Oil and gas operators in the Marcellus shale play need a $3.84 per thousand cubic feet gas price, on average, to achieve a breakeven10% 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 Developing Unconventional Gas–East conference in Pittsburgh, which attracted more than 3,000 industry professionals.

Additionally, well-head production from the Marcellus is expected to top 10 Bcf of gas per day by 2017, with an additional 42,000 barrels of natural gas liquids and condensate, he projects.

That play-wide breakeven is based on a 20-to-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, Washington and Greene counties break even at $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 LP 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 takeaway capacity, said Nikhanj. 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 or 2.5- to 3.5 Bcf per day of scheduled-out production.

Operators are pushing out laterals, which average 3,400 feet across the play. Susquehanna and Wyoming counties have the highest EURs of 10 Bcf 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 Bcf 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.

Some operators, however, may be leaving potential on the table, said Nikhanj, noting "it appears tighter frac spacing may be a source of future improvement for operators still using 350 to 450 feet between stages. Going to tighter frac spacing between stages incrementally improves results quite dramatically." Cabot, as example, spaces stages at 250 feet apart, and capture the same EURs with shorter laterals.

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 gas shale 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 generates some $5.3 billion per year in federal revenues over the past five years, creating 3 million jobs and supplying 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.

Shale gas production has increased 400% since 2006, she said, but while shale plays are "exceeding expectations in a spectacular way," environmental rules and regulations remain an uncertainty facing the industry. To measure the economic impact of such potential regulations, the API commissioned IHS Global Insight to project the economic cost of existing proposed regulations.

Underground injection control compliance would result in a 10% production loss, about 635,000 lost jobs, and $84 billion in lost GDP. Fluid restrictions could have an even bigger impact, with a 22% drop in production, 1.3 million lost jobs and a $172-billion negative hit on GDP.

A ban on hydraulic fracturing would be the most economically debilitating. Production would take a 45% hit, 2.8 million jobs would disappear and the treasury would lose $374 billion in potential revenues. "We're looking for policies to regulate shale resources primarily at the state level. We think the states are the best to regulate the industry," she said.

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 EPA estimates the cost at $30,000 per well, while some in the industry have projected $60,000.

"We're concerned that not every driller even knows that it is out there. It will be a challenge to do this in a short amount of time, and we’re recommending that they phase this in."

As the Marcellus rapidly develops, Dougher urged that good stewardship is critical. "A lot of questions have to be answered. We can't have this (perceived as) not safe and not environmentally responsible."

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 flowing 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 mergers and acquisitions (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 needed to lay off some of their costs. This has forced them to either sell legacy properties or to enter joint ventures," he said.

Significantly, 45% of Marcellus transactions since 2010 are the results of international major oil companies staking claims in the play. At the beginning of 2010, 75% of wells drilled in Appalachia were private companies and small- and mid-cap operators. Now, majors represent half of all well completions.

"You can see the enormous impact the joint ventures and majors have had," Mason said. "The pie is growing, but the share of that pie held by the joint ventures and the majors is growing as well."

Joint ventures 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, he projects.

"We have not yet seen the ramp in activity from the Chevrons, Royal Dutch Shells or from the ExxonMobils. The major ramp-up is going to reach the equivalent market share with what we see with JVs. "They have not yet begun to work the way they will eventually. That's likely to be a 2013 to 2015 story."

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