“They should make some money but not $30 a barrel, in my opinion.”
The U.S. isn’t just on the verge of a “stranded oil” situation, it’s already in the midst of it, says Scott Sheffield, chairman and chief executive officer of Permian-Basin producer Pioneer Natural Resources Co. “If not for some dynamics in the Midwest refining market, yes,” he says.
Sheffield recently addressed members of the energy M&A group ADAM-Houston, which named him its “Dealmaker of the Year” for Pioneer’s 2013, $1.7-billion, Permian joint venture with Sinochem Group and its roll-up of Pioneer Southwest Energy Partners LP. The company incurred a one-year stock-price gain of 66% in the midst of WTI-price growth of just 5% and while issuing 10.4 million additional shares in a $1.3-billion raise.
A political impediment to exporting U.S.-produced oil beyond a few exceptions, such as sending it to Canada, is refiners who are enjoying margins of as much as $30 a barrel, Sheffield says. Acknowledging that U.S. refiners suffered from marginal profit for decades until the past few years, “they should make some money but not $30 a barrel, in my opinion,” he added.
While the Nymex price for WTI, for example, is up to $100 a barrel and breakeven in many plays is at least $60 oil, what producers net is affected by transportation-to-market costs and by the onshore-versus-Gulf Coast price differential, which was $18 in mid-March for Permian Basin crude, for example.
So, while the Nymex price for WTI may be $100, a Permian producer may net between $70 and $80; with a cost of $60 a barrel, its profit may be $20 a barrel or less.
“Once all North American, light, sweet imports are displaced, the Gulf Coast will become saturated with domestic production,” he says. As a result, producers will experience a more than $30-a-barrel differential to Brent, rigs will be let go, “starting with the marginal plays and eventually every play will shut down,” he says.
Meanwhile, he adds, lifting the ban would create up to 1.7 million new jobs by 2020, as per a McKinsey & Co. study; reduce U.S. gasoline prices, as per a Resources for the Future analysis; and improve the U.S. trade balance as per a Citigroup forecast that a $354-billion U.S. trade deficit in 2010 could become a $5-billion surplus in 2020.
Securities analyst David Tameron writes that producers who presented in a mid-March, Wells Fargo Securities LLC-hosted symposium “agree that an oversupply of light, sweet crude and condensate is forthcoming and represents a mismatch with the Gulf Coast refinery feed-slate, which is more configured for medium to heavy barrels.
“The industry is attempting to deal with this dislocation in a number of ways, including the construction of condensate splitters, some minor investments by refiners (such as Valero Energy Corp.) to process more light, sweet crude and increased blending with heavy crudes.”
They weren’t expecting the oil-export ban to be lifted anytime soon, however, he adds, “given the political dynamics—no politician wants to take actions that could result in higher motor gasoline prices—and the near-term election cycle.”
He concludes, “Any potential change in policy would likely be on a case-by-case basis and in response to severe market dislocations that cause public sentiment to shift.”
FBR Capital Markets & Co. securities analyst Benjamin Salisbury notes in a report this week that producers are asking the Department of Commerce to allow export of natural condensate, which is a gas while still in the ground and arrives at the wellhead as a liquid.
Sheffield says U.S. wells are currently producing some 800,000 barrels of condensate a day, particularly from the liquids-rich Eagle Ford play. The figure represents some 10% of total, daily, U.S. oil production. If producers are able to export the condensate, he says, daily, U.S., refining capacity for new, light, sweet production would grow by some 800,000 barrels.
Salisbury writes, “It is possible to seek (a condensate exception) and it appears that producers have a relatively strong technical argument. Moreover, lease condensate is relatively obscure and does not carry the political sensitivity that crude-oil exports would.”
An option, however, is to send it to Canada, he adds. “As we understand it, the law allowing crude exports to Canada could be similarly applied to exports to Mexico with a presidential determination of national interest.
Oil-price speculators are discounting forward-month contracts for WTI, primarily due to concern about future markets for it. While WTI was trading at $101 a barrel today, the May 2015 contract was $91; May 2016, $85; and May 2017, $83.
Judith Dwarkin, director and chief energy economist for research group ITG Investment Research Inc., says, “We believe fears are overblown that U.S. crude prices are about to collapse because domestic, light-oil, production growth will soon hit a ‘wall’ with respect to crude-import-displacement opportunities.”
The firm analyzed the price discount required on light, sweet domestic crude—relative to other crude types—to displace sour and heavy grades in cracking and coking-type refinery configurations in the U.S. Gulf Coast market, she says. Taking January 2014 price spreads for LLS/Mars ($4/barrel) and LLS/Maya ($14) and Gulf Coast product prices as the starting point, the firm found that “light, sweet crude largely displaces sour in the example USGC cracking refinery at a $1/barrel narrowing in the light sweet/sour price differential.” She adds that, “for the coking refinery, light, sweet largely displaces heavy at a $3/barrel narrowing in the light sweet/heavy spread.
“A bigger price discount is required for the coking compared to the cracking configuration because the coker sees a smaller uplift in product value by shifting to a lighter crude slate.”
As for geography-based—rather than oil-type-based—differentials, she notes, “they’ve ticked up this year in part because WTI Cushing prices are being supported by a very robust stock draw from this hub, due to the start up of (the Keystone) XL (Gulf Coast leg), and because production growth in the Permian is out-pacing take-away capacity again.
“The latter problem should diminish as additional pipeline projects come to fruition in the basin.”
-–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at firstname.lastname@example.org.
2023-11-27 - As the core of the Permian Basin gets drilled up, E&Ps see years of upside from fringier acreage and unproven targets deeper underground. But these targets will be more expensive to develop, experts say.
2023-11-22 - E&P Permian Resources will shift to smaller-scale deals to add value as opportunities to consolidate in the Midland and Delaware basins shrink.
2023-11-21 - Non-op specialist Northern Oil & Gas is entering the Ohio Utica Shale and expanding its position in the northern Delaware Basin with approximately $174 million in M&A.
2023-11-08 - Third-quarter earnings for U.S. natural gas producers plummeted compared to last year, when prices spiked to their highest levels since the Great Recession. Now, all eyes are turned toward growing gas demand to serve new U.S. LNG export capacity coming online.
2023-11-03 - The largely untapped potential of Canadian shale is a draw for investors.