Last Thursday, officials at the Texas Bureau of Economic Geology released highlights of its two-year study of the Barnett Shale field. This is ground zero for the American shale revolution since it is where George Mitchell and his engineers tested the thesis that by drilling horizontal wells and applying substantial hydraulic pressure on the rock the natural gas known to be trapped in the Barnett shale formation would be able to be produced. Through trial and error and with the assistance of research help the federal government, designed to devise methods for extracting gas from coal seams, Mitchell Energy was able to begin meaningful natural gas production from the Barnett Shale in the late 1990s.

The Barnett Shale in North Central Texas is an important field for the state and the nation's second largest shale gas field. The history of the field's production and the financial performance of operators in the field have played a significant role in fueling the debate over the viability of the shale revolution. For the past 4-5 years there has been a vigorous debate underway about the volume of shale gas resources in the U.S. and elsewhere, and the amount of production that can be extracted from these formations economically. This latter consideration played a part in the debate over the financial performance of operators who have staked their future on the shale revolution. So will this exhaustive study of the Barnett Shale end the debate, or merely provide fuel to continue it?

The Bureau of Economic Geology was selected to conduct the study, which was funded by the nonpartisan Alfred P. Sloan Foundation. Care was taken to make sure that the study was conducted without undue influence from oil and gas industry interests in an attempt to arrest the typical bickering over possible ties any researchers have to industry or environmental interests that might be construed as undercutting the researchers' independence.

The study involved a well-by-well analysis of the production from more than 16,000 wells in the Barnett field based on a decline basis and determining each individual well's estimated ultimate recovery (EUR). The Department of Petroleum Geosystems and Engineering at the University of Texas helped develop a physics-based decline curve that related time to the rate of well production that closely modeled the output of Barnett wells. The well analysis decline curve accounts for production impacts due to interfracture interference late in a well's life, which was defined as after year five. The field was mapped and divided into 10 productivity tiers enabling increased granularity of the analysis for the reserves and economics of wells. Average well economics in each of the 10 productivity tiers were analyzed including how gas plant liquids impact well economics.

The study concludes that there is 86 trillion cubic feet (Tcf) of technically recoverable free gas in the 8,000 square miles of the field analyzed. As of 2010, the field had produced over 12 Tcf of gas and there was 7 Tcf of gas reserves proven. Of the remaining 67 Tcf of gas remaining, 45 Tcf is located in drilled blocks consisting of 4,172 square miles of the field and 22 Tcf in undrilled blocks. The 45 Tcf in drilled blocks exceeds the estimates of 23.81 Tcf by the Energy Information Administration (EIA) of 4,000 miles of active area prepared in July 2011. The 67 Tcf of technically recoverable gas over 8,000 square miles exceeds the EIA estimate for the full Barnett field of 43.37 Tcf, which covered 6,500 square miles. The U.S, Geological Survey estimated 26 Tcf of reserves for the Barnett field in their 2003 assessment that covered 5,000 square miles.

The base case model developed for the study used a $4 per thousand cubic feet (Mcf) of gas price and concluded the field will produce approximately 44 Tcf of gas through 2050 based on wells already drilled and the estimated wells still to be drilled. The econometric model allowed for variations in the price of gas, the volume of gas drained by each well, the economic limit of every well, advances in technology, gas plant incentives and other factors that would impact how much gas can be extracted economically. The model called for a peak in gas production at 2 Tcf a year, which would reflect a plateau and then begin to decline to 900 billion cubic feet (Bcf) by 2030. The history of the field's production since the end of 2010, the final year of the study, shows that Barnett production peaked at 2 Tcf in 2012.

The model assumes that about 13,000 wells still needed to be drilled by 2030. In 2011 and 2012, a total of 2,900 wells were drilled in the field, which is about on track for the forecasted well forecast. Therefore, about 10,000 wells remain to be drilled.

So what about the gas shale debate? The headline for the story in The Wall Street Journal read, "Gas Boom Projected to Grow for Years." That headline sums up the bullish case that there are plenty of natural gas resources in the United States and that they can be produced for years into the future. This thesis suggests that the shift underway in how our electricity is generated – away from coal and to natural gas – will continue. It also argues that exporting natural gas in the form of liquefied natural gas (LNG) should be allowed as concluded by an earlier study of LNG exports on domestic gas prices prepared for the EIA. Implicit in these conclusions is the belief that natural gas prices will remain low for the foreseeable future, as exemplified by the use of a $4/Mcf gas price in the economic model and allowing for future price volatility, meaning both higher and lower gas prices.

It is the gas price conclusion that becomes the core of the debate over shale. Natural gas prices have fallen from over $13/Mcf in 2008 to $3.43 now, or over a 70% decline. An interview with Scott Tinker, Director of the Bureau of Economic Geology and the Principal Investigator of the Barnett Shale study, in an article earlier in February in the Ft. Worth Star-Telegram reporting on preliminary results of the study said the average well had a EUR of 1.44 Bcf of gas, but he acknowledged that there was a wide disparity in the performance of wells in the field. That confirms that shale formations do have "sweet" spots in which production is much greater and total resources are large, contributing to low well costs and positive financial returns. Mr. Tinker went on in his interview to suggest that there were still many well locations in the richer areas of the Barnett Shale formation, but he also acknowledged that there were many wells with very poor returns. The report's average well EUR estimate is below the estimate claimed by numerous operators in the field, suggesting poor financial returns for the field.

A critic of the gas shale boom, geologic consultant Art Berman, was quoted in The Wall Street Journal article as asking "why didn't they identify the sweet spots initially, before spending $40 billion on land and wells?" This financial question is the core issue currently reshaping the shale revolution. The revolution began with a small independent oil and gas company, Mitchell Energy. Its success in cracking the code of the Barnett Shale led to its acquisition by Devon Energy

, a rapidly expanding independent that was seeking new exploration opportunities. As the shale boom mushroomed beyond the Barnett to the Haynesville in East Texas and Louisiana, the Fayetteville in Arkansas and finally the Marcellus formation of Appalachia encompassing Pennsylvania, New York, West Virginia and Ohio, aggressive independent operators, including newly formed companies backed by private equity funds, were leading the parade. The high initial production of newly drilled wells in these fields excited investors who were willing to provide tons of capital to these small companies (the per share leverage for small capitalization companies was huge). A land rush began with operators paying large lease bonuses and high royalty rates to secure wide swaths of acreage in these shale plays. Remember, the shales are blanket formations so it was thought that the amount of acreage leased was the most important consideration. The operators also agreed to aggressive drilling commitments, which further cranked up the euphoria surrounding the shale boom.

As production from gas shale fields began to climb, natural gas prices began to slump – partially due to the impact of the financial crisis and the resulting recession but also do to the impact of associated natural gas being produced from crude oil wells in shale formations such as the Eagle Ford in South Texas and the Bakken in North Dakota. However, early shale well results began to reveal that shale formations were not evenly distributed throughout a basin. Some areas proved much more prolific than others, something more similar to conventional reserves. Even before natural gas futures prices fell below $2/Mcf in April of last year, the variable production of wells led to the economics of shale wells being questioned by some analysts and investors. Some producers resorted to distorted analyses of their well economics by eliminating the investment in leases, geological and geophysical analysis and overhead when determining the returns from their shale wells.

The larger, aggressive independents moved earlier before gas prices fell to the $2/Mcf level to secure stable sources of capital in the form of joint ventures with major integrated oil companies seeking reserves, production and technological knowledge, and national oil companies seeking financial returns and shale intelligence. Some of the small, aggressive operators elected to sell out to these larger oil and gas companies. With gas prices at distressingly low prices, companies of all sizes began sorting out their asset bases and selling less desirables properties. Today, we are in the midst of a major restructuring of the domestic E&P industry as shale technology leaders, but saddled with a high cost of capital and large debt burdens are being absorbed by larger oil and gas companies with low costs of capital, large research and development budgets to fund further improvements in drilling and extraction technology and the financial staying power to withstand the time until natural gas prices rise to support the shale gas economics.

While we haven't seen the Barnett Shale study (its results are being presented in five papers submitted for peer review), we doubt it will end the debate over the shale revolution and its future. In fact, we suspect the report may actually heighten the debate as it points out the economics of shale gas, especially because a new model for forecasting well EURs has been developed, pointing out that shale formations are not uniform – either within or between formations. The Bureau of Economic Geology is engaged in studies of the Haynesville, Marcellus and Fayetteville shale formation to be completed by the end of the year. Those studies will add fuel to the debate. We believe the results of the Barnett Shale study will be used aggressively to debunk those who are critical of the economics of shale and to support an expansion of the role natural gas will play in the future U.S. energy picture.

G. Allen Brooks works as the Managing Director at PPHB LP. Reprinted with permission of PPHB.