This September marked the one-year anniversary when 12 major shareholders in US shale oil and gas producers met in Manhattan to discuss ways to turn fracking operations from cash burners into cash distributors. In the following months since that clandestine meeting, the very same shareholders, including Invesco Ltd., Macquarie Group and others, pressed executives to curtail capital expenditures and instead use that cash to reward investors with dividends and share buybacks.
One year on, the pressure appears to be working.
Remarkably, U.S. exploration and production companies (E&Ps) generated enough output in 2018 to equal the entire growth in global demand, yet wildcatters hit those production goals with half the capital investment of 2014.
“The driver has been a shift to a manufacturing mode that has transformed the E&P industry as dramatically as Henry Ford’s moving assembly line changed the automobile industry in 1913. Geophysical and technological innovations, such as multi-well pad drilling, have allowed the industry to double output per well bore at half the previous cost,” writes Nick Cacchione for RBN Energy. “With oil prices and margins rising, you’d think the E&P industry, which historically has invested like ‘there’s never too much of a good thing,’ would be pouring every available dollar into drilling more and more wells. But that isn’t the case. Instead, mid-year 2018 guidance shows that producers have adopted the long-term investment strategies usually associated with integrated oil majors, plotting incremental increases in investment to methodically accelerate production growth to 2020 and beyond.” RBN Energy tracked 44 E&Ps that reported USD 21 billion in pre-tax operating profits, up from USD 6.2bn in the first six months of 2017, and over USD 50 billion in operating cash flow, up from USD 39bn a year ago. Most notably, these companies are on pace to garner an astonishing USD 30bn in free cash flow.
“Yet, in their financial reports for the first half of 2018, our group of 44 E&Ps boosted total 2018 capital spending by only USD 3.9bn, or 5%, over their initial guidance to USD 68.1bn, which is 10% higher than their 2017 investment,” Cacchione added.
Oil prices fell further on Thursday, after OPEC lowered its oil demand growth forecasts for this year and for next year for the third consecutive month mainly due to a weaker global growth expectations. According to the monthly OPEC’s oil market report, world oil demand this year will increase by just over 1.54m barrels a day, 80,000 b/d less than last month’s estimate while for 2019 oil demand will grow by 1.36m b/d, 50,000 b/d less than the previous projection.
Yesterday, light, sweet crude for November delivery ended 3% lower at USD 70.97 a barrel on the New York Mercantile Exchange, marking its lowest closing value in the past six trading sessions since hitting USD 76.41 a barrel on October 3. In a similar pattern, Brent crude, the global benchmark, fell 3.4% for December delivery to USD 80.26 a barrel from the previous day’s close, though it was still down 7% from the October 3 close of USD 86.29.
Aside from the OPEC forecast, a variety of market and political forces are pushing and pulling the price of oil. Sanctions on Iranian crude exports, production declines in Venezuela and elsewhere, the appreciation of the US dollar, OPEC quotas, and growing US exports are among the most influential factors for pricing.
A bounce-back in oil prices, greater efficiency in extraction, and a lower cost structure for E&Ps has turned the United States into a net energy exporter (the federal government lifted the export ban on oil in December 2015). The race to build the appropriate energy infrastructure – pipelines, gathering and processing facilities, export terminals, storage, etc. – has gained the interest of private equity firms and infrastructure funds, among others, because the projects’ contractual reoccurring revenue streams offer attractive risk-adjusted returns.
According to Wood Mackenzie, an energy, chemicals, renewables, metals and mining research and consultancy firm, found that deep-water oil E&P projects generated a 13% IRR, unconventional oil developments (shale) netted a 20% IRR, and LNG projects earned a 13% IRR. However, unconventional shale plays could face production challenges in the near future, as Wood Mackenzie also recently found that maturing wells are experiencing a roughly 15% decline in annual output. That compares with the 5% to 10% initially modeled.
Despite productivity concerns, oil supply in the US has grown tremendously because of the shale revolution. Midstream developers and operators are eagerly building out the infrastructure to support production activity. As a result, some midstream players are courting private equity firms and infrastructure funds as equity or debt investors in order to monetize assets or gain operational expertise during the early phases of project development.
In fact, several projects slated for the Gulf Coast would expand export capacity for shipping oil to Asia and elsewhere via Very Large Crude Carriers (VLCC). While VLCCs are the most cost-effective method for shipping petrol, the carriers face limited access because of the dimensions and depths harbors must maintain in order to accept them for loading and unloading. See here for the specs on VLCCs and Ultra Large Crude Carriers. Despite these logistical hurdles, in February 2018, the Louisiana Offshore Oil Port (LOOP) completed its first‐ever loading of a VLCC with U.S.‐ produced oil for export at its deepwater port, 18 miles from Port Fourchon, LA. Following the successful LOOP project, several more are slated for the US Gulf Coast, which readers can find here.
The ongoing buildout of energy infrastructure over land continues apace as well, which has implications for buyers and sellers in Mexico and Canada. Several projects call for the construction of pipelines that would carry oil and gas from the Permian Basin and elsewhere into Mexico, where demand is ramping up on the back of recent regulatory reform. In recent months, midstream developers including Sempra’s IEnova unit, NuStar, Riverstone, and USD Group have announced plans to build fuel storage infrastructure in Mexico, where virtually none exists at this time. Industry leaders aim to increase the minimum storage capacity to five days by 2020 and to 11-13 days by 2025, up from the current two- to three-day standard.
On October 24, Mergermarket will host its annual Mexico M&A and Private Equity Forum in Mexico City, where panelists will discuss issues related to importing energy from the US.
Written by
Matt O'Brien
Content Editor
Acuris Studios (moderator)
Matt is content editor for Acuris Studios, the sponsored events and publications division of Acuris Global, since 2016. He curates content for the events team by overseeing research of market trends and transactions relating to corporate M&A and project finance. Matt works with the news editors and reporters of Acuris’ various publications, meets with market practitioners, and stays current with recent developments to ensure the company delivers industry-leading conferences. He also blogs about economic and market trends that affect the financing and structuring of M&A transactions and projects throughout the Americas.
Matt spent nine years in the news reporting industry covering a wide variety of industries and beats as a freelancer and as an employee with various publications. For five years, he worked in the financial services sector conducting research and relationship management for the mass affluent clients of AXA Advisors and then Wells Fargo.
Matt holds a B.A. from Rutgers University where his degree was in Political Science and History. He graduated in 2003.
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