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Oil: Rearrangement of Pricing Relationships is Likely

One of the key sectors of the U.S. economy impacted by the border adjustment aspect of the DBCFT is the oil sector, for both consumers and producers.

The border adjustment provision as proposed would effectively eliminate the tax deductibility of expenditures on imported goods including imported raw materials—such as crude, feedstocks, and blendstocks--used in manufacturing. If this were to become law, it would effectively raise the cost of imported crude relative to domestic crude by the marginal tax rate times the cost of crude.

At an oil price between $50-$55, that would be more than $10/barrel. U.S. crude producers would benefit as refiners would have a huge incentive to purchase domestic rather than imported feedstocks. However, refineries and petchem plants dependent on imported crude, feedstocks, and blendstocks—for example, most refiners on the U.S. East Coast--would be at a competitive disadvantage under this plan.

Broadly speaking, refiners facing a loss of tax deductibility for imported crude will face a disadvantage approximately equal to the marginal corporate tax rate (proposed at 20%) times the price of crude. At a $50/b crude price, this would represent a $10/b cost disadvantage. Refiners will seek to substitute domestic crude for imported crude and in that process, the price of domestic crude will be bid up relative to imported crude. When equilibrium is reached, the premium for domestic crude should just offset the tax disadvantage.

Whether exceptions will be made for Canada and/or Mexico is still an open issue and could be a piece of a renegotiated NAFTA agreement. This is not a trivial matter, as 41% of total U.S. crude imports are from Canada, while 7.5% are from Mexico. The regional importance of Canada crude is even more important to Midwest and Rocky Mountain refining economics.

The specific impacts will depend on the details of the proposal, which are still at the early stage of development. However, based on the analysis to date, we would expect the following:

  • One aspect of border adjustment—the presumption that the dollar will reset in value and that consumers will not be impacted by higher import prices—is not a factor when discussing crude or other petroleum feedstocks. A commodity like oil is priced in dollars worldwide, so there is no reset that can occur. The U.S. oil producing industry is not in the same situation as the U.S. retail industry.
  • U.S. crude producers would benefit to the extent that the proposal has a similar impact to a tariff on foreign oil and raises the price of domestic production. Eventually, this will lead to higher U.S. production. There would be feedback impacts on providers of domestic upstream services, such as rig operators, well service operators, and upstream labor markets. Land values of oil producing and prospective acreage would rise, supporting debt collateralization.
  • U.S. crude exports would be highly disincentivized with the domestic market priced above international markets.
  • Refiners that currently rely on imported oil with limited ability to export products (e.g.,the East Coast) will be disadvantaged, possibly to the point of curtailing crude throughput and processing.
  • Domestic refiners that purchase U.S. crude and export products would benefit, especially since they would not pay corporate income tax on export revenue. However, U.S. product exports would likely not expand since parts of the U.S. (Northeast) would be product-short, particularly if refineries there cut runs or closed. Refiners are running close to capacity, so we would not expect a large increase in overall runs.
  • Many of the Houston area domestic refiners are already included in free trade zones. The Port of Houston Authority manages Foreign Trade Zone (FTZ) No. 84, which includes many privately-owned and port-owned sites located throughout Houston and Harris County. The Houston Zone offers users special benefits. For example, customs duties on imported goods entering the FTZ can be delayed until the cargo is removed from the zone. No duty is paid if the merchandise is exported directly from the zone. As such, many of these entities already benefit from the existing playing field. Whether that would change is a matter for consideration.
  • There would an increase in returns to transporters (pipeline and vessel) with the ability to move product from product-long to product-short markets within the U.S. The key movement of such products and crude, for that matter, is critical to meeting demand/consumption in key regions, such as the U.S. East Coast.
  • Domestic product prices will rise. The average price of U.S. crude will be higher since crude imports would fall. Consumers would face higher pump prices, on an order of magnitude up to 25 cts/gal. There would be disparities in the degree of increase, with the East Coast facing potentially the greatest rise in pump prices. Inland protected markets would be somewhat buffered, but not immune, from upward price pressures. Impacts on short-term and longer-term demand trends would be noticeable as prices rise. Higher prices could foster demand for smaller more fuel efficient cars. Growth in vehicle miles traveled would be less than it otherwise would be, thus providing a double whammy on fuel consumption.
  • All else equal, global crude prices would probably be slightly lower since the policy would create some additional U.S. supply and would have a slight negative impact on demand due to higher product prices. Whether Canadian or Mexican supply would be impacted would depend on whether an exclusion was negotiated.
  • Petrochemical processors and manufacturers would be less impacted by the proposal, since most of their feedstock is domestically sourced and derived from natural gas production, along with much of their output being targeted to the export market. The projected upward impact on domestic natural gas prices is seen as much less than crude oil and petroleum products. A preliminary assessment of the proposal’s impact on the petchem sector is seen as modestly positive, to the extent export demand holds up.

U.S. Balances By PADD, Jan-Nov 2016

(MBD) PADD I (East Coast) PADD II (Midwest PADD III (Gulf Coast) PADD IV (Mountain) PADD V (West Coast) U.S.
Crude Runs 1,112 3,612 8,495 598 2,357 16,173
Imports-Crude (Region of Entry) 867 2,356 3,159 327 1,170 7,879
Import Dependency 79.5% 60.6% 39.6% 45.5% 49.7% 48.7%
Net Receipts Crude 213 -214 236 -364 129
Crude Exports 150 79 281 8 10 527
Demand (Consumption) 5,424 5,014 5,441 709 3,010 19,599
Local Supply 3,897 4,597 7,832 3,084 129 20,064
Local Coverage 71.8% 91.7% 143.9% 92.4% 102.5% 102.4%
Imports-Product 1,034 115 717 14 322 2,202
Net Receipts Product 3,138 -354 -2,873 -308 397
Product Exports 267 367 3,610 8 382 4,636
Crude Imports* 884 2,189 3,362 272 1,172 7,879
- Canada 243 2,147 350 272 229 3,240
- Mexico 14 16 572 N/A 1 588
Product Movements
PADD III(USGC) to I (EC) (pipeline) 2,595
PADD III (USGC) to I (EC) (tanker/barge) 586
PADD III(USGC) to II (MW) (pipeline) 658
PADD III (USGC) to II (MW) (tanker/barge) 56

*By Region of Processing

Based on the above table, the key takeaways with regard to overall U.S. and regional balances are as follows:

  • U.S. East Coast (PADD I) is the region most dependent on imported crude at 79.5%, with only about 27% of the imports being from Canada. The Midwest (PADD II) is also heavily dependent on imported crude at 60.6%, but almost all of it is from Canada.
  • The Gulf Coast (PADD III) still imports a large volume of crude, 3.16 MMB/D, which is 40% of total U.S. crude imports, though the processing dependency is less than the U.S. average at 39.6%. The Gulf Coast imports 0.9 MMB/D of Canadian and Mexican crude, about 27% of the imports that are processed. The region exports a large volume of product, some 3.6 MMB/D. The economics of these continued exports would be at risk as domestic crude prices rise, and the resulting product output must face international market competition, at which it would be disadvantaged.
  • The U.S. East Coast (PADD I), is dependent on shipments from other regions to meet demand. Local supply only covers 71.8% of consumption, a shortfall of 1.5 MMB/D. This shortfall is made up of product imports of over 1 MMB/D, and shipments from the U.S. Gulf. The Gulf moves 2.6 MMB/D via pipeline and more than 0.6 MMB/D via tanker or barge. To the extent East coast local supply is cut back, additional movements would be necessary, either via pipeline or tanker/barge. Availability of Jones Act compliant vessels for waterborne movements could be an issue, while idle capacity on the key Colonial Pipeline system would also be an issue. Lastly, to the extent that the region would have to rely on additional movements, its vulnerability to pipeline disruptions increase, as such movements take a significant time period (20-30 days), where local supply can adjust much more rapidly, if price signals and profitability are supportive to stepped-up operations. Such time delays would exacerbate price spikes due to unforeseen supply disruptions.
  • The U.S. Midwest (PADD II) is 91.7% covered in terms of consumption vs. locally produced supply. However, there is a shortfall of about 0.4 MMB/D which is met from product movements from other regions. Movements of product into the Midwest from the Gulf, via pipeline, are 0.66 MMB/D, while 56 MB/D are moved via tanker-barge. With regard to import reliance, as mentioned, the region relies on 2.2 MMB/D of imported crude, almost all Canadian.
  • The Rocky Mountain region (PADD IV) is almost covered with regard to local supplies (92.4%), but does rely on 0.27 MMB/D of imported Canadian crude to meet its processing requirements, which is 45.5% of the crude it processes.
  • The West Coast (PADD V), is mostly covered with regard to local supply, but does rely on 1.17 MMB/D of imported crude to meet almost 50% of its processing requirements. Only 0.23 MB/D is sourced from Canada, and minimal amounts from Mexico. The balance is largely from Saudi (0.3 MMB/D), Ecuador (0.2 MMB/D), and Colombia (0.12 MMB/D). The region does rely on 0.32 MMB/D of product imports, but also exports about 0.38 MMB/D. Such export flows could also be at risk, depending on refining economics.
  • The U.S. has become a major exporter of refined products in recent years, the biggest in the world by far. Under the DBCFT, refiners with access to export facilities will initially have an incentive to export (no tax). So this would tend to drive domestic product prices higher until refiners are indifferent. That effect will ripple through the interconnected U.S. product markets. However, it may not be true for smaller products that are not being set by export parity (e.g., LPG exports will be driven by the much larger NGL producer volumes and their economics have higher domestic operating costs, and so cannot support as high an increase in domestic LPG prices). The net effect is that both domestic crude and major domestic products move up similar amounts. But if there are some smaller products that do not move up as much, it would tend to reduce refinery margins somewhat.