NEW YORK (Reuters) - In 1964, a Supreme Court justice sought to settle the debate over art versus pornography with a simple pronouncement: “I know it when I see it”. Fifty years later, the U.S. energy industry faces a similarly vexing controversy over the ultra-light crude known as “condensate”.
As record production of the once-rare oil emerges from U.S. shale wells in North Dakota, Ohio or Texas, what constitutes “condensate” is becoming a critical question in the debate over easing a longstanding U.S. ban on crude exports.
What’s in a name? Possibly hundreds of thousands of barrels a day of exported oil. If U.S. regulators opt to allow further exports of processed condensate, but not crude oil, the distinction between the two will be worth billions of dollars.
Not unlike in the Supreme Court case, the difference is often in the eye of the beholder: there is no single definition of what distinguishes a condensate from ordinary crude oil.
The Energy Information Administration (EIA) is now trying to remove that uncertainty by defining condensate and quantifying its output.
“We hope to have this sorted out so that policymakers will know what the numbers are,” EIA’s chief Adam Sieminski said late last month in New York.
The agency, the independent statistics branch of the Department of Energy, aims to launch by mid-2015 a new survey that would capture the quality of oil from each well.
It also held a closed-door “Condensate Workshop” for officials from several agencies and energy experts last Friday, one of its first efforts to produce a firm definition, according to two participants.
U.S. export regulators may wait for such a definition before they issue any more rulings on exports of “processed” condensate, the attendees said. The first two rulings rattled the industry earlier this year.
The term refers broadly to any type of oil that “condenses” into a liquid after being freed from high-pressure wells, where it often lurks in gas form, or separated from gas.
But once it becomes a liquid, there is no agreed way to tell condensate from ordinary crude. Most state regulators do not even measure it; those that do, only measure gas-related condensate, not that from the hydraulically fractured oil wells.
Most industry insiders expect the definition to revolve around API gravity, a standard measure of density with higher readings produced by lighter grades. Condensate is the lightest of the light.
However, deciding where to draw that line is likely to be a contentious process.
Refiner Phillips 66 (PSX.N) and midstream giant Plains All American (PAA.N) have said condensate is oil with an API gravity of 45 or above. Meanwhile, Marathon Petroleum Corp’s (MPC.N) top executive said in a recent interview he believed condensate should have an API gravity of 60 and above.
Without a universal standard, production data vary wildly. The EIA’s own figures suggest that anywhere from 8 percent to 16 percent of U.S. crude oil production is condensate - a difference of more than half a million barrels a day.
In one respect, condensate is just another term used to describe one end of a spectrum of over 100 grades of crude oil.
However, unlike most types of crude it can be used in a variety of processes, from refining to the production of petrochemicals. The term also applies equally to condensate pumped from a well or processed at a gas plant, which are chemically interchangeable but often reported differently.
Most importantly, the U.S. Department of Commerce earlier this year gave two companies approval to export condensate that had been minimally processed, the first sign of loosening the four-decade-old ban on exports.
Because the rulings are private, it is not clear whether the same sort of processing would allow for exports of ordinary varieties of crude oil as well.
To be sure, lifting the ban completely could render the discussion moot. However few policy experts see any chance of that happening before presidential elections in 2016, if then.
Available data is more misleading than helpful, probably dramatically understating condensate production.
For example, the Texas Railroad Commission, which oversees the Eagle Ford and Permian basins that account for most condensate output, publishes monthly production data, but only counts condensate that comes from natural gas wells. Most states, including North Dakota, do not report it at all.
The most recent data from the EIA, which also only counts natural gas lease condensate, shows production rose by nearly a fifth to around 750,000 bpd in 2012.
Energy consultancy Bentek Energy estimates current national condensate output at around 1.45 million bpd, with only about a third coming from gas wells.
“You’re missing most of it,” said Al Troner, a condensate expert and president of Asia Pacific Energy Consulting.
The EIA earlier this year made the first effort to distinguish and forecast domestic production by API gravity. It estimated that out of a forecast 8.4 million bpd 2014 oil output, about a quarter was in the API 40-45 range. However, the project was hamstrung by a lack of consistent data from various state-level regulators, many of whom do not collect it.
In Texas, for instance, API gravity data gets collected only from initial tests for oil and gas wells and during annual and semi-annual tests for gas wells.
“This certainly does make the export question more difficult as the data is not precise, nor are the definitions,” said Anthony Starkey, a manager at Bentek.
“So how policy is shaped in a clear way around such a gray area does make for some interesting discussions.”
Additional reporting by Timothy Gardner in Washington; Editing by Jessica Resnick-Ault, Jonathan Leff and Tomasz Janowski