Oil and gas operators in the Marcellus shale play need an average natural gas price of $3.84 to achieve a breakeven 10% rate of return on investment, according to Manuj Nikhanj, managing director and head of energy research for Calgary-based ITG Investment Research. Nikhanj spoke as part of a panel on Marcellus economics at Hart Energy’s 3rd annual DUG-East conference in Pittsburgh.

Additionally, wellhead production from the Marcellus is expected to top 10 billion cubic feet (Bcf) of gas per day by 2017, with an additional 42,000 barrels of natural gas liquids and condensate, he said.

That play-wide breakeven is based on a 20:1 oil-to-gas ratio and varies across the expansive play. Northeastern Pennsylvania, which is producing the most robust returns, has the lowest cost, breaking even in a sub-$3 environment. In the southwestern region of Pennsylvania, another hot spot for development, Washing-ton and Greene counties break even at prices of $3.55 and $3.93, respectively.

The economic value of the region is evident as some 153 horizontal rigs are currently seeking the Marcellus zone in the Appalachian Basin and where 3,600 permits have been issued, Nikhanj estimates.

Half of that rig activity is busy in northeastern Pennsylvania, where Chesapeake Energy Corp. is the most active operator with 27 rigs and 840 permits.

Sizeable estimated ultimate recoveries (EURs) per well are driving these favorable economics in the Marcellus, particularly in northeastern Pennsylvania. Here, operators are logging an average 9.9 Bcf EUR in Susquehanna County, and 9.8 Bcf in Wyoming County.

EURs from companies operating in these regions include Chesapeake, which tops the list at 10.3 Bcf, privately held Citrus Energy Corp. (9.8 Bcf), Cabot Oil & Gas (9.7 Bcf) and Southwestern Energy Inc. (6.7 Bcf).

Elsewhere, EURs are averaging 2.7 Bcf in southwestern Pennsylvania, 2.2 Bcf in central Pennsylvania, and an average 3.1 Bcf in West Virginia. EQT Corp. is getting the best results out of Greene County in southwestern Pennsylvania at 8.2 Bcf, EOG Resources in Clearfield County in central Pennsylvania with 3.1 Bcf wells, and Antero Resources is seeing the best results in West Virginia’s Harrison County with an average EUR of 5.9 Bcf.

ITG estimates that drilling time from spud to rig release has dropped from 30 days to 22 days in the past three years in the region, “and on the heels of operators moving to longer laterals,” but the time from spud to sales is more than six months due a backlog of completions crews and take-away capacity. Also, pad drilling with six to eight wells drilled simultaneously leads to a big inventory.

“With more than 3,200 wells that have been drilled or are currently drilling in the play, there could be 1,300 wells in the Marcellus waiting on completion and tie-in,” he said, or 5 Bcf per day of instantaneous production or 2.5 to 3.5 Bcf per day of scheduled-out production.

Operators, too, are pushing out laterals, which average 3,400 feet across the play. Susquehanna and Wyoming counties have the highest EURs of 10- and 8.3 Bcf respectively from lateral lengths of 3,100 and 2,400 feet. Compare that to Clearfield County, where the average lateral length is 4,700 feet to capture less than 3 Bcf.

“Clearly, the rock has to be worked a lot harder in that county for significantly lower recoveries,” he said.

By operator, Cabot and Citrus have average EURs of 9.7 and 8.3 Bcf, respectively, from using lateral lengths of only 2,700 and 2,400 feet, respectively. Chesapeake is drilling relatively long laterals at 4,200 feet for an average EUR of about 7.5 Bcf.

Rayola Dougher, senior economic advisor for the American Petroleum Institute, emphasized that elected officials at the national level still haven’t grasped the transformational potential that the Marcellus and other shale-gas plays can have for the U.S. in terms of jobs, revenue and economic security.

“It will transform this state and the nation,” she said.

Natural gas in total generated $5.3 billion per year in federal revenues over the past five years, creating 3 million jobs and supplying about 25% of the nation’s energy needs.

“In the next decade, we’re going to get 80% of our natural gas needs met through unconventional sources. We’re not going to be importing natural gas in the future. Imagine that future without these shale plays.”

And while drillers have angst over low natural gas prices, the vast supply of the commodity means industry that has pursued lower-cost environments overseas can now come back to the U.S.

Dougher is concerned the “green completion” rule, set to take effect February 28, is going to catch many small operators off guard. The rule directs operators to capture methane emissions from hydraulically fractured wells and sell them back into the marketplace. The Environmental Protection Agency estimates the cost at $30,000 per well, while some in the industry have projected $60,000.

Hart Energy’s chief technical director of upstream, Richard Mason, modeled the structural shift in power taking place in the Marcellus and beyond.

The Marcellus has experienced an economic influx of $16 billion in joint-venture funds flow into the region since 2006, more than twice that of any other U.S. shale play, and an additional $12.5 billion in assets and corporate M&A, again the leading region for acquisitions.

“Cash-constrained independents did a wonderful job blocking up the acreage (in the Marcellus), but when it came time to develop the acreage, they were needing to lay off some of their costs. This has forced them to either sell legacy properties or to enter JVs.”

Significantly, 45% of Marcellus transactions since 2010 are the results of international oil companies staking claims in the play.

At the beginning of 2010, 75% of wells in Appalachia were drilled by private companies and small- and mid-cap operators. Now, majors represent half of all well completions. “You can see the enormous impact the JVs and majors have had,” Mason said. “The pie is growing, but the share of that pie held by the JVs and the majors is growing as well.”

Joint-venture partnerships with the capital influx from associated drilling carries are driving current growth, said Mason, which he expects to expand into 2013 to fulfill the terms of those requirements. But a second wave of capital is coming as well.

“We have not yet seen the ramp in activity from the Chevrons, Royal Dutch Shells or from the ExxonMobils. They have not yet begun to work the way they will eventually. That’s likely to be a 2013-to-2015 story.”

For more coverage of joint ventures in shale plays, see OilandGasInvestor.com? .