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Lifting the U.S. Crude Export Ban: Impact on Oil, Biofuels, Wind & Solar & the Evolution of the U.S. Energy Landscape

crude export ban and impact on renewables

Now in the hands of President Obama for final sign off, the budget deal that could end the 1975 oil export ban, could also extend investment and Production Tax Credits (ITC and PTC) that support wind and solar energy.

The tax measure (a provision sought by Democrats in exchange for lifting the oil export ban), if passed, will extend a $1.00/gallon biodiesel credit, a five-year extension on a production tax credit for wind developers, and an extension on an investment tax credit for commercial, utility, and residential solar developers for the next five years. Below further details how this tax measure could impact the different commodity and energy markets.


The extension of the solar tax credit will add an extra 20 GW of solar power, which is more than every panel ever installed in the U.S. prior to 2015, according to Bloomberg. Additionally, the wind credit will add another 19 GW over the next five years.

In the medium- to long-term, the extensions of tax credits for wind and solar energy will prove to be much more significant than the long-overdue removal of the oil export ban. The production tax credit for wind and the investment tax credit for solar energy have been important factors in the rapid growth of renewable energy sources, but uncertainty over their longevity has held back investment. Now, with a clear understanding of policies for the next five years, those industries will be much better positioned to plan their investments.


The tax credit extension will be very positive for the solar market and its development. At a high level, the tax credit should help even out the potential bubble that would have been seen in the market at the end of 2016, helping to alleviate the potential volatility in the market. Additionally, the ITC expiration was expected to require a lot of job cuts in the industry, so if it’s extended, it will likely at minimum stay the same, but should continue to grow.

projected solar growth

At a more granular level, the tax credit will do more for solar analytics than what it does for just monitoring. Demand for analytics has always been nascent because photovoltaics (PV) is still sub-scale, compared to other energy assets. According to recent articles, the ITC extension could boost the market by more than 50 percent, which is a huge step towards real-scale. When this is combined with the Clean Power Plan and COP21, solar is poised for an incredibly strong growth trajectory.


Similar to the solar industry, after years of uncertainty, this forward-looking tax policy will be a major boon to the biofuels industry. It’s no coincidence that 2013, the last time Congress created a forward-looking tax credit, was one of the best years for the industry.


ERCOT’s installed wind generation capacity currently stands at just over 15 GW as of December 2015, with an additional 3.2 GW of project currently in the queue between now and 2017. Short-term, the volume of planned wind resources significantly outweigh generation from other fuel sources, particularly natural gas-fired generation, despite the continued downward trend of wholesale natural gas pricing.

The proposed extension of the production tax credit is likely to sustain this trend of wind generation taking a larger share of the Texas generation mix as developers are incentivized to bring new wind projects online. As an intermittent, non-dispatchable source of generation, this increased wind generation is likely to continue to drive instances of supply stack volatility seen this winter in ERCOT.


Lifting the decades-long U.S. crude export ban could provide domestic producers with additional markets for light grades and economic incentives to resume drilling programs.  In addition, the U.S. benchmark West Texas Intermediate crude price may strengthen to come into parity with global crudes due to free market competition.

While the deal still needs authorization from both houses of Congress as well as President Obama’s signature, the consensus seems to be that the bill will pass. On Dec. 16, congressional leaders announced a piece of legislation that, in addition to enacting certain environmental measures sought by Democrats, will lift the decades-old ban. The export regulation, titled the Energy Policy and Conservation Act, was enacted in 1975.

If the ban is reversed, some U.S. refiners may benefit while others could face renewed economic challenges. Crude exports would likely ease grade quality imbalance issues on the U.S. Gulf Coast, while squeezing refining margins on the U.S. East Coast.

Though the potential effects on the U.S. midstream industry remain cloudy, increased coastal crude shipments could be a boon for crude-by-rail, which many times links high production centers with shipping docks. The industry, which centers on sending land-locked crude on train in times of capacity constraints, faced headwinds in 2015 as shippers chose new pipeline capacity rather than rail transportation.  

In recent years, light sweet crude production from mostly shale plays boomed in the U.S.: a country with a refining complex optimized to run a heavier, sour crude slate. This growth spurred crude infrastructure growth, a wide-spread crude storage glut and pressured lawmakers to open export opportunities beyond current legal levels.

Price affects production

Though access to free market efficiencies would likely incentivize increased U.S. drilling activities, crude prices are not expected to increase enough in 2016 to significantly alter the production outlook for that year, according to Genscape.

In 2015, lower crude prices sent crude rig counts to levels unseen since the economic crisis of 2009. The price of WTI declined about $27/bbl during 2015 to $34.95/bbl on Dec. 17.

As a result, crude production in the United States is expected to fall by nearly 800,000 bpd year over year in 2016 from 2015, according to Genscape, which did not take into account the lifting of the export ban in the data. The anticipated 2016 year-on-year decrease will mark one of the first times in over five years without a year-on-year increase in crude production.

Increased light crude production in the United States is a supporting factor to lift the export ban. Domestic production during the last five years has almost doubled, hitting a high of 9.6 million barrels per day in April 2015. Nearly all of the growth was light crude. However, U.S. production recently slowed on the decline in crude prices, which was in part due to higher output contributing to the global crude supply and demand imbalance.

Production levels are often affected by the outright crude price. Brent crude prices are expected to average $56/bbl in 2016 with WTI crude prices averaging $5/bbl lower than Brent that year, according to the U.S. Energy Information Administration’s Short Term Energy Outlook released in December. Goldman Sachs, on the other hand, recently warned that crude prices could hit $20/bbl. WTI futures for delivery in January 2017 traded below $45/bbl Dec. 17.

WTI-Brent spread could narrow, inverse

If exports are allowed, WTI-priced crudes will again compete freely in the global market. This will likely bring the spread between WTI and Brent closer to parity or WTI may trade at a premium to Brent, as it did historically before the U.S. light sweet crude boom. The Brent-WTI spread is an important factor when assessing directional crude flows and hedging transportation risk.

Prior to five years ago, WTI always traded at a premium to Brent, and as that spread widened, foreign crude was pulled to the U.S. Gulf Coast because of economic factors. The historical spread between NYMEX Light Sweet Crude futures contract delivery crude, WTI, and Brent detached after crude formed a bottleneck at the storage hub of Cushing, OK. In addition, there was a lack of infrastructure to move the crude from the shale production fields. So, much so that the spread between the two benchmarks reached a point in 2011 where Brent trading at a premium of $28/barrel over WTI.

Gulf Coast refiners could lose the light

Increased crude exports would allow refiners the ability optimize their crudes slates -- especially the refining complex along the Gulf Coast. Refiners there may import more medium and heavy sour crudes, for which there facilities were designed, after a portion of the lighter sweet domestic crude is exported to other markets.

Prior to the shale crude boom, the export ban did not have a material impact since U.S. refiners imported a significant portion of their crude requirements. Companies spent billions of dollars building a U.S. Gulf Coast refining complex to optimize heavy and medium sour crudes, which primarily imported from the Middle East, South America and Canada. The inability to export growing U.S. crude, or even Canadian crude that had not be segregated as it passed through the United States, resulted in a market where refineries do not process the optimal blend of crude for the design of the plants.

East Coast refiners may feel the squeeze

Should exportation of light sweet domestic crude limit supply to the East Coast due to uneconomic rail movements, refiners there may again be in hot water. The shale boom revitalized many East Coast refineries, who were close to closing on poor profits, by replacing more expensive comparable oil with new light domestic production by rail.

Though they have recently resumed sourcing foreign oil in greater shipments, East Coast refiners continue to run Bakken crude by erasing some portion of poor shipping margins with profitable refined products crack spreads, which measure a refineries profitability, and investing in midstream assets. During the past year, crude-by-rail unloadings on the East Coast have declined, but remain healthy at some locations.

Midstream caught in the middle

It’s left to be seen what changes may occur in the midstream if exports are expanded. With light, sweet crude the most likely to be exported, crude by rail movements in the Bakken region may be the first to rebound as infrastructure and capacity are readily available.

The same goes for piping excess crude pooled in the U.S. Midcontinent to Gulf Coast ports for export. Utilization on three key pipelines connecting Cushing and the Gulf Coast has decreased over the past two months, averaging only 50 percent utilized in the last six weeks, according to Genscape. Should production volumes significantly increase, stalled infrastructure projects such as Shell’s proposed 900,000 bpd St. James, LA, to Port Neches, TX, Westward Ho pipeline, a potential reversal of the Marathon-operated 1.2 million bpd St. James to Patoka, IL, pipeline, or Spectra’s proposed 400,000 bpd Guernsey, WY, to Patoka pipeline could be accelerated if de-bottlenecking is needed.

Exports already increasing

Export activity allowed under the current export ban has already increased along the Gulf Coast. So far in 2015, an average of nearly 1.5mn barrels per week of crude was moved from Gulf Coast ports to Canada with additional stabilized condensate exports to Western Europe, the United Kingdom and the Caribbean. More than three million barrels of crude were destined for Canada from the Gulf Coast during the week ending Dec. 4, according to Genscape.

Transportation of crude from the Gulf Coast to Canada has been an essential mechanism to ease storage capacity constraints in the Gulf Coast region. If the volumes moved to the Canadian East Coast over the last six months were held in storage instead, capacity utilization would have reached the operational maximum threshold of 80 percent this week, according to Genscape.

Many energy companies in the Gulf Coast region are expanding storage and transportation infrastructure to help accommodate the rapidly increasing crude inventories and potential crude exports. In 2015, more than 15 million barrels of new storage capacity was brought online along the Gulf Coast in Houston, Beaumont-Nederland, TX, Corpus Christi, TX, and St. James terminals. An additional 23 million barrels of storage capacity is under construction in the region, according to Genscape.

Because it significantly affecting the oil industry, along with renewables, including wind, solar, and biofuels, the deal, if it goes through, could significantly impact the speed at which the U.S. energy landscape evolves and changes.

With the world’s largest private and patented network of land, sea, and satellite monitors, Genscape delivers exceptionally accurate market insight and intelligence. To learn more about Genscape’s suite of product offerings, click here.