Setting the Bar

It’s the New Year, a time for a fresh start. If you’re an E&P company, you may be looking for peer data by basin to use in assessing the competition. If you’re an investor, you may be wrestling with the size of the resource base the industry is building, and trying to pin down the cost level at which the supply can be brought to market.

Using data from thousands of wells, spread across hundreds of counties throughout 37 plays in the Lower 48 states, a recent research report from ITG Investment Research provides answers to these and a host of other questions.

For example: What are the economic breakeven prices for basins, assuming a pre-tax 10% rate of return requirement and a 25:1 gas-to-oil ratio? And how much total resource is recoverable if one assumes a price deck held constant at $4 per thousand cubic feet (Mcf), or $100 per barrel, again assuming a 25:1 gas-to-oil ratio?

ITG IR sets the stage with an analysis of wells drilled from 2010 to 2012, showing an average supply cost, or breakeven, weighted by reserves, of $4.32 per Mcf, for all 37 plays studied in the Lower 48 states. Within the average, of course, there is plenty of variation by well type (e.g., liquids content), both between plays as well as within individual plays.

Breakeven for incremental new gas is currently $3.70 per thousand cubic feet, down from $4.30.

Not surprisingly, oil-weighted plays (65%- plus wellhead liquids) occupy the lower end of the cost curve, showing an average supply cost, or breakeven, of $2.53 per Mcf, equivalent to $63.25 per barrel. Gassier plays (from zero to 20% wellhead liquids) come in at a supply cost of $4.59 per Mcf, while liquids-rich plays (between 20% and 65% wellhead liquids) break even at $3.40.

The standout on the gas side is the Marcellus shale in the Appalachian Basin, with a breakeven price of $3.81 per Mcf, making it the lowest-cost gas play and the only dry-gas play with a sub-$4 threshold. The report highlights the Marcellus as the basin with the largest remaining recoverable resource, exceeding levels in the Eagle Ford and Bakken shales.

On the oil side, the Bakken, Eagle Ford and Permian Basin—tipped as the big three drivers of U.S. oil growth, with ITG IR expecting each to contribute more than 1.5 million barrels per day by 2025—are among the lower-supply-cost basins. The Bakken breaks even at $2.51 per Mcf, or $62.75 per barrel, with the Eagle Ford just a dime higher at $2.61, or $65.25 per barrel. Various Permian plays, both vertical and horizontal, stand out as having similar or even lower supply-cost characteristics.

A tad higher in terms of supply costs—and just besting the $2.70 per Mcf, or $67.50 per barrel, mark—are the horizontal Niobrara play in the D-J (Wattenberg) Basin and the Uinta vertical play, which break even at $2.68, or $67

per barrel, and $2.65, or $66.25, respectively. The Marmaton in the Anadarko Basin comes in a little lower, breaking even at $2.49, or $62.25 per barrel. ITG IR notes the Anadarko Basin is among the most sensitive to natural gas liquids (NGL) prices.

The Eagle Ford provides a prime example of how supply costs can vary within a play.

The report separates the Eagle Ford into eight fairways, made up of four windows (dry gas, wet gas, gas condensate, and oil), each having an east and west side. The east gas-condensate, east oil, and west gas-condensate windows have supply costs of, respectively, $44, $50 and $55 per barrel. Individually, these would rank ahead of supply costs in, say, the Bakken, at $62.75 per barrel.

Oil-weighted plays occupy the lower end of the cost curve.

However, neither of the dry-gas fairways breaks even until gas prices are well above $4 per Mcf, or $100 per barrel. As a result, the dry-gas components mask the competitiveness of the oil-weighted and liquids-rich plays by raising the average supply cost for the Eagle Ford as a whole.

Thus, breakeven for the Eagle Ford, at the earlier cited level of $2.61 per Mcf, or $65.25 per barrel, is shown to be marginally higher than for the Bakken, for example, even though much of the Eagle Ford is similarly or markedly more competitive. These calculations are based on results for wells drilled from 2010 to 2012.

What do recent trends tell us?

As we all know, the industry has been drilling fewer dry-gas wells, as the focus has turned to drilling more liquids-rich targets using horizontal rigs. In its model, ITG IR assumes that wet-gas volumes trend higher, contributing 1.2 billion cubic feet per day of monthly gas additions, while dry-gas plays are still expected to add 900 million cubic feet per day on a monthly basis. (Providing an offset are base annual decline rates for natural gas that have averaged 25% for the past several years, according to the report.)

As a result, ITG IR projects a significant drop in the breakeven cost for incremental new gas volumes, reflecting the migration away from drilling in higher-cost gas plays, such as the Haynesville and Barnett shales, and toward the liquids-rich plays in the Eagle Ford, Permian and Anadarko basins. In addition, a greater percentage of the dry gas is expected to come from the low-cost Marcellus.

How much have breakeven costs come down? From a level of $4.30 per Mcf in 2011, using combined new production additions by play, the weighted average breakeven is currently at $3.70, according to the report, which was released in fourth-quarter 2012. Further declines are expected, to $3.65 and, longer term, $3.63.

With breakeven levels improving, what is the competitive outlook, given the magnitude of the resource base that the industry is developing?

The report, says co-author Ryan Horvat, was in part a response to “a lot of our client base asking us how much resource base is remaining? And at what cost does this supply of resources come on?” For example, “If gas stayed at $4 per Mcf and oil at $100 per barrel forever, how much resource is there available?”

To answer these questions, the analysts studied thousands of wells, sorted by individual counties within individual plays. They used more than 140 type curves for the 37 plays.

“We can estimate how much resource is within a county by estimating how much of that county falls within a given play,” Horvat says. “We risk a county’s acreage, and we make a spacing assumption in terms of how many wells you can drill within a 640-acre section.

And that’s how we estimate how much resource is in a given county within a given play.”

About 600 trillion cubic feet equivalent is recoverable at $4 per thousand cubic feet equivalent, or $100 per barrel, and below.

The result? “We estimate that there is about 600 trillion cubic feet equivalent (Tcfe) that is recoverable at $4 per Mcf, or $100 per barrel, and below,” Horvat says, again assuming 25:1 gas-to-oil ratio and a pre-tax 10% rate of return requirement.

This is illustrated in the graphic shown above, in which breakeven levels of resources by play and county are represented by the curve of the shaded area, arranged from the lowest supply cost, at left, to the highest cost, at right. Roughly midway across the graphic, the curve begins to intersect the $4 Nymex breakeven level (left axis). At a $4 breakeven, the cumulative total resources (Tcfe) (6:1) line, which aggregates resources at various breakeven points, aligns with approximately 600 Tcfe (right axis).

If cost were not an issue, ITG IR estimates the remaining unrisked resource would total over 1 quadrillion cubic feet, with 680 Tcfe coming from gassier counties, 210 Tcfe from liquids-rich counties and 30 billion barrels/180 Tcfe from oil-weighted counties.

At 330 Tcfe, the Marcellus “dwarfs” any other resource, with the next highest resources forecast held by the Eagle Ford, at 152 Tcfe/25 billion barrels, and the Bakken, at 72 Tcfe/12 billion barrels.

In comparing its estimates of recoverable resources with those published by the Energy Information Administration (EIA), where an apple-to-apple comparison of 10 plays is possible, ITG IR says it believes that the EIA’s estimates are “grossly understated” and are likely to be revised higher in future studies.

ITG IR notes, for example, that its estimates of recoverable resources are double to triple those of the EIA for the Marcellus, Eagle Ford and Bakken. In total, ITG IR’s estimates of recoverable resources from these 10 plays amount to 900 Tcfe as compared to the EIA’s 426 Tcfe.

Oil resource development has the fastest trajectory, of course. ITG IR projects that total Lower 48 oil production will reach 10 million barrels per day by 2025. The Bakken, Eagle Ford and Permian are the Big Three drivers of growth, with each expected to contribute more than 1.5 million barrels per day by 2025. The current weighted average breakeven of the three plays is $65 per barrel.