Ahmad Atwan

perspectives on us energy


22 years industry experience

Ahmad Atwan is a seasoned investor and executive who has consistently created outsized returns for his investors and companies as a private equity investor and operator over the past two decades. His extensive investment experience includes the sourcing and execution of transactions across the energy industry value chain. This includes oil and gas exploration and production, oil and gas midstream and related infrastructure, supporting equipment and services, and downstream infrastructure. He has also invested in the telecommunications and industrial sectors.

Ahmad Atwan has sourced, led, and executed over a dozen energy significant energy transactions and has a superb track record of returns. He has served on a number of boards, and has spearheaded change management initiatives to create value in collaboration with corporate management teams.

Besides over a decade in private equity, Ahmad Atwan has been an entrepreneur and senior executive in energy and technology companies.  Early in his career, he helped to build an energy technology company and sell it at a superb return for investors.  He also founded an energy business in Brazil which he grew and sold to a Chinese firm for many multiples of capital invested.  Throughout these operating experiences, Ahmad Atwan focused on elevating the operational and commercial performance of the businesses by upgrading their management teams and then working hand in hand with them on a daily basis to improve the business.

Ahmad Atwan also has significant experience turning around distressed businesses, both as an investor and an operator.  In multiple cases, he has helped seize control of businesses that were on the verge of bankruptcy and turn them around through a formula based on a relentless focus on cost-cutting, generating G&A, Opex, and Capex reductions, and then repositioning the businesses for growth.  Once the businesses were on sounder financial footing, Ahmad Atwan either brought in new management or upgraded the existing team to re-focus the companies on customer acquisition and growth in a capital-efficient manner.  These turn-around strategies led to significant appreciation in corporate cash flows and outstanding returns to investors

Ahmad Atwan received a Bachelor’s Degree in Economics from Harvard University with the highest distinction, and was among 32 Americans selected as a Rhodes Scholar. He also earned a Master’s Degree in International Relations from Oxford University.

Ahmad Atwan


Ahmad Atwan has expertise across a number of industries, including:

  • Oil and gas exploration and production
  • Midstream energy (oil, gas, NGL gathering and processing and fractionation)
  • Downstream energy (terminals, storage, refining)
  • Energy export (LNG, LPG, oil export)
  • Petrochemicals
  • General industrial, especially relating to natural resources value chains
  • Telecommunications infrastructure (data centers, fiber, and towers)
  • Technology (enterprise software, cloud computing, energy technology)


Ahmad Atwan also has significant expertise across several geographies, where he is able to capitalize on his experience working in developed as well as emerging market and to utilize his language skills.  Some of the key geographies where Ahmad Atwan has spent time and done business include:

  • United States: Houston, New York City, San Francisco (Bay Area), Miami, Boston
  • South America: Sao Paulo, Brazil, Rio de Janeiro, Brazil, Santa Rita, Brazil
  • Middle East: Kuwait City, Kuwait, Dubai, UAE
  • Europe: London, England, Oxford, England

And Now for Some Fun: A Friend’s Top 10 Energy Predictions for 2020 (Some Already Disproven!)


The price of natural gas has a fundamental problem. It’s crude oil.

Over the past three years, more than 80% of the growth in natural gas production has been from associated gas (from wells that predominantly produce crude oil) and rich gas (well economics driven primarily by NGLs). What’s the price of natural gas got to do with it? Almost nothing!  For example, only 2-3% of the typical 2019 Permian well’s revenue came from natural gas. The higher the crude price (which usually provides some uplift to NGL prices), the more growth will come from associated and wet gas, so more natural gas oversupply will weigh down gas prices. The implication? Gas prices stay low as far out as we can see.


Natural gas has another problem. As shale wells age, they tend to get gassier.

In other words, the gas-to-oil ratio (GOR) increases as a well gets older. As more shale wells age, proportionally more gas will be produced. Worse yet, from the perspective of oversupply, the most prolific part of the Permian — the western Delaware Basin — has a GOR more than double that of the Midland Basin and the eastern Delaware. Moral to the story? It’s more gas production that is indifferent to gas prices. So gas prices will be under that much more downward pressure.


U.S. crude oil production winding down? Don’t think so.

As long as OPEC+ hangs in there with those production cuts, now is no time to write off U.S. production growth. Let us not forget that there are still more than 800 rigs turning out there, and they are highly productive units drilling in the most lucrative of sweet spots. At RBN we are still projecting a year-over-year increase in crude production of 800 Mb/d in 2020.


The Permian crude to Gulf Coast differential will get crushed.

Bad news if you are trying to sell crude oil pipeline capacity out of the Permian. We predict that the crude oil price differential between Midland and the Gulf Coast will average a paltry $1.50/bbl in 2020 and periodically shrivel to $1.00/bbl. Back in 2018, the differential averaged $11.60/bbl and came in at $8.20/bbl in the first half of 2019. But the demise of the big spread started in July as Plains’ Cactus II ramped up, followed by the startup of EPIC and Gray Oak. Since October, the differential has averaged only $2.25/bbl. As flows on those pipelines go full bore, downward pressure on the differential will continue to increase.


IMO 2020 finally arrives, not with a bang but a whimper.

We can’t do a prognostications blog about 2020 without some mention of IMO, the new rule that kicked in yesterday and that slashes the allowable sulfur content in bunker fuel used in the open seas from 3.5% to only 0.5%. Bottom line, as we said in a blog posted last week (All Around the World), we think the market will digest IMO 2020 with minimal disruption. In fact, with heavy-sour crude imports from Mexico and Venezuela much lower or zero, some U.S refiners are positioned to make great margins running low-cost resid feedstock that was previously marketed as bunker. That will help make 2020 a good year for sophisticated U.S. refiners.


Crude oil export capacity is not a problem. At least in terms of the capacity to load volumes that need to be exported. Today there is about 6 MMb/d of capacity, for a maximum flow rate so far of 3.8 MMb/d (EIA’s week of June 21, 2019). From the perspective of flows, we see that being enough for the next 4-5 years. The past few weeks are a good example of how it is likely to play out. Exports from Corpus Christi have been ramping up at the expense of Houston, Beaumont and other Gulf Coast terminals. That means that those other terminals have capacity on their hands. Export costs are another matter. New capacity to allow the full loading of VLCCs without reverse lightering — like the planned Enterprise/Enbridge offshore terminal — will allow shippers to cut costs and profitably increase exports. But the takeaway here is that there will be no shortage of physical export takeaway capacity.


NGLs are coming to the rescue in the Bakken.

The past couple of years have been difficult for Bakken producers. Crude prices are down and the economics of drilling and completion are tough to make work outside the four “core” counties in North Dakota. And in those counties, producers have faced a shortfall in natural gas processing and NGL takeaway capacity, which has resulted in more flaring and fewer well completions. But relief has arrived! New processing plants are coming online and ONEOK’s new Elk Creek y-grade pipeline has just started up — it should resolve the y-grade takeaway issue for a long time to come. Also, by allowing additional ethane to be recovered rather than rejected into the gas stream, the new facilities will also reduce the Btu content for gas flowing into Northern Border, the largest gas takeaway pipe out of the Bakken. Northern Border has been struggling with Btu content issues and is reported to be considering a new, tight Btu spec. All in all, it is a good-news story for the Bakken.


There is not enough y-grade to go around for all the new fractionators coming online.

There’s a backstory on this one. In 2018 the NGL market hit a wall, maxing out fractionator capacity. Spot fractionation fees shot up and strange things happened to NGL price differentials (see We’re Not in Kansas Anymore). So the industry responded. A lot. In addition to 475 Mb/d of new Mont Belvieu frac capacity already on track for completion during 2019, 845 Mb/d of additional fractionation was announced for Mont Belvieu and a whopping 1.0 MMb/d of new capacity is being planned from Corpus Christi to Texas City. In our mid-range y-grade production forecast, that’s enough fractionation capacity to last beyond 2025. Which makes us believe that surplus capacity will push fractionation rates lower over the next few years, perhaps a lot lower. Assuming of course that all that capacity gets built. Eventually the capacity will fill up, but it’s going to take a long while.


U.S. LNG will get exported, even if the global gas market is glutted.

Ever since the LNG arb to Asia and Europe collapsed during the summer of 2019, this issue has been hotly debated in the RBN network. If the economics for exporting LNG go underwater in 2020, will cargoes get cancelled (as might seem likely) or will the LNG be exported anyway, due to a combination of onerous contract cancellation provisions, sunk cost economics for terminal capacity and shipping (i.e., a shipper loses less by not cancelling), and likely spot-price behavior both in the U.S. and globally? Our prediction? We think the volumes are going to move offshore come hell or high water, as we say in Texas. In other words, few cancellations. Which is one piece of good news that U.S. gas markets can look forward to in 2020. The bad news falls to LNG shippers that don’t have their cargoes placed. The spot LNG market could get very ugly.


Shale is not over, but it is going to be much more difficult to get projects done.

Seems like every pundit on the street would have you believe that it is “game over” for the Shale Revolution. We beg to differ. Nobody is abandoning a sinking ship. Sure, growth has slowed. But production is still increasing. The problem with the Shale Era is the same as it’s always been: too much success. Econ 101. More supply at a lower unit cost drives prices down. But 2019 did bring with it a couple of profound market shifts that will be with us into 2020 and beyond. The first is obvious. Wall Street has soured on anything to do with oil and gas, and that’s tightened capital markets for both drilling and infrastructure. But it is deeper than that. The industry itself is shell-shocked from what seems like a continuous cycle of capacity constraints, the need for long-term capacity commitments, overbuilds, low prices and collapsing price differentials. A lot of producers are just tired of supporting midstream projects and then getting wacked by the market (and Wall Street) for doing so. Consequently the whole process of infrastructure development has been s-l-o-w-i-n-g  d-o-w-n. Seems like producers are more inclined to deal with capacity issues in a few years rather than sign up for a new project today. That’s the reality of the Shale Era as we enter the new decade.

areas of expertise


Natural Gas