Untitled Document
Untitled Document

The US crude production quality debate

Sandy Fielden, RBN Energy

US tight oil production from shale has surged over the past three years pushing overall domestic output up by more than 60 percent since 2011. Over that same period the quality of US crude production has gotten considerably lighter. An EIA report out last week showed that the percentage of crude production with higher than 40 degrees API of gravity (very light crude) has almost doubled between 2011 and the end of 2015. The increasingly light crude slate is challenging US refining capacity and driving the push for reform of crude export regulations. Yet the data available to inform this critical industry debate is confusing and inadequate. Today we discuss the analysis challenge.

The drumbeat of interest currently surrounding crude oil exports in Washington DC has initiated increased analysis around the topic. One study, prompted by congressional request and published at the end of May 2014 by the Energy Information Administration (EIA) delves into the quality of current US crude production. The EIA is investigating this topic because of concerns that surging US crude production – up over 60 percent in the past 3 years - is increasingly lighter in quality whereas much of the available refining capacity is geared towards processing heavier crudes. This quality mismatch is adding pressure to a wider debate about whether the US should repeal decades old laws restricting the export of US crude.

Prior to this EIA study – itself only the first stage in a wider enquiry into crude quality – the agency placed little focus on the quality of US domestic production – concentrating instead on reporting the gravity and sulfur content (two key criteria that the industry uses to measure crude quality) of imported oil. That concern with imports dates back to a time when declining US production meant that understanding where US crude imports came from and the possible political implications of the latter was a big deal. Now US production is regaining levels not seen since the late 1980’s and heading to record volumes in the next four years, (11 MMb/d by 2019 is the latest RBN estimate – see Like A Bat Out of Hell), so concerns about supply are fading. Today the question is one of demand – how is all the new light domestic production going to be processed? And if we can’t process all that oil efficiently – then should we loosen up restrictions that prevent the US from exporting it to other countries?

As we have recently discussed (see Imagine There’s No Export Ban) the debate over US crude oil export policy is about regulations implemented in the 1970’s by the Department of Commerce, administered today by the Bureau of Industry and Security (BIS). These regulations prevent the export of US crude oil except to Canada or in specific narrow circumstances from Alaska and California (see I Fought the Law). Although exports to Canada under license from the BIS have been creeping up (246 Mb/d in March 2014), these are barely making a dent on the large stockpile of crude that has accumulated in the Gulf Coast refining region since the start of 2014 where inventories have been close to record levels since April. Much of that crude stockpile is assumed to be light crude oil that most refiners have a harder time absorbing because their refineries are best suited to heavier crudes. And as we pointed out in “Texas Bound and Flying” even if Gulf Coast refineries ran flat out, it would still take three months for inventories to return to 5-year average levels.

(Refinery/Shutterstock/Kodda)

Proponents of an end to the crude export restrictions argue that the new growth in domestic crude production could be rapidly curtailed by refining bottlenecks if the government doesn’t allow exports to relieve the inventory build up. On the other side of the debate are those like independent refiners that benefit from the domestic crude build up. They enjoy lower crude feedstock prices than their international competitors because of the export restrictions and have benefitted from a boom in refined product exports. 

Unfortunately for the participants in this debate the information that the EIA can bring to the table – such as that included in it’s initial report last week, is a mixed bag. While some of the trends observed in the data ring true, we do not believe that the analysis should  be considered conclusive. That is because it is based on data sets that were not organized to address the questions being answered. The EIA is the first to admit that their estimates are based on currently available data and that the “quality and timeliness of well-level data on production by crude type used to develop the estimates vary widely across states”. The agency also clearly states its proposed intention to collect better data starting in 2015. Until then, with no nationwide requirement to report data on crude quality, the EIA is left doing its best to patch together diverse data sets from multiple states. This information is difficult to rely on at a time when the nature of US crude oil production is changing so radically and rapidly.

Figure #1

Source: EIA

Case in point is Figure #1 above from the EIA report that summarizes US crude production by type. The data shows daily crude production totals between 2011 and 2013 based on actual numbers and forecasts for 2014 and 2015 – that derive from data EIA has already published. But then within the overall production totals, there are (count ‘em) 11 different crude types identified – again through no fault of the EIA – they are just using the data available. The crude types primarily use the industry standard American Petroleum Institute (API) degrees gravity measure of density by which low numbers represent heavy crude (water has an API of 10) and high numbers represent light crude. For some of the crude types listed a secondary identifier is added based on crude sulfur content using industry standard terminology of “sweet” to represent low sulfur (usually less than 0.5 %) and “sour” to represent higher sulfur. Quality data for California crude (which is mostly heavy crude with an API <27) is separated out into its own category because the EIA considers that since it is produced and refined in State, it is isolated from the heavy crude market dynamics of the rest of the country. As a result of all these categories some of which overlap, the chart is confusing – representing as it does a number of different data collection methods across the US.

But in spite of the category soup, useful trends are discernable in Figure #1. Clearly overall crude production is growing rapidly over the period from 5.7 MMb/d in 2011 to 9.2 MMb/d in 2015. Also clear is that the quality of new crude production is lighter – such that crude with API gravity above 40 degrees is 25 percent of the total in 2011 but nearly doubles by 2015 to 46%. Within that category of lighter crude the data suggests that the fastest growth is in crude with an API between 40 and 45, which doubles from 13% of the total in 2011 to 27% of the total by 2015. However, crude with an API above 50 stays relatively static over the period at between 7% and 8% of the total.

We at RBN agree with the overall trend to lighter API crude. We have posted many blogs on that topic (see Turner Mason and the Goblet of Light and Heavy and Charge of the Light Brigade). We are more skeptical of the EIA numbers for crude oil with an API above 50. These are shown growing from about 370 Mb/d in 2011 to 640 Mb/d in 2015. Our current estimate – that we believe is conservative – is that crude with an API above 50 degrees reached at least 600 Mb/d in 2011 and will get to at least 1.4 MMb/d by the end of 2015  - in other words more than double the EIA forecast. But before we get into a name calling contest with the EIA, the first thing we need to say about their 50 API plus category is that the rest of the world calls it condensate rather than crude oil. That is because although there is no universal standard for what defines a condensate, some number between 50 and 55 degrees API gravity is typically used to differentiate condensates from light crude oil (see Fifty Shades of Condensate Which One Did You Mean?).  And once again here, the EIA have their hands tied by prior history whereby they have always categorized condensate produced at the wellhead (known as lease or field condensate) as crude oil because – well frankly it didn’t used to matter because there wasn’t much condensate and nobody cared.

Trouble is that calling your crude “condensate” does matter now and it hits US producers directly in the pocket book. That is because refiners typically pay lower prices for lease condensate because it is such a light mix of hydrocarbons that they often struggle to process it without blending it first with heavier crudes (see Don’t Let Your Crude Oils Grow Up to be Condensate). And although we can’t prove it, we are fairly sure that condensate production is generally under-reported. Our contention is therefore that the EIA analysis likely under reports the 50 + API category that we call condensate.

And the amount of condensate or crude over 50 API in the EIA report’s regional analysis is also lower than we would expect. [Again our disagreement here is with the accuracy of the reporting in the source data, not EIA analysis]. Rather than going into every region in turn, we will just touch here on the Texas data, which most clearly doesn’t represent what we’ve been hearing from the field. Figure 2 below shows production for the Permian Basin. Note the very low percentages of production over 50 API (1% in 2011, 2.5% by 2015) – even over 45 API (growing from 5% in 2011 to 10% by 2015). This contradicts our understanding that the recent surging Permian crude production that has resulted from a rapid increase in horizontal drilling (see Stacked Deck) is yielding significant volumes of condensate.  The EIA data for the Eagle Ford basin in South Texas has crude over 50 API shrinking over the forecast period from 36% in 2011 to 16% in 2015. Again counter to our expectation. The Texas data that EIA used is from the Railroad Commission that does actually separate out condensate from oil in its production data, but has a reputation for under reporting condensate compared to other industry estimates.

Figure #2

Source: EIA

So this opening salvo in the battle to inform the debate about crude quality in the context of possible repeal of, or change to, the export regulations is not a home run. It shows us that data currently collected on crude quality is weak and needs to improve. As we have emphasized, the blame does not lie with the EIA, but rather the raw material they are working with. If anything this report reiterates just how confusing the situation out there is for refiners and marketers trying to get a handle on the huge challenge that crude oil quality poses in optimizing supply and refining capacity for the feedstocks available.

 

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