At the PBPA Annual Meeting, Pioneer Natural Resources’ President and COO Tim Dove raised a concern about the growing excess of light sweet crude being developed in the unconventional plays in the Permian Basin, exacerbated by the light crude and condensate being developed in the Eagle Ford. Not coincidentally, Pioneer is one of the major players in both basins and one of the largest producers. I understand Pioneer is investigating its options as it proactively plans for the impending wall we will hit when light sweet crude production exceeds the capacity of our inland and Gulf Coast refineries to process it.
Oil is a global commodity; therefore, the global supply-demand balance is the primary driver of its price. However, transportation and refining capacity affect local pricing, which is what we as producers care about. The first red flag was pipeline capacity from the Permian to the Gulf Coast. While Permian oil production has risen from 850,000 barrels per day (bpd) in 2007 to an estimated 1.3 million bpd currently, the five inland refineries buying our crude have a capacity of approximately 410,000 bpd. That means almost 900,000 bpd needs to find its way to the Gulf Coast refining complex that stretches from Corpus Christi to New Orleans, or to Cushing, most of which ends up in the Gulf Coast. There is 450,000 bpd of pipeline capacity from Midland to Cushing, and once the four pipeline projects are all completed in 2015, almost 1.5 million bpd of capacity from the Permian to the Gulf Coast will be in service. Problem solved.
Well, not so fast. The problem is that refiners, including Shell/Pemex, Lyondell/CITCO, Exxon Mobil, and Valero, spent billions of dollars each primarily in the 1990s, as domestic sweet production declined, to modify their refineries to process heavy, sour crude from sources including Mexico (Maya), Venezuela (Orinoco), and Saudi heavy-sour. It is not coincidental that Pemex, CITCO (Venezuela), and Aramco (Saudi Arabia) formed joint ventures with refiners in the Gulf Coast in the 1990s to secure outlets for their poorer quality crude. It will cost hundreds of millions to convert each refinery back to sweet service, and the EPA is unlikely to approve a permit for a new refinery in the United States. It remains to be seen whether refiners will invest money to switch back to sweet service, but rest assured they will want a price that is competitive with the heavy sour grades from our Latin neighbors and the Middle East.
E&P companies have long dealt with gas-on-gas competition. Our industry drilled and developed natural gas so efficiently that we drove the price of gas down to a point where drilling for gas was marginal except in the most prolific plays in the best locations relative to consumer markets (e.g., the Marcellus). In addition, the Permian Basin and Eagle Ford have long suffered a glut of NGLs, especially ethane, the lightest and lowest valued component of the NGL stream. In 3+ years, the construction of ethane crackers and olefins complexes in the Gulf Coast for the export of products ranging from ethylene and propylene to plastics and fabrics will help alleviate the NGL glut. Between now and then, “Houston, we have a problem,”–a glut of NGLs.
The same phenomena will occur with the light, sweet crude oil and condensate that is produced from the Eagle Ford, Wolfcamp, and Leonard-aged formations that include the Bone Spring, Spraberry, and Avalon. The price at the wellhead in the Permian will likely be $10-30 per barrel below that of Brent crude, the new global benchmark for oil prices. The price of Brent or WTI Cushing will be irrelevant to Permian or Eagle Ford producers, as it will take discounting to induce an oversupplied sweet refinery to take one producer’s crude over another’s.
There are at least three market-based solutions to this quandary. One, the federal government should lift its ban on exports of crude oil. There are simple, “tea kettle” refineries in Mexico and other Central and Latin American countries that would buy our sweet crude if permitted to do so. We, in turn, import heavy, sour Latin crude to be processed in our complex Gulf Coast refineries. This amounts to a crude swap with our Latin neighbors. Two, refiners invest billions in the aggregate to convert their refineries back to sweet service. The impediment to this strategy is the fact that most of the incremental oil to be developed outside the U.S. is heavy sour, whose producers are willing to discount and enter long-term contracts to sell it. Three, prices fall into the $70s or worse at the wellhead and the investment and the rig count drops, reducing oil production, alleviating the problem. You see, E&P companies primarily reinvest their cash flow into leasehold, drilling, and completions. Few of the most active drillers in the United States pay a dividend.
Lower oil and gas prices mean lower cash flow and reduced rates of return on investment, thus reduced reinvestment, and slower production growth. It is a brutal self-correction mechanism that would have worked for natural gas if not for the large amounts of rich associated gas produced with the oil in our unconventional plays. None of us hopes to resort to the third option.
In this brave new world of increasing oil, NGL, and natural gas production, do not take your markets for granted. Check with your friendly natural gas marketer or gas gathering and processing company, along with your favorite crude oil marketers, prior to drilling your next well if it is not in a unit. Secondly, Pat Ennis warned us at the PBPA Annual Meeting to check with your power distribution company—often times it is Oncor in West Texas—about ordering a meter and service to your new location. Finally, permitting times on saltwater disposal wells are six months out at the Texas Railroad Commission, so investigate both your water disposal and sourcing in advance. If any of these are not prepared in advance, your multi-million investment may sit idle until products can be gathered and sold, power can be delivered, and water sourced and disposed.