On a straight dollars-divided-by-acres basis Marathon paid close to $24,800 per acre — which struck a number of analysts as a whole heck of a lot to pay for the right to drill on a piece of South Texas land.
Including the value of the 7,000 barrels of oil equivalent already flowing from the property the price comes down to something like $21,000 per acre: more reasonable but it’s still more than the past record for the Eagle Ford — the $19,375 per acre that Korea National Oil Co. paid in March for a one-third stake in Anadarko Petroleum’s Eagle Ford assets.
It begs prompts the question, did Marathon pay too much? That’s hard to say, but they certainly aren’t going to be confused with the smart money/early movers when it comes to shales.
Small to mid-sized E&Ps were the first to catch on to the potential of shale in the last decade, taking large acreage positions in fields that had been abandoned or ignored by the oil majors as unproductive years ago.
As the trend caught fire companies started to issue debt and equity to help fuel the pace of expansion, drilling furiously to avoid losing their leases (companies typically have three years to drill a lease or they lose it).
There are a number of observers who questioned the sustainability of the shale drilling expansion, however, saying the pace of production would undermine profitability. And it did, with natural gas prices having dipped into the low $4 range for more than a year.
Companies argue they can still drill profitably in that price range as shale plays are now more like manufacturing — they know where the gas is, it’s just a matter of getting drilling rigs and hydraulic fracturing crews to run as quickly and efficiently as possible. That’s why when you see reports from companies like El Paso on their shale E&P operations there’s a lot of information about driving down per well costs (even though they don’t include the acreage costs in the calculations, a fact that some see as complete BS).
But it’s still expensive. Companies like Chesapeake Energy and Petrohawk Energy, which used the debt and equity markets raise billions to fund expansions, would be in big trouble today if they had not found an exit strategy — getting deeper pocket to buy in.
Everyone from BG to BP, Shell to Chinese giant CNOOC has spent billions to form joint ventures with the smaller players. Exxon Mobil bought XTO Energy outright to get itself in the shale game. This has led to higher and higher acreage costs as the wealthier players are desperate to get a piece of the shale action. It’s created a bubble that Wood Mackenzie analyst Neal Anderson recently told us will eventually burst.
That all leads us back to Marathon’s record-breaking expenditure.
As Marathon President and CEO Clarence Cazalot told us earlier this week, not all acreage is created equal, as there are areas of the Eagle Ford with dry gas, black oil, natural gas liquids and volatile oils that all have widely disparate economics depending on the prices for those commodities. So liquids-rich acreage should naturally fetch higher prices than dry gas acreage.
Cazalot also said a publicly traded company invested in about 5,000 undeveloped acres in the Eagle Ford at about $24,000 an acre (although we have yet to figure out who that was — any ideas?).
Analysts seem to agree Marathon needed to make a big, bold move like this to stand out as a standalone E&P company — which it will become at the end of June when Marathon’s refining business spins off to become a new publicly traded firm, Marathon Petroleum (yeah, that won’t be confusing).
“Prior to this deal, the investment case for post-split Marathon upstream was going to be a head-scratcher, other than the dreaded ‘it’s dead cheap,'” Deutsche Bank equity analysts wrote in a research note this week. “By announcing the deal pre-split and using cash on hand, the company has taken low return cash and bought higher return growth.”
But they have to execute well — get that manufacturing process to go smoothly — if they’re going to make that high price asset pay off, says Deutsche Bank.