We are reducing our fair value estimate for EOG to $61 per share from $86 to reflect the depressed oil outlook following the collapse of the OPEC+ coalition and the continuing escalation of the global COVID-19 crisis.
Oil prices crashed on March 6 after Russia surprised the market by refusing to agree to shoulder a portion of the production cuts proposed by OPEC for the wider OPEC+ partnership. The disagreement was escalated when Saudi Arabia responded with wide discounts on its oil exports, kicking off a price war. That leaves individual OPEC members free to ramp up their production and is likely to result in heavily saturated oil markets for the next couple of years, materially reducing futures prices for crude. That these events coincided with the worsening of the coronavirus outbreak makes things exponentially worse: Essentially, it combines a supply shock with a demand shock.
However, we think stock markets have overreacted. EOG’s current price essentially assumes that oil prices never recover. However, the marginal cost of supply is still around $55 a barrel for West Texas Intermediate-- the price required to encourage development in the U.S. shale arena. Russia and Saudi Arabia do not have enough spare capacity to displace the 10 million-plus barrel/day U.S. shale industry, and we estimate the coronavirus impact on long-term demand will be marginal, even if 2020 demand plummets. Thus, further growth is required from U.S. producers for supply to keep up with demand after 2021, and that won't happen without higher prices.
In addition, EOG still has above-average financial flexibility. It has $4 billion in liquidity, and at current prices will outspend by around $2 billion through the end of 2021. With debt/capital at just 20%, it can probably roll the $1.8 billion debt coming due in that window, which means it could theoretically maintain the dividend ($1.4 billion).
Business Strategy and Outlook
EOG Resources stands out among large-cap exploration and production companies because it derives most of its production from shale. Only about 10% of its output is sourced overseas (mostly in Trinidad, with a small contribution from the United Kingdom). Shale-focused E&Ps tend to be much smaller, with assets concentrated in one or two basins. But EOG has exposure to most major shale plays, including the Permian Basin, the Eagle Ford, and the Bakken. Additionally, the focus now includes the Powder River Basin and the Anadarko Basin.
Due to the combination of its size and focus, EOG has significantly more shale wells under its belt than most peers. This has enabled it to advance more quickly up the learning curve in each play. As a result, initial production rates from new wells are usually well above industry averages (though subsequent declines are usually steeper as well--EOG isn't necessarily producing more oil from each well, but it is recovering the available volumes more quickly, boosting profitability).
The firm's acreage contains 10,500 potential drilling locations that management designates as "premium." These are expected to generate internal rates of return of at least 30% (assuming $40/bbl WTI and $2.50/mcf natural gas). Opportunities that don’t currently satisfy this criteria may be upgraded later, if the company can reduce the expected development cost or boost the likely flow rate of the well. During the past several years, EOG added more premium locations than it drilled, resulting in a net increase to its drilling inventory.
The company also benefits from a high degree of vertical integration. In addition to gathering structure, EOG has its own sand mine to supply proppant for fracking. It was also the first upstream company to bring completion design in-house, giving it more control over the cost of each well, and it supplies its own water, tubular goods, chemicals, and drilling mud as well. It is therefore less beholden to the service industry and can utilize more low-cost mom-and-pop suppliers for its third-party equipment needs.
Until recently, very few shale producers were paying attention to shareholder returns, but EOG was one of them. The firm actually delivered excess returns on invested capital for five of the six years of 2009-14, before the downturn in global crude prices began. That pushed returns back in negative territory for several years. But a relentless focus on cost-cutting, productivity, and efficiency eventually paid off, enabling EOG to start earning its cost of capital again and qualifying the firm for a narrow moat rating.
Management has achieved this by focusing on what it calls premium drilling locations--those it believes would earn a 30% internal rate of return at $40/bbl WTI and $2.50/mcf natural gas. The location of a horizontal shale well plays a huge part in determining its eventual productivity and also influences the oil content of its production stream. EOG’s acreage is mainly located in areas that typically yield very impressive initial flow rates and strong oil cuts, giving the company a clear cost advantage.
EOG’s inventory contains around 10,000 net drilling locations that meet management’s premium criteria. As it stands, that’s enough to support 10-15 years of further activity. But that’s a bare minimum estimate: The firm is establishing a record of “upgrading” nonpremium locations (of which it has several thousand more) to meet the criteria. By tweaking well parameters in nonpremium areas to raise productivity expectations, or by lowering costs through efficiency gains, it can add premium locations without spending capital. 2017 and 2018 are great examples, as the firm added more premium locations than it drilled (without making acquisitions).
Strong acreage isn’t the only reason that EOG wells outperform industry norms. Trial and error enables shale producers to optimize the design of their wells, enhancing productivity over time. As one of the largest shale companies, EOG has access to a more complete database and is able to better optimize the completion process to drive superior performance. As a technical leader, it can rely more on third parties mainly for equipment rather than technical expertise (enabling it to control costs by utilizing more mom-and-pop suppliers). But these advantages aren’t necessarily sustainable, and other companies can theoretically catch up as they climb the learning curve. It is the land itself that EOG has already locked up that forms the basis of its economic moat, because this advantage cannot be replicated.
The firm has a long history in the shale patch, starting with the Barnett Shale, which it was developing in 2004. That play is one of the earliest examples of an unconventional field made profitable through advances like fracking and, later, horizontal drilling. EOG also entered the Bakken Shale at a very early stage in the basin’s development, and by 2010 it was already active in most of the areas it is developing today. By being an early mover, the company was able to keep acquisition costs under control, giving it a sustainable advantage over peers that rushed in later and overpaid.
EOG deviated only once from this strategy of getting in early and avoiding lofty premiums, when it purchased Yates Petroleum for $2.5 billion in 2016. Even then, the transaction took place at the low point of the commodity cycle, presumably resulting in more favorable terms for EOG than it would have otherwise ended up with. In any case, no further deals are expected. Management usually seeks to avoid large-scale acquisitions, and as the company has already assembled enough premium inventory to keep it busy for at least 10 years, there’s no need to extend the portfolio.
Fair Value and Profit Drivers
Our primary valuation tool is our net asset value forecast. This bottom-up model projects cash flows from future drilling on a single-well basis and aggregates across the company's inventory, discounting at the corporate weighted average cost of capital. Cash flows from current (base) production are included with a hyperbolic decline rate assumption. Our valuation also includes the mark-to-market present value of the company’s hedging program. We assume oil (WTI) prices in 2020, and 2021 will average $30/bbl and $32/bbl, respectively. In the same periods, natural gas (Henry Hub) prices are expected to average $2.10 per thousand cubic feet and $2.50/mcf. Terminal prices are defined by our long-term midcycle price estimates (currently $60/bbl Brent, $55/bbl WTI, and $2.80/mcf natural gas).
Based on this methodology, our fair value estimate is $61 per share. This corresponds to enterprise value/EBITDA multiples of 14 times and 11 times for 2020 and 2021, respectively. Our production forecast for 2020 is 916 thousand barrels of oil equivalent per day, which is at the high end of recent guidance. That drives 2020 EBITDA to $2.7 billion, and we expect cash flow per share to reach $4.72 in the same period. Our 2020 estimates for production, EBITDA, and cash flow per share are 939 mboe/d, $3.6 billion, and $6.15, respectively.
Risk and Uncertainty
As with most E&P firms, a deteriorating outlook for oil and natural gas prices would pressure EOG’s profitability, reduce its cash flows, and drive up financial leverage. Other risks to keep an eye on include regulatory headwinds (most notably environmental concerns) and uncertainty regarding future federal tax policy.
EOG is one of the few firms in our coverage to focus on delivering returns to shareholders. It has delivered excess returns in most years since inception (1999). Employee compensation, including management, depends heavily on returns on capital employed. Unlike ROIC, this metric overstates profitability because it does not incorporate asset write-downs, which occur periodically in the oil and natural gas industry (EOG reported more than $6 billion of impairments in 2015). However, ROCE is still a better yardstick than production or EBITDA growth. Maximizing ROCE (and thus ROIC) is engrained into the culture at EOG.
We award a Standard stewardship rating.
EOG Resources is an oil and gas producer with acreage in several U.S. shale plays, including the Permian Basin, the Eagle Ford, and the Bakken. At the end of 2019, it reported net proved reserves of 3.3 billion barrels of oil equivalent. Net production averaged 818 thousand barrels of oil equivalent per day in 2019 at a ratio of 72% oil and natural gas liquids and 28% natural gas.