Wednesday, August 15, 2012

Marcellus America’s No. 1 play. So what does that mean? Daily production records relevant, but so are other factors

Recent data show Marcellus daily production soaring, with gas coming online faster than markets can absorb it. As the AP’s Kevin Begos reports, the combined output from Pennsylvania and West Virginia wells in July was about 7.4 billion cubic feet per day. That’s grown from 3.6 billion feet in April, 2011, and from 4.6 billion feet in August of last year. In his August 5 story, Begos cites Bentek Energy analyst Kyle Martinez as a source of this information. (In search for access to the data, I spoke with Kyle Tuesday and learned that he calculates projections from raw metering data. The U.S. Energy Information Association, which uses Bentek data, has yet to compile an online summary of Bentek’s most current assessment, but it does have a summary to data from August 2011 that supports the trend, which can be found here.)

With this kind of output, as Begos points out, the Marcellus is poised to surpass the daily production of the Haynesville formation, straddling parts of Louisiana, Texas and Arkansas, to become the top producing gas field in the country. Now questions are less about the production capability of the Marcellus (at least over the short term) and more about where all this gas coming on line will go. Will a nationwide glut keep prices suppressed to the point where extraction loses its economic luster or even drive operators to a fiscal breaking point? Or will market forces divert the flow of this domestic bounty to places like Europe and Japan, where gas prices are four times greater than they are in the U.S.? Or will domestic markets begin to open with projects such as a petrochemical plant proposed by Shell Oil in southwestern Pennsylvania, conversion of coal fired power plants nationwide, or natural gas powered vehicles? The daily production numbers that provide the hook to Begos story also represent a compelling gauge of Marcellus prospects for investors. They provide a snapshot that supports a broader sense that the play has been proven. But there is far more to it than that, in the Marcellus region and in other shale gas regions nationwide and globally.

Surging Marcellus production is partly a function of the number of wells drilled, and in this regard its geography is as important as its geology. The location of the Marcellus in proximity to the world’s largest markets in the mid Atlantic and northeast is a factor that cannot be overstated in accounting for its popularity. Compared to gas plays such as the Haynesville in the Gulf, the much lower cost of getting Marcellus gas to market provides a major incentive to drill. That’s the way it stands now, anyway. But day-to-day figures can change dramatically with market dynamics over the course of years; and keep in mind that it will takes decades for the Marcellus, or any other shale play, to reach maturity. (Considering something the EIS calls “proved reserves” the Haynesville versus the Marcellus equation looks very different. In 2010 the Haynesville was credited with more than 24 billion cubic feet of “proven” reserves, compared to 13 billion of the Marcellus. It will be interesting to see the 2011 figures when they are available. See table three in this EIA report U.S. Crude Oil, Natural Gas, and NG Liquids Proved Reserves.)

Judging the amount of gas coming from the ground is one thing, judging it’s worth is another. Projecting the future of a given shale play is far trickier than evaluating its past, because it involves reading the push and pull of present and future market dynamics. Bit there are some very big telltale signs that are worth watching closely, and they involve the tens of billions of investor money big energy companies are committing to projects to develop natural gas markets both domestically and overseas.

Sempra Energy officials have announced a $6 billion liquefied natural gas export terminal at the company’s existing import terminal at Hackberry in southwestern Louisiana. Meanwhile, two multi-billion export projects are on the drawing board in Los Angeles California: Cheniere Energy Partners has secured $5.4 billion to begin modifying its import terminal at Sabine Pass in Cameron Parish for exports; and Energy Transfer Equity LP is planning an export facility at its import terminal at Lake Charles, La. These plants which now sever as import terminals will chill natural gas into a liquid that can be shipped on tankers. As these plans take shape, you may see market incentives to develop shale gas plays closer to the Gulf and Pacific Coasts, which may turn the tables on the geographical advantages the Marcellus now holds. These projects may also face significant long-term political opposition. Exporting has significant drawbacks by saddling areas with the problems associated with extraction without related economic gains. (This is known in economic parlance as “the resource curse,” referring to the paradox of regions or countries with poor economies based on the export of an abundance of non-renewable resources such as minerals and fuels.)

There are also plans to capitalize on the market glut from the Marcellus in the Mid-Atlantic states. One high profile project is a $4 billion petrochemical plant by Shell Oil Co. in southwestern Pennsylvania. The plant, proposed for Beaver County, would use shale gas as both fuel and feedstock for products at the core of the U.S. consumer economy, including fertilizer, textiles, packaging material, and plastics of all sizes and shapes. Economically, this is a good alternative to exporting resources, but there are questions about the size of the public tax subsidy Shell is demanding (now at $1.65 billion) and the degree to which the petrochemical plant will spur growth of other regional business.

Development of both the Shell plant in Pennsylvania, and gas export facilities in the Gulf and the Pacific Coast are still years away. But the fact they are being embraced by capital forces with wherewithal to summon the kind of investment to influence global markets is something to be taken into consideration. While many people are eager to assess the industry based on production figures and policy debates unfolding on a daily basis, it’s important to consider this long-term picture. Big Energy has always adapted to volatile market forces while controlling markets and investment over the course of decades. But there is a factor that they have little control over. In the case of the on-shore drilling boom – enabled by the recent technological marriage of fracking and horizontal drilling – future projections are dependent on a key unknown: How long will each shale gas reserve produce?

While daily production may be booming one year, it can taper dramatically in subsequent years, especially with shale gas wells. The rate at which a given well produces gas over time – both actual and projected -- is called a decline curve. Decline curves attempt to relate initial production rates (IP) with long-term production and ultimately recoverable reserves (URR). Decline curves help operators determine what they can expect out of the well over decades, and calculate things such as the amount of re-fracking and related expenses a given well will require to keep it flowing. Interpretations and analyses of decline curve projections for shale gas vary greatly. (For more on the problems associated with projecting decline curves, check out Greg McFarland’s "Shale Economics, Watch the Curve," or Mike Markes’ “Does I.P. Mean Investor Problems?” Both evaluations are in the Oil & Gas Evaluation Report.)

Perhaps one of the greatest examples of the uncertainty of this kind of analysis is the discrepancy between figures provided by the most trusted industry sources to answer a question that is the starting point of all long-term projections: How much recoverable gas is in the Marcellus Shale? As recently as 2010, the U.S. Energy Department estimated the Marcellus held 410 trillion cubic feet of recoverable gas – a projection based in part of the work of Terry Engelder, a Penn State Geologist who became famous for his study of the Marcellus. In August of last year, the federal government cut its estimate of undiscovered Marcellus Shale natural gas by as much as 80 percent after an updated assessment by the United States Geological Survey. Prior to Engelder’s work, the USGS estimated the Marcellus contained only 2 trillion cubic feet. Subsequently, the USGS had revised its estimate to 84 trillion cubic feet – far more than the its original estimate, but far less than Engelder’s calculation, which was close to 500 trillion cubic feet.

While the uncertainty caused by differences between these projections is a lot, it’s nothing compared to the noise in the system introduced by commercially and politically derived hype. A recent notable example is Ohio Gov. John Kasich's claim that a single energy company could recover $1 trillion worth of oil and gas from the state's (largely unexplored) Utica shale reserve. AP’s Julie Carr-Smyth put this outsized claim into perspective: At current oil prices, that figure represents more than four times U.S. oil production last year. Viewed another way, every drop of oil produced in America for the next four years will be worth roughly $800 billion, based on current prices and production rates. (Arthur Berman, a Texas-based petroleum geologist and independent energy consultant, told Smyth "My best estimate is he’s probably wrong by a couple of zeroes.")

How long will shale gas be viable and what will be the cost of future extraction when factoring in social and environmental factors? That sort of question is keeping more than a few policy makers and politicians very busy. It’s a question that extends beyond daily production values. Ultimately, the answer will determine the legacy for the next generation.


  1. Interestingly, estimates of how much gas the Marcellus Shale might yield are seldom accompanied by estimates of how many wells would be needed to produce the predicted amount of gas.

    In his 2009 article "Marcellus 2008: Report card on the breakout year for gas production in the Appalachian Basin," published in the Aug. 2009 issue of Fort Worth Basin Oil and Gas Magazine (see reference #155 at, Dr. Terry Engelder uses a model that assumes that 70% of the 73,333 "sections" (I believe a "section" is a square mile--i.e. 640 acres) in 117 counties would be drilled with 80-acre spacing (i.e. 8 wells per square mile). That's a lot of gas wells.

    Or, consider the figures given in the economic assessment portion of the most recent draft of the NYS DEC's SGEIS on shale gas. That document assumes that in an "average" development scenario, 21,067 gas wells would be drilled in "Region A" of NY state, which consists of Broome, Chemung, and Tioga Counties. That works out to about 13 gas wells per square mile, or about 1 gas well for every 16 residents of the area! It is not possible to drill at that density without creating profound negative effects on the landscape and the communities involved. Drilling at this density would also require a very, very large financial investment. It's little wonder that the gas industry seldom provides estimates of how many wells would be needed to fulfill their high-end extraction estimates.

  2. Mary, thanks for this analysis. I have also added a link to Engelder's report you cite here in my above post. Also, it's worth mentioning that the Nature Conservancy used SGEIS and industry data and found a similar well development scenario to the one you present here. That report, An Assessment of the Potential Impacts of High Volume Hydraulic Fracturing (HVHF) on Forest Resources, can be found at

  3. If production is more than half of last year, where is all this gas being stored , since there has already been a glut for a good while?
    and if they are producing so much more, is that being reflected in the royalty checks for landowners?