While the size of the prize in the Permian Basin is now greater than ever in my lifetime, the bar is set higher than ever for those who aspire to attain the prize. I am told that the late 1950s was a great time to be in the Permian Basin, but I did not show up here until 1962, so I may have missed the best of times in the development of the largest oil basin in the country.
But there is still opportunity aplenty. And it all starts with the human capital. People are the most important ingredient for success in the revitalized Permian Basin. Yes, attracting and retaining the right team is more important than amassing capital, at least for now, in Midland/Odessa and surrounding region. For emphasis, let me restate it in slightly different terms: in the Permian Basin, money is easier to attract than people. This phenomenon could be limited to me, as I may have better relationships with capital providers than with engineers, geologists, and landmen, but I don’t think so. I’m more inclined to believe that my experiences mirror every other E&P company. Capital is in great supply, and qualified individuals are not. Be that as it may, my point here is not to examine our 3 percent unemployment and our incessant competition for competent employees. My subject, instead, is the availability of capital for upstream investment and the size of capital investment required to sustain current activity levels.
Let’s consider, first, the supply side of the capital equation. Financial institutions, including pensions, endowments, and family offices of the wealthy, thirst for exposure to oil and gas. Due to the stellar success of upstream-focused private equity firms since the 1990s, there has been a ballooning of these funds under management. The rising commodity price environment has provided a tail wind for their investing success, with the exception of the collapse in gas prices in 2009 following its run-up in the years prior. To the surprise of all of us, NYMEX oil prices are clinging to the $100 mark, though wellhead prices remain more volatile thanks to infrastructure constraints. The challenge upstream private equity firms face is generating above-market returns (>20% IRR) in a flat price environment. As we read in mutual fund prospectuses, “past performance is no guarantee or predictor of future returns.” It is true in our business, yet the most sophisticated portfolio managers invest based on the historical track record of money managers—in other words, on “past performance.”
I digress, but I’m reminded of the experiences of legendary investors Peter Lynch and Bill Gross. It was Lynch who managed Fidelity Magellan’s stock mutual fund, once the largest, while Gross manages one of the largest bond fund portfolios in the world at PIMCO. Both funds became so large they couldn’t beat the broad market averages, especially after fees were deducted. Fidelity had to close Magellan to new investors because it got so large due to the appeal of its outsized returns. Magellan’s growth in assets was Lynch’s downfall, as his stock returns regressed to the mean as Magellan resembled the broad stock market. Likewise, PIMCO, managed by the smartest investor in the fixed income world, Bill Gross, has around $500 billion of fixed income assets under management. With PIMCO’s breathtaking growth, its larger bond fund returns have recently fallen below market averages. We fickle investors have pulled our money from Magellan and PIMCO and moved on to greener pastures as the returns in our standbys have fallen behind the pack.
I predict the same may occur in energy-focused private equity. When I joined First Reserve in 1995, our funds were in the $100-250 million range. In 1998, First Reserve raised an $800 million fund, led by the energy services investing prowess of Bill Macaulay, who has co-owned and run First Reserve since 1983. Fast forward to 2009, at the height (or bottom, depending on your perspective) of the financial crisis, First Reserve closed a $9 billion fund. Quantum Energy Partners, for whom I worked in 2004-2005 during the formation of Legacy Reserves LP, started humbly enough with a $125 million Fund seeded by legendary oilman and gentleman A.V. Jones of Albany, Texas, in 1998, which was another bottom in oil prices and a great time to invest. Roll forward to 2013, and Quantum closed Fund VII at the $4 billion mark.
We all know that a dollar today is less valuable than a dollar in 1998, when oil prices reached below $10 per barrel at the wellhead. For simple math, let’s say oil averaged $20 per barrel in the late ‘90s when energy PE funds averaged $150 million in size. Oil prices are almost $100 per barrel now, a five-fold increase. The most recent PE funds now average $4 billion (EnCap – $5.6B, Quantum- $4B, NGP-$3.4B, Pine Brook-$2.5B). The average fund size is up 27 times over the same period that oil prices have risen five-fold. This does not factor in the expansion in the number of funds and the fact that big buyout funds including Apollo (Athlon, EP Energy), and KKR (Samson) are direct investors in the oil and gas business. Add the Asian investors and national companies (Sinopec, Sumitomo, Sinochem, Samsung) who have partnered with the likes of Chesapeake, Devon, Pioneer, and Parallel, respectively, and we are awash in capital targeted at the upstream business in the United States.
The other side of the scale is the rising cost of doing business and rising activity levels. Most of us can remember drilling San Andres wells for around $250,000 in the late 1990s. Let’s be fair and pick a vertical well of equivalent depth, say a Spraberry well, that in the late 1990s might have cost $450,000 and IP’d for 30-40 barrels of oil per day (Bopd). Roll forward to 2006, when we started drilling and multi-stage hydraulically fracturing Wolfberry wells at Legacy Reserves and spent $1.4 million per copy. By 2008, that same well cost $2.2 million thanks to high oil and gas prices driving the rig count across the nation in the Bakken, Barnett, Fayetteville, Haynesville, and Marcellus shale plays. By 2010, that same Wolfberry well drilled to 10,500’ costs $1.8 million and, if you are lucky, produces 100 Bopd over its first 30 days.
Most of us don’t need a lot of external capital to drill Wolfberry wells. We certainly don’t need the billions that the big New York buyout firms or the Asian partners offer to drill vertical wells. The unconventional resource play has raised the cost of poker (cost to drill and complete a well) to $6 million in the southern Midland Basin for a 1.5-mile lateral (horizontal section), and $12 million for a 2-mile lateral in the Bone Spring sands in the northern Delaware Basin. A one-mile lateral in the southern Delaware Basin (11,000’ true vertical depth, so a three-mile long hole) costs $8 million if everything goes right, which rarely happens. So applying complex algorithms, we now have an 18-fold increase in the most popular well drilling in the Permian Basin in the 1990s and now: Spraberry well costing $450,000, and $8 million for a 3-mile-long (2 miles down, one mile lateral) horizontal Wolfcamp well in the Delaware Basin.
Let’s not forget that more than 60 percent of the rigs operating in the Permian Basin are drilling horizontal wells, while as recently as 2011, only 12 percent of the Permian rigs were horizontal. Assuming 45 days per horizontal well and 15 days per vertical well (both include completion time), we can drill 2,500 horizontal wells in a year with 310 active rigs and about 5,000 vertical wells with 208 rigs. This translates to spending $20 billion on horizontal wells and $6 billion on vertical wells, assuming an average of $1.2 million per vertical well to account for shallower San Andres and Clearfork wells. This adds up to $26 billion of annual drilling and completion expenditures, and more for production and disposal facilities, and gathering lines, so gross it up to $30 billion per year of upstream capital expenditures at our current rig count. Compare that to equally rough math of 120 rigs running on average in the Permian in the late 1990s (assume 24 wells per rig per year, so 3,000 wells, or one-third of what was drilled in Texas in that time frame) with an average cost of $500,000 would be $1.5 billion, grossed up to $1.8 billion including associated facilities. All of this would be much clearer in Excel, but even if you nitpick my assumptions, we are going to need a whole lot of capital to execute the horizontal development of unconventional resources in the Permian Basin. Less than $2 billion per year of expenditures in the late 1990s have morphed to over $30 billion per year of upstream investment in the Permian Basin.
You can now better understand why our traffic is so bad, roads torn up, schools overcrowded, housing scarce and expensive, and unemployment below 3 percent. If you’ve flown on an airline into Midland recently, you’ve seen about one-half of the plane occupied by oil field workers, many wearing hardhats. I speculate that we import at least 20,000 workers from out of town from as far away as Canada and Vermont to keep our rigs running, frac jobs pumping, and oil hauling (our tanks are brimming with oil). Let’s also remember the jobs created by oil and gas gathering, processing, and transportation investments.
So is there too much capital chasing too few good drilling opportunities in the Permian Basin? I don’t think so, at least not until the majors start spending billions here like the large independents—including Apache, Concho, Devon, Oxy, and Pioneer. Chevron is the largest private mineral owner and leaseholder in the Permian, Oxy is the king of enhanced oil recovery and is getting active in the Wolfcamp and Cline plays, and Exxon has XTO gearing up in horizontal drilling. Shell bought Chesapeake’s position in the southern Delaware Basin for $1.9 billion in 2012 and is assessing its horizontal strategy. On the large independent front, Pioneer is the king of the Spraberry and positioned to be huge in the horizontal Wolfcamp play in the Midland Basin. Concho is the king of the Delaware Basin due to its foresight in acquiring MarBob and Mack Chase before the horizontal revolution. Cimarex is betting its company on horizontal drilling in the Delaware Basin. Apache is all over the Permian and would like to spend $3 billion per year drilling wells here. We cannot ignore nimble independents like Diamondback and Laredo who are practically all horizontal now in the Midland Basin and creating large companies in a limited amount of time. Keep the private capital flowing to the second tier of scrappy, under-the-radar independents like us and perhaps one day we’ll go public or sell to one of the great companies I listed above. No, there is not too much private capital coming to the Permian Basin, and yes, there are not enough good people to help us put it to work effectively.