|Shares Out. (in M):||580||P/E||14||16.3|
|Market Cap (in $M):||51,000||P/FCF||0||0|
|Net Debt (in $M):||5,200||EBIT||4,300||0|
There are 580 million EOG shares outstanding, $5.2bn of Long-term debt, $1.1bn in cash and equivalents and $1bn of retirement obligations for a Market cap of $51bn and an EV of $57bn today. EBIT in 2018 was $4.4bn.
I would recommend taking a look at the discussion thread started in November 2018 by hkup881 on “Understanding Oil Stocks” for some background in the sector. Also, snarfy, ad17, and a few others have posted good write-ups on oil & gas names in the past, which I would recommend you read as well.
While the E&P business itself is not complicated, understanding the economics of each particular company, as discussed in the thread referred to above, is not easy. And, as demonstrated by the poor overall returns generated by investing in E&Ps directly (or the energy sector in general), not worth the time and effort in most cases.
the 15% annualized returns EOG has delivered since been spun-off of Enron in 1999
that it has generated average ROCEs of 12% (vs. a cost of capital of around 8%) in that same time frame and has paid a growing dividend every year since 1999.
that it is considered “the” benchmark amongst peers for being a good operator, being low cost, having a unique culture and being well managed
I was very surprised to find that there’s never been a write-up on EOG in VIC. I assume that having always traded at a “premium” to its peers from a multiple of earnings or cash flow perspective, traditional “value” metrics automatically exclude it. In any case, I believe it has the qualities of a great business in a “bad” sector, and that it is trading at an attractive valuation, with the potential for double digit returns in the years to come. Below is my take on EOG (from a generalist perspective, of course)
History of the business:
EOG is the largest shale oil producer in the US lowest 48 states. Originally part of the Enron Corp, it was spun-off in 1999, the year in which Mark Papa was elected Chairman and CEO of the company.
The company was initially focused on gas exploration and production, at a time when the US was believed to be running out of gas. After finding and drilling for oil in the Bakken play in North Dakota in 2007, the company began shifting its strategy towards producing more oil and liquids. This shift proved very successful after EOG acquired 520,000 acres in the Texas Eagle Ford. Industry experts believed this to be a mature basin, and EOG was able to get their acreage for less than $450/acre. 2010 marked the first time when more than half of revenues came from liquids production rather than gas, as of 2018, the volume mix is 56% Crude Oil, 16% NGLs and 28% Natural Gas.
In 2010, EOG acquired acreage in the Permian and Niobrara basins. In 2013, the company became the largest oil producer in the US lower 48 states, when it reached 220 kbpd of net crude oil production. Oil production has grown at 25% CAGR over the last decade, from 45kbpd in 2008 to 400kbpd in 2018.
Around 2008, Mark Papa, then CEO, realized that the US had moved from a natural gas deficit position to an oversupply situation. In 2006 he had already started a realignment of the organization to find oil. He understood that the same fracking techniques could unlock oil.
EOG has been unique in its sector from the very beginning in that it focused on maximizing value per share, rather than increasing production volume for growth’s sake. In his early CEO letters, Mark Papa was always very vocal about the need to generate returns on the capital employed and on his plans to run the company with a long term view of actually creating value for shareholders in an industry that traditionally destroys it. He was a believer in being a low cost operator, in investing to retain a low cost advantage and in worrying about returns before growth. He also believed in paying a dividend that was covered by operating cash flows and in growing the dividend (they’ve grown the dividend at a 19% CAGR since they first started paying one) as a way to maintain capital discipline. They have increased the dividend payment in 18 of the last 20 years and currently pay-out about $0.9/share. While small, the consistency of the payment is remarkable in the E&P space.
EOG asset base at the end of 2018 is almost 100% US based. Their objective has now moved from being the lowest cost US E&P to becoming one of the lowest global oil & gas operators.
Shift to Premium Wells:
In 2015, EOG set the foundations of their Premium Drilling program, asking each of their seven divisions to identify wells capable of delivering “solid direct and all-in rates of return at commodity prices as low as $40/bbl and $ 2.5/mcf”. The idea was simple: generate returns on capital above its cost sustainably. These returns were later specified to be at least 30% at $40/bbl WTI and $2.5/mcf Henry Hub.
In 2016, premium wells were delivering over 100% total returns, compared to 20% for non-premium wells. They were also delivering ca. 200,000 barrels of production in their first year; double that of non-premium wells and equivalent to 548boepd/well. They were also advantaged in terms of total finding costs, at $6.9/boe vs. $13.25 for non-premium wells. The company completed 220 premium wells during the year and 225 non-premium ones.
At the end of 2018, EOG had 18.5k drilled and undrilled locations (vs. 16,000 at the end of 2016) across its 2.2 million acres in the US lower 48 states. Of these, 9.5k are premium undrilled locations (compared to 6,000 at the end of 2016, and 3,200 at the end of 2015), of which 24% were Eagle Ford, 51% Delaware Basin and the remainder Bakken and Rockies locations. The total resource potential (not PDP) identified with their premium locations was 9.2 billion barrels of oil equivalent, up to 970kboe per well.
In 2018, around 90% of the 760 completed wells were Premium wells but they no longer break this down.
As explained during the 4Q 2015 earnings call, they expected a large portion of non-premium inventory to be converted to premium through technology and efficiency gains over time, with the rest of the inventory adding value to property sales or trades. The results to date demonstrate they’ve done this. Net undrilled premium locations as of the end of 2018 are 9,500 and they expect 740 well completions over 2019.
According to Mark Papa buying 500,000 of the right acreage in the Eagle Ford unlocked ca. $30bn of market value for EOG. It remains to be seen how much value EOG can create in addition to its current market cap by developing the identified locations. In any case, they currently have 13 years of Premium drilling inventory ahead, and they are replacing Premium locations twice as fast as they are drilling them. For investors in a low cost operator focused on Returns on Invested Capital, this seems like a very good thing.
At the end of 2018, EOG operated over 10,000 net wells, 99% in the US and 64% of which crude oil wells. They completed 759 net wells in 2018, of which 704 were crude oil.
Some comments from management on capital allocation:
“EOG’s capital discipline governs our growth. Disciplined growth means not adding overpriced or poor performing services and equipment in order to grow. Disciplined growth means not growing so fast that we outrun the technical learning curve and leave significant reserve value in the ground. Disciplined growth means operating at a pace that allows EOG to sustainably lower costs and improve well productivity instead of growing so fast that costs go up and well productivity goes down”
“We will not issue new equity or debt to fund capital expenditures or the dividend”
“EOG is driven by returns. Our goal is to earn return on capital employed that is not only the best among our peers in the E&P industry but also competitive with the best companies outside of our industry (…) By executing on our premium capital allocation standard and practicing capital discipline, we believe we can sustain competitive ROCE throughout the commodity price cycle”
“Our number one priority for that cash is to reinvest into high-return premium drilling. We also want to continue firming up the balance sheet with non-core asset sales. And if the business environment continues to improve, we will want to refocus on our commitment to the dividend”
EOG has historically been wary of acquisitions, rather focusing on organic growth. Other than small add-on to assets in order to enhance a location prospect, and regular sales of non-core assets in order to optimize the portfolio, EOG had not engaged in large M&A deals until 2016. In September of that year, EOG announced the acquisition of Yates Petroleum. They substantially increased their exposure to the Delaware Basin (Permian) and doubled their acreage in the Powder River Basin (Bakken). They also gained exposure to smaller plays and different locations. EOGs shift toward becoming an oil producer was implemented by acquiring acreage both in the Bakken and the Eagle Ford. They proved very successful plays, but the Bakken became uneconomical after 2014 with oil prices falling. EOG had a decent position in the Permian basin, but given the attractiveness of the basin, these were not enough to drive EOGs attempts of becoming a global low cost producer. The Yates acquisition helped with this, as it gave them 78% more acres in the Delaware basin than they had. They issued 25 million shares for a total consideration of $2.3bn plus $37 million in cash. The shares moved 14% higher over the two months following the announcement, allowing them to issue less shares than initially estimated. In retrospect, and based on comparable transactions, the Yates acquisition was a good deal, as they gained very good assets without paying the premiums that other peers paid in the Permian basin during the 2016 and 2017 rush. In my estimates, they paid ca. $5.7k/acre, when some competitors were paying $20k and more per acre at the time. The deal also added diversification of assets, as Yates Petroleum had been in operation for over 90 years and had acreage in multiple locations across the US. The consideration paid was roughly equal to the book value of the net assets transferred, thus there was no goodwill created as a result.
Their efforts since the downturn have translated into lower operating costs, which have come down from $12.9/bbl in 2014 to $9.4/bbl in 2018. As a rule of thumb, an E&Ps breakeven price tends to be equal to 2x F&D costs + operating costs over a 3-5 year period. Using previously disclosed figures for F&D costs of Premium ($6.9/boe) and non-Premium ($13.25/boe), Premium wells breakeven (minimum oil price at which they will generate a 10% IRR) at ca. $24/boe, compared to $37/boe for non-Premium wells.
It should be clear why the strategy to focus on Premium wells makes sense financially: having lower Finding & Development costs leads to a lower Depreciation & Amortization charges over time as this charge converges to the F&D costs of Premium wells drilled. From an accounting perspective and according to EOGs latest PV10s, their average breakeven cost is around $54/bbl. They’ve also stated that the oil price required to generate double digit returns has come down from $83/bbl in 2014 to $55/bbl in 2018. This should continue falling as their premium drilling matures. Overall, a higher portion of premium wells drilled should lead to higher pre-tax earnings at greater capital efficiency (EBITDA/F&D costs)
Since becoming independent from Enron in 1999, average ROCE has been above 12%. They delivered 13% in 2017 and 15% in 2018.
The company has historically been run in a decentralized manner, with seven internal divisions competing for capital based on their drilling prospects’ potential returns. Typically, each division will submit a budget for its drilling plan for the year. After this, it becomes an iterative process based on cash flows and what other divisions have. Divisions operate autonomously, which forces them to optimize if they want to get any capital. Well design, completion plans, engineering, etc is driven at the direct employee level and not at the executive level.
A portion of everyone’s compensation is based on returns on capital and total shareholder returns. Employees own about 0.5% of the company. There have only been three CEOs in its history, and Bill Thomas, who succeeded Mark Papa in 2013, spent many years moving across divisions before becoming CEO: he has been with the company for more than 35 years. They believe that the organizational structure helps preserve a culture they deem unique and differentiating in the sector and it also prevents the build-up of bureaucracy and helps everyone stay focused on returns as they need to compete for capital.
Management and the board own around 3 million shares in the aggregate. This is a low figure in my view, considering the number of years some of them have been with the company. Still, compensation from the top down is roughly 30% related to ROCE. This has been the case historically, as opposed to most of their peers who have recently been under severe pressure from shareholders to shift their focus from production growth towards returns. Another 15% of compensation is linked to specific growth targets in combination with specific operating cost targets. Another 40% of compensation is partially linked to reducing finding & development costs.
Some of the things they’ve done historically can help explain the company’s culture:
They typically recruit their people when they are still in university. They’ve done this for over 17 years. It results in very low turnover and a young and engaged work force with up-to-date knowledge, eager to experiment and try new things. While this may not sound as relevant, the industry is famous for its “if it ain’t broke, don’t fix it” mentality, i.e. very conservative. That’s one of the reasons it took George Mitchell’s Mitchell Energy & Development Corp 20 years to convince large Oil Companies of the merits of fracking and also to perfect the methods by which wells could become economical when fracturing the rock with the new techniques. EOG takes pride in embracing new challenges and trying new things constantly. They test and evaluate everything they do. In their 4Q17 conference call, Billy Helms, Head of Operations, explained: “in every one of these plays, and we’ve been doing this for two decades now, we’ve learned to take a systematic approach and not really switch into what some people would call a manufacturing mode, because we want to continue to learn. And we want to continue to get better”
They opened a sand mine in Wisconsin in 2012, at the time one of the largest sand mines in the US. They were also the first to send crude by rail in 2012 from their Bakken operations, to be able to reach Gulf Coast refiners. They owned a large portion of the rail tanks, which helped them reduce freight costs, not having to pay for tank rental. They believe their sand costs are the lowest in the industry. They were 18% lower in 2017 as per IR comments.
They have historically sold a portion of their crude directly to refiners, minimizing the level of intermediation, locking-in higher netbacks. Most recently, they have signed agreements to more than double their export capacity from the Gulf Coast by 2022, from 100kbpd to 250kbpd.
A large part of their technology is developed in-house. While they use SLB, BH, HALs products, they tend not to use them for completions, for example. They have also developed more than 100 internal applications that allow any employee in the organization to follow what’s happening at each of their wells and production sites in real time and to see what the ROIC for each of the wells is based on their daily updated forecasts. They have long had a private cloud that processes data coming from black box in each well. A lot of companies now talk about big data but this has been embedded in their DNA for over 25 years. “We collect a lot of core data, and our goal with all that is to find better and better inventory than we currently have”
They have drilled more than 5,000 horizontal wells to date, 50% more than any other operator today in the US or elsewhere (small or large!). They believe this gives them a significant advantage in terms of efficiency. It is true that EOG is usually referred to as a benchmark for high quality operations, both by competitors and by analysts.
The organization is very flat; there may be three layers between the CEO and a production engineer, compared to up to 10 at other E&Ps. As an engineer you have a lot of leeway for tinkering around. Good ideas are rewarded properly, with several official compensation checkpoints throughout the year. Good performance may be rewarded via stock awards, salary increases or cash bonuses. Outstanding performance awards entail a special bonus and are also given. A team discovering a new play, for example, may get a 7 figure bonus to distribute amongst the team. Divisions present to executives 3 times a year, which ensures a lot of visibility.
They think years ahead. An example is the Powder River Basin. They’ve had acreage in the basin for over 20 years but began developing it in 2008-09. They surprised the market in 2018 when they announced the addition of 2 billion barrels of resource and 1,500 well locations as a result of their development activity in the region in early 2018. Prior to the Yates acquisition in 2016 they had 200k acres. Yates added 200k which they say was pure optionality. They turned more aggressive in evaluating the acreage after the Yates’ deal, delineating the resource and have moved to test spacing assumptions. They expect drilling, completing and infrastructure development activity to increase going forward, but volumes will come at the end of 2019. They also began planning for bottlenecks in the Permian in 2015 and 2016, which is one reason they’ve been able to realize higher netbacks than peers in the basin in the last couple of years.
The question is whether EOG’s culture is linked to performance at all. Simple answer is yes. EOGs historical finding and development costs were the lowest in the industry when it was a pure gas play before 2009. Since then, it has struggled a bit in regaining the top spot for costs amongst peers, but has made significant gains at lowering their finding and development costs over the last decade. The capital costs of developing undeveloped reserves to developed reserves are now below 2009 levels of $10.2/bbl, to $8.6/bbl. They were as high as $14.8/bbl in 2011, when services inflation plagued the industry. They have steadily come down since.
EOG wells tend to be more prolific (higher first 30 day Initial Production) than peers in the same basins, by a significant amount.
Given the fact that more than 1/3 of a shale oil well Estimated Ultimate Recovery is produced within the first two years, this is a significant advantage, as earlier cash flows have a large impact on the NPV of a well. EOG estimates that its Premium wells in the Eagle Ford, for example, generate 102 percentage points more of return than their peers in the same basin, 89pp more in the Permian, 101pp more in the Powder River Basin and 20pp more in the Bakken, using $50/bbl WTI and $3/mcf gas prices as estimates for the life of the wells, including those of their peers.
There are 580 million shares outstanding, $5.2bn of Long-term debt, $1.5bn in cash and equivalents and $1bn of retirement obligations for a Market cap of $51bn and an EV of $56.7bn today. EBIT in 2018 was $4.4bn.
They have 10,168 producing wells today (63% oil and 37% gas, for a 56% oil, 16% NGL and 28% gas production mix), which have an NPV10 as of the end of December 2018 of $32.4bn (as per the SEC standard definition, using $69/bbl WTI average prices). Since 2008, EOG has traded at an average of 3x its PV10, it’s trading at 1.8x PV10 today. That’s one very simplistic way of looking at it.
Another way to look at the valuation involves looking at their disclosed inventory of crude oil assets and build a DCF model for each of the plays, assuming full development over a reasonable period. In my case, I’ve done the exercise for the Eagle Ford, Delaware, Bakken three forks, Woodford and Powder River Basin. Using the current WTI and HH strip curve and $55/bbl as of 2024 and $2.5/mcf post 2020, I arrive at a NAV of $73bn for the whole. Deduct debt, retirement obligations, working capital and add back cash and you have the equity trading at a 32% discount to its intrinsic value today.
A third approach is looking at peers. Pioneer is a good example. They have 680,000 net acres in the Permian (Permian pure player) and produced 181kbdp of oil in the basin on average in 2018. EOG has 913,000 acres in the Permian and produced 132kbdp of oil in 2018. Pioneer’s current market cap is $24.4bn, valuing each acre at around $36k. At these levels, EOGs Permian acreage is worth around $33bn, or 65% of the current market cap. That implies a valuation of $18bn for everything else: way too low in my view. On a per-flowing oil barrel the numbers are as follows: $369 for Pioneer’s Permian production, implying an $18bn valuation for EOG’s Permian current production, which is expected to grow at double digits for years to come. That leaves $33bn for the rest: Eagle Ford, Bakken, Rockies and Woodford, which together produced 268kbdp in 2018, implying $337/flowing oil barrel.
Still, none of those approaches tell us how EOG will generate value for shareholders going forward. Significant value will come from completing wells. A mental exercise: EOG said the average well brought online in 1Q19 is expected to deliver $9 million of NPV. That’s across all basins. At $9 million/well, 740 wells in 2019 add $6.7bn of NPV, or 13% of the current market cap. Remember they have at least 13 years of Premium location inventory, 9,500 potential wells identified. They completed 490 wells in 2017 and 760 in 2018. Assume a normalized level of 500 well completions per year (in 2014 they completed 853 in total, for example), which delivers 9% annual value accretion.
The other way in which they can create value is by adding location inventory to the current existing one as it depletes. While it would take them more than 13 years to go through the 9,500 undrilled premium locations identified so far, they have added 6,300 locations in three years, 2,100/year since the premium program began. Assume $9 million per premium location for simplicity: each 1,000 Premium locations are worth ca. $9bn, or 18% of the current market cap. Given their current growth plans of 12-16% per year going forward, it seems possible for them to identify 700 new locations per year on average in the future.
Additionally, the company has paid a dividend for the last 20 years. The current dividend yield is 1%
Also, EOG has $1.8bn of state income tax Net Operating Losses being carried forward which would expire between 2019-2036 if unused. These represent 3.5% of the current market cap. In any case, it’s unlikely that EOG will pay any cash taxes as long as their capital budget is bigger than their pre-tax earnings.
In 2019, they expect to incur ca. $6.3bn in CAPEX. 30% IRRs at the well level bridge down to ca. 13-15% at the corporate when accounting for leasing expenses, infrastructure investments and because even 10 year-old oil and gas wells will still account for ca. 40% of the capital in the books, which at current commodity price levels is a drag to ROCEs. In any case, as an exercise: assume the incremental CAPEX generates a 12% return (the historical ROCE average), which results in $0.75bn of incremental EBIT.
Going back to 2006, the market has historically paid 29x EOG’s 12 month forward EBIT on average. Using this multiple implies that EOG can add $21bn of market value from its incremental EBIT. A more conservative 10x adds $7.5bn or 15% of today’s market cap.
A reasonable question to ask is whether they can do this. Historically they have been able to, and the share price performance reflects that, having compounded returns at 15% annually since 1999, a 16x on initial capital over 20 years. Having achieved this organically speaks well of the organization, the management and the culture.
Revisiting the acquisition of Yates Petroleum Corp in 2016, which came with 424,000 acres in the Delaware basin and for which they paid $2.4bn. On a per-acre basis, EOG paid $5,693/acre. They had identified 1,740 Premium Net Locations within the Yates acreage by the end of 2016. According to this figure, EOG paid $1.4 million per premium location, compared to an NPV per premium location of $9 million (as of 1Q19), a 85% discount.
From a maintenance/no-growth CAPEX perspective, what could cash flows be? Decline rates are not static so it’s hard to say exactly what maintenance CAPEX looks like, but a good proxy for a year when they didn’t invest much in terms of growth CAPEX is 2016. The figure was $2.6bn. At that rate of investment and with the premium drilling program in full motion and current commodity prices, they believe they can generate between $4.4bn and $5.5bn of Free Cash Flow. That’s a 9% - 11% FCF Yield.
The transformations EOG has gone through during its lifetime: first from a gas to crude producer and now from a high quality to a Premium producer, give me confidence to trust management as capital allocators.
To conclude, I believe EOG is trading at a significant discount to its intrinsic value and a purchase today should deliver attractive double digit returns in the next few years.
Commodity price: This is a risk that comes with the package. EOG does engage in opportunistic hedging, but they don’t have a permanent hedging program, instead, they try to mitigate commodity price risk by fostering a cost conscious culture across the organization. I’m currently less concerned with oil price risk. Natural gas prices in the US, however, are likely to remain low (lower?) for a long time. Natural gas should remain close to quarter or a third of EOGs total production going forward.
Cost inflation: Never say never, but judging from the current state of the US oil service industry, I believe it’s quite unlikely for costs to become a problem like they were in 2012. Over the past few years, EOG has tried to mitigate this risk by securing over 60% of their coming year well costs in advance. For 2019, they have secured ca. 65% of their anticipated well costs. They also self-source quite a few critical things: water, chemicals, completion design, sand, logistics, drilling fluids and gathering, which represent 25% of total well costs. Their obsession with cost reductions also helps mitigate this risk, see above for culture.
Demand for oil and gas globally. Eventually, marginal cost producers may be pushed out and only the lowest cost will survive. EOG has the lead in becoming a low cost producer, but anything that changes their current culture, objectives, operational ability, etc. can be detrimental to their ability to survive in the long term. Also, this isn’t a short term risk, in my view, consider the following: global oil (excluding NGL and gas) production has increased from 74.3 to 83 million barrels per day since 2008; of these, 5.9 million have come from the US, and around half of these from shale. If US shale is the swing producer globally (and it is expected to represent around 50% of future global production growth for the next 20+ years), your global base decline has moved from less than 5% to almost 6.5%. To offset this in the medium term the world will need a lot more than just shale production growth. I doubt global oil production is growing at 8%, not even 7%. Even in a moderating demand growth environment, it should be ok for oil prices, but yes, it’s all debatable, hence the risk.
Can they run out of premium drilling inventory? Maybe, but seems unlikely, given the rate at which they have been adding locations to it. One way the inventory can disappear is if oil prices fall below $40/bbl permanently. Again, unlikely in the near and medium term, in my view.
A bid for the company is another risk. The Oxy/Chevron bidding contest for Anadarko shows the commitment oil majors now have for a segment of the industry they actively ignored for so long. It would be a shame if that happened, though, as I don’t think the culture would survive under IOC ownership. In any case, shareholders would be deprived of a best-in-class in the sector.
 2018-02-28 (EOG) 4Q 2017 Results
 2017-02-28 (EOG) 4Q 2016 Earnings Call
 2018-02-28 (EOG) Q4 2017 Earnings Call
 2018-02-28 (EOG) Q4 2017 Earnings Call
- Higher oil/gas prices
- Further M&A in the sector