’s electric power and industrial sectors. With the 0.89 billion cubic feet per day (Bcf/d) VAG pipeline entering service, EIA expects utilization of the Wahalajara system to quickly ramp up, resulting in increased U.S. natural gas exports to Mexico out of western Texas and additional takeaway capacity out of the Permian Basin.

Since 2016, Mexico has been expanding its natural gas pipeline system, which has supported continual growth in U.S. natural gas exports. Most of this growth has been in U.S. natural gas exports from southern Texas after the existing U.S. pipeline infrastructure was expanded and the Los Ramones Phase II pipeline in central Mexico was completed.

Since the Sur de Texas-Tuxpan pipeline was completed in September 2019, U.S. natural gas exports to Mexico reached a record 5.5 Bcf/d in October 2019. U.S. natural gas exports from the border at Brownsville, Texas, to the southeastern state of Veracruz in Mexico averaged 0.6 Bcf/d during the last quarter of 2019, or about 20% of the pipeline’s capacity.

Overall, U.S. natural gas exports from this region have only increased by 0.2 Bcf/d from 2016 to 2019 because of delays in pipeline construction in Mexico. In particular, two regional pipelines were completed in 2017 but have not been used near their capacity:

  • The 1.1 Bcf/d Comanche Trail pipeline, which delivers natural gas to Mexico from San Elizaro, Texas
  • The 1.4 Bcf/d Trans-Pecos pipeline, which crosses the border at Presidio, Texas 

U.S. monthly natural gas exports to Mexico by region

Source: U.S. Energy Information Administration, Natural Gas Monthly

The Comanche Trail pipeline has been delivering an average of 0.1 Bcf/d of natural gas to Mexico since the San Isidro-Samalayuca pipeline entered service in June 2017. Pipeline operators do not expect flows to rise until the 0.47 Bcf/d Samalayuca-Sásabe pipeline is completed in either late 2020 or early 2021 in Mexico.

The Trans-Pecos pipeline, the U.S. segment of the Wahalajara system, did not transport significant volumes of natural gas until October 2018; it is currently only operating at 10% to 15% of its total capacity. Most of the demand centers are in southern Mexico, waiting to be connected to the VAG pipeline. Three of the project’s four pipelines in Mexico that are currently in-service include

  • Ojinga-El Encino: 1.4 Bcf/d, entered service in June 2017
  • El Encino-La Laguna: 1.5 Bcf/d, entered service in January 2018
  • La Laguna-Aguascalientes: 1.2 Bcf/d, entered service in December 2019

Before the economic impacts and uncertainty associated with COVID-19 mitigation efforts and declining crude oil prices, S&P Global Platts expected U.S. natural gas exports to Mexico to increase immediately by 0.3 Bcf/d to 0.4 Bcf/d on the Wahalajara system. However, given the decreased demand for natural gas in Mexico in response to the economic impact of COVID-19 mitigation efforts, growth is likely to be slower than expected. Beyond these volumes, additional export volumes will be limited by how quickly customers in Mexico can be connected to the pipeline system.

These connections include new natural gas-fired combined-cycle generators and the scheduled 2020 completion of the 0.89 Bcf/d Tula-Villa de Reyes pipeline, which will deliver natural gas to central Mexico. Deliveries from the Wahalajara network are likely to partially displace higher-cost liquefied natural gas (LNG) imports into Mexico’s Manzanillo terminal, which serves markets in Guadalajara and Mexico City.

As U.S. natural gas exports on the Wahalajara system rise and crude oil prices remain low, EIA expects the price at the Waha hub in the Permian Basin, which had been steeply discounted to the Henry Hub national benchmark, to continue to strengthen.

July, 07 2020
The Oil World’s Ongoing Impairments

Officially, we are past the half point of 2020 and with that the end of the second quarter. And what a quarter it has been. WTI prices plunged into negative territory (as low as -US$37/b) then recovered to US$40/b as OPEC+ moved from infighting to coordinating the largest crude production cut in history. In between, the Covid-19 pandemic wreaked havoc with the global economy, setting off a chain reaction within the oil world whose full impact is still unknown.

Opinions on a post-Covid oil world are divided. Some voices, the more optimistic ones, think that oil demand could recover to pre-Covid levels within a year or two. The more pessimistic ones think that this will never happen, that Covid-19 has hastened the trend away from fossil fuels to sustainable energy against the backdrop of climate change. Either way, this has thrown a spanner in the works of the giant, multi-billion oil and gas projects that were announced over the past two years as the energy world began to wake up from its post-2015 price crash investment hibernation. Those projects were made at a time when oil prices were at US$50-60/b. Since oil prices are now only at US$40/b, the current value and the future worth of these assets have now declined. Energy companies account for this by adjusting the value of their portfolios in accordance to the projected value of crude: an upward adjustment is known as a revaluation, and a negative one is known as an impairment.

This is a term that will crop up many times over 2020, as energy companies close their quarterly financial books and report their results to shareholders. The plunge in crude oil prices and the uncertain outlook for oil demand means that publicly-traded companies must account for this to their shareholders. Chevron was the first supermajor to book an impairment, in late 2019 when it took a US$10 billion hit to its oil and gas assets. It wasn’t the only one: firms all across the oil chain also reduced the value of their assets, from Repsol to Equinor.

Further impairments were made in April 2020 when the Q1 financial results were announced, mainly in response to the triggering of the OPEC+ price war (which saw crude prices halve from US$60/b to US$30/b) and the Covid-19 pandemic accelerating to a point where over half of the world’s population went into lockdown. But the major impact will come in Q2 2020, when the roil in the oil markets truly began to boil uncontrollably. BP has announced that it may take up to a US$17.5 billion impairment in its Q2 2020 financial results, while Shell has just admitted that it may have to shave US$22 billion from its asset value.

This has roots not just in the depressed demand for energy due to Covid-19, but also the ongoing conversation on climate change. Almost all supermajors have announced intentions to become carbon neutral by the 2050 timeframe. That may be good news for the planet, but it is bad news for the companies’ portfolio. Put simply, it means that some of the assets that they have invested billions in are now not only worth a lot less (due to Covid-19) but they may in fact be worth nothing at all, because climate change considerations mean that they will never be exploited. Challenging projects such as Total’s deepwater Brulpadda discovery in turbulent South African waters or Pertamina/ExxonMobil/Total/PTTEP’s beleaguered and complicated East Natuna sour gas asset in Indonesia may never be commercialised, either because of uneconomic prices or because they run counter to the goal of becoming carbon neutral. The Financial Times estimates that the amount of unviable or stranded hydrocarbon assets could reach as much as US$900 billion; that figure is pre-Covid, and could now become even higher.

There is one supermajor bucking the trend though. The biggest supermajor of all, in fact. Unlike its peers, ExxonMobil has not yet succumbed to impairments. If fact, it has not announced any negative revaluations at all over the past decade, even during the 2015 oil price crash. ExxonMobil claims that this is because it books the value of new assets ‘very conservatively’ and does not ‘adjust values to short-term price trends’, but critics say that it has an ongoing history of vastly overestimating its assets’ value. Along with Chevron, ExxonMobil does not disclose price assumptions in its financials. But unlike Chevron, ExxonMobil has not yielded to climate change through an official emissions target or asset revaluations.

On paper, that will make ExxonMobil look better than its supermajor brothers. But behind the scenes, this reluctance to admit that the future is less rosy than expected could be trouble waiting to be unleashed. Impairments are a necessary reality check: an admission by a company that things have changed and it is starting to adapt. Most have accepted that reality. ExxonMobil seems to be resisting. But even it is not immune. In pre-Q2 2020 results guidance that was just announced, ExxonMobil admitted that it expects to take a hit of some US$3.1 billion and slump to a second straight quarterly loss. In terms of Covid-19 impairments, that’s small. But it is, at least, a start.

Market Outlook:

  • Crude price trading range: Brent – US$40-44/b, WTI – US$38-42/b
  • A swathe of positive economic data is supporting oil prices within its current range, with US light crude settling above US$40/b for the first time in four months
  • The relaxation of Covid-19 restrictions has led to improvements in most economic indicators, but the risk of the situation reversing is also higher, given the accelerating cases being reported in part of the USA, South America and India
  • On the supply side, OPEC+ is making adherence a priority, with lagging members now bucking up and swing producer Saudi Arabia also keeping its promises by throttling crude exports in June to some 5.7 mmb/d

End of Article

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July, 04 2020