With heavy ramifications for Midcontinent energy infrastructure and eventual exports, the United States will find itself with an oversupply of both domestically produced liquids and crude oil from now through 2017, according to market consultant Rusty Braziel of RBN Energy LLC.
Braziel was part of a panel discussion at the recent Colorado Oil and Gas Association’s Rocky Mountain Energy Epicenter. He said the oversupply has significant pricing and operational implications for the U.S. energy markets as the nation greatly steps up its production of liquid hydrocarbons. He noted that the greater production of shales promises technical and operational implications because of almost exclusively light sweet (lower sulfur content) crude oil and super-light crude.
Emphasizing the steady increase in U.S. liquid hydrocarbon production, Braziel said the industry is “in for big changes in how it does business,” noting that what he considers the biggest change will be “significantly more exports of U.S. energy products. He is predicting that “will be a good thing for the markets, for the industry and for the economy.”
Braziel cited a Bentek Energy forecast of up to almost 3.4 million b/d of natural gas liquids (NGL) by 2017, effectively doubling from the 1.7 million b/d in 2007 (2.4 million b/d today). To deal with those volumes, he cited 13 NGL pipeline projects and 86 gas processing plants being built or expanded. The pipeline projects represent 2 million b/d of capacity collectively, and the processing plants all together would add 12.8 Bcf/d of capacity.
More than 70% of the new NGL pipe capacity will be used to get the additional product to the Gulf of Mexico (GOM) where most of the growth in demand will be located, Braziel said. “By 2017 there will be several new — and very large — chemical plants built, and until then, the supply-demand balance will periodically move through oversupply cycles.”
He anticipates that NGLs will be in an oversupply situation generally, but the sector will find the situation “manageable” with the surplus finding a home in export markets, in the growing petrochemical demand, and “for the next few years back into natural gas” through ethane rejection.
In terms of U.S. crude production, Braziel focused on six major shale plays, along with incremental Canadian imported supplies, assessing that the nation is looking at an overall increase of 5.1 million b/d by 2017 in what should be the conclusion of 10 years of robust growth after U.S. production fell steadily for nearly 30 years until 2009.
“Fourteen new pipeline projects or capacity expansions are being built to get new crude production to market, with most of those pipelines moving volumes to Cushing, OK, and then down to the Gulf Coast,” he said. Overall, the relatively lower prices for U.S. and Canadian crude will continue, said Braziel, noting that “crude oil prices on the GOM will be cheaper than equivalent world crude oil prices.” But he added that Cushing, Rockies and Canadian prices will increase at some point, helping prices “balance out to variable transportation costs, adjusted for quality differentials.”
On the operations side, the influx of lighter, sweeter supplies from the shales promises to transform the refining sector. “It will take a long time for the U.S. refining system to adjust to all of these realities,” Braziel said.
Despite the rash of crude oil refinery closings in the Eastern United States within the past few months, U.S. refineries in total appear to be burning about the same percentage of incremental gross crude oil supplies (defined by U.S. production plus imports) as they have over the last 30 years. Last May the most recent data available from the Energy Information Administration, U.S. refineries took in 87.2% of gross monthly U.S. supplies, only slightly higher than the monthly average of 85.9% since January 1981. However, crude oil stocks have continued to build at a steady pace since 2001, and closed May at 1.082 billion bbl, just a shade below the all-time high set in May 2011.
Separately, experts said the prospective liquefied natural gas (LNG) export business is alive and well, but not for the under-capitalized or inexperienced.
Attorney Stephen Davis of Akin Gump Strauss Hauer & Feld LLP, sees the export issue as being broader than LNG, seeking instead gas molecules that take various forms in future export markets. Davis sees an “all-of-the-above” energy scenario developing in the U.S. gas export space. “We either are going to be having exports of LNG, or petrochemicals that are from ethane or propane that are derived from the gas stream, or we will export natural gas liquids from those streams or directly converted from gas, or it could be ‘all-of-the-above,'” he said.
Julia Sullivan, a senior policy adviser for Akin Gump, said both the “thirst in the market” for LNG exports and the discussion it is stimulating among policy wonks and elected officials in Congress is a clear sign there is going to be more action in this space. “We have a lot of activity on LNG among our clients,” Sullivan told NGI. “There are a number of very sophisticated companies that are very savvy about natural gas deals, and the fact that they think these export facilities are going to be built, fully subscribed and financed is really all I need to know.”
Davis and Sullivan said the most likely export facilities will be at existing import sites, particularly along the GOM, and perhaps on the East Coast. “I don’t know that all of the projects have the same viability,” Sullivan said. “There is a wide range among the applicants [for export permits].”
Bob Braddock, the project manager for the proposed Jordan Cove LNG import-export project in Oregon, sees new LNG projects as being overwhelming in cost ($7.5 billion) and impact on local communities. “It is imperative that the community preparation for the scale of these undertakings be done well in advance,” Braddock told NGI.
Braddock said the West Coast has some shipping advantages for the Asian market and that the greenfield-brownfield differences among prospective export projects can be overstated.
“Yes, it is true greenfield projects are facing higher costs, but even the previously constructed LNG import projects are not immune to cost escalation since the original important investments account for less than 30% of the cost of the export facility,” Braddock said. In addition, “because shipping costs from the North American West Coast are less than half the cost of shipping to Asia from the Gulf, West Coast facilities can absorb a high investment cost than their GOM counterparts and still be competitive in delivering LNG to Asian customers.”
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