Stratas Advisors is a Hart Energy company.

If the forecast recently published by the Energy Information Administration (EIA) proves correct, production from the Gulf of Mexico will be back to “pre-Macondo” levels sometime in mid-2016. Even as low oil prices continue to put significant pressure on U.S. onshore shale operators, longer-term projects in the deepwater GoM are showing little evidence of a slowdown. At least in the near term, the region will see a production surge in 2015, benefiting from exploration programs that were completed over the past several years. According to the EIA, the GoM will continue to see production increases as new fields come online this year and next, boosting total output to more than 1.61 million barrels per day (MMBbl/d) by 2017.

Hurricane Katrina in 2005 was a massively destructive force affecting GoM production and processing, requiring a couple of years for production levels to recover. Production not only recovered, it pushed materially beyond previous highs. These increases were the result of new projects coming online in spite of being hit by hurricanes Katrina and Ike. But then the explosion on BP’s Deepwater Horizon rig occurred on April 20, 2010.

While the effects of low oil prices might hit a few years from now, it seems there are plenty of operators anxious to move back over to the accelerator, at least for a while.

This catastrophe sent shock waves through the industry’s general understanding of project life cycles under BOEM. Shut-downs and delays accumulated, pushing production back down to post-Katrina levels (notwithstanding the relatively long-lasting support of three-digit oil prices in the period). Last month, the Obama administration put forth legislation designed to enhance operators’ abilities to monitor and control deepwater wells, all in the spirit of avoiding future blowouts.

The proposed legislation, unveiled by the White House in April, would require companies involved in offshore oil and gas drilling in the GOM to implement new and improved standards for equipment and well designs to avoid a catastrophic spill like the Macondo disaster. Among other new requirements for drilling technology, the proposed regulations would also require oil and gas drillers to perform tests and enhanced maintenance on their blowout preventers (BOPs). In addition, drillers will be required to undergo a yearly review by a third party to ensure that the BOP equipment is fit for purpose. Finally, the new law would require a detailed inspection and re-certification every five years.

If approved, these regulatory requirements would likely increase development costs, but not fundamentally. According to the Interior Department, the new standards could cost about 90 companies an estimated $883 million over 10 years. However, as expected, even excluding any net benefits that might accrue to the operators, approvals for these long-term offshore projects are “sticky” after achieving FID (final investment decision). Once billions of dollars have been spent in development, the price of oil would have to drop below project variable costs for an extended time period before we would see a fundamental drop in offshore production. Prices are still far from that point.

Until then, the EIA forecast seems not only achievable, but also logical, given the long queue of projects that have been anxiously awaiting approval to turn on. Between 2014 and 2018, it is estimated that more than 900 Mbbl/d of oil and 1,200 million cubic feet per day (MMcf/d) of gas nameplate processing capacity will have been added to the total supply put forth from the region. Recently started deepwater projects like Chevron’s Jack-St. Malo fields, which came online in December 2014 and will soon ramp up to produce 94,000 bbl/d; Anadarko Petroleum’s Lucius Field, which came online in January with capacity to produce 80,000 bbl/d; and future projects like the Anadarko-operated Heidelberg Field, with another expected 80,000 bbl/d, will prop up production for several years.

Offshore