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Oil and Gas Energy News Update

Tuesday, April 26, 2011

Musings: Natural Gas Is So 2010; Now It's All About Liquids-rich Shale

Tuesday, April 26, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks

Last week the Baker Hughes U.S. active drilling rig count hit 1,800, up 1.6% from the prior week and up 21.5% over the past year. These were notable achievements. The increases reflect the exploration and development fever that is gripping oil and gas companies. This should be good news for the country's oilfield service industry, but maybe even better news for consumers as the increased drilling should lead to higher oil and gas production, and maybe lower fuel prices. More production means the nation's economy need not import as much oil and gas from abroad, which could have a significant impact on our balance of trade and payments, and the value of the dollar.

The most notable bit of data about last week's rig count was that for the first time in nearly 16 years, the oil and gas industry is employing more rigs targeting crude oil prospects (913 rigs) than drilling for natural gas wells (878 rigs). Analysts and investors, keen to see higher natural gas prices, have seized on this switch in drilling focus as a signal that future gas production will soon stop climbing. Assuming that the nation's natural gas consumption continues to rise, the drilling switch portends a shrinking of the oversupply of natural gas. That should mean higher natural gas prices – the only question is when.

Those E&P companies that are leading the charge into the gas shale plays around the country will be happy to see higher natural gas prices. They continue to claim that they can be profitable drilling these gas shale plays at natural gas prices in the $4.00 to $5.00 per thousand cubic feet (Mcf) of gas. Their financial results suggest something different. They still proclaim the success of the gas shale revolution, a movement that is beginning to spread globally.

Slightly over two weeks ago, the Energy Information Administration (EIA) released an analysis of gas shale resources around the world. It was clear from the report that the EIA believes the domestic gas shale revolution will be embraced globally. The EIA report estimates that 32 countries with known gas shale resources have added 5,760 trillion cubic feet (Tcf) of technically recoverable natural gas to the world's resources. With the addition of the U.S. gas shale resources, the global total would swell to 6,622Tcf. For comparison purposes, the world's proven natural gas reserves as of January 1, 2010, were 6,609Tcf. The world's total technically recoverable gas resources were 16,000Tcf as of the beginning of 2010, so with the new gas shale resources added in, the world now has over 22,000Tcf of gas resources.

The 32 countries with gas shale resources span the world and are likely to become energy-headline locations before long. Most people are familiar with the gas shale drilling underway in Poland and China, but those are only two of the 32 countries that span the globe. China leads the world with an estimated 1,275Tcf of gas shale resources. In Europe, Poland is in first place with an estimated 1,867Tcf of potential reserves, followed closely by France with 180Tcf. Interestingly, France has announced it is considering banning the drilling of gas shale wells until a study of possible water pollution problems associated with hydraulic fracturing are investigated and proven false. Equally surprisingly is that Norway has nearly half the gas shale resources of Poland and France.

Exhibit 1.  Gas Shales Located Around The World
Gas Shales Located Around The World
Source:  EIA

In South America, Argentina is highly prospective with nearly 90% of the total gas shale resources estimated to be in the United States. Brazil has about a third of the resources of Argentina with most of the potential resources located in the area close to some of the key manufacturing sites in the country. Surprisingly, Mexico has a huge potential with almost 80% of the estimated United States gas shale resources.

In Africa, the greatest potential source of natural gas from shales lies in South Africa, which has an estimated 485Tcf of resources. Libya, the site of the current civil war involving the country's crude oil reserves and production, has an estimated 290Tcf of gas shale resources. Algeria follows with nearly 80% of Libya's estimate.

While the world has lots of gas shale resource potential, it is in North America, and primarily the United States, where the gas shale revolution is in high gear producing substantial volumes of new gas production. According to the EIA, 2010's 4.87Tcf of gas shale production represents about 23% of total U.S. output, but it is projected to account for 45% of the nation's gas supply by 2035. The huge potential of gas shales in this country was first highlighted by the 2009 report of the Potential Gas Committee (PGC) at the Colorado School of Mines. In that report, the PGC estimated that there was about 616Tcf of gas shale resource, or about a third of the country's total resource potential.

Recently, Ken Medlock, a professor at Rice University, delivered a presentation about the gas shale industry at the American Association of Petroleum Geologists (AAPG) annual meeting. In his presentation he listed a timeline of potential gas shale resource estimates beginning with the 2003 National Petroleum Council estimate of 38Tcf. Two years later the estimate was raised to 140 Tcf and then in 2008 Navigant, a consulting company, estimated there was 520Tcf of potential reserves. The next year came the PGC estimate of 616Tcf and last year, consultant ARI estimated gas shale resources of more than 1,000Tcf. Mr. Medlock said there is a Department of Energy study underway with a May release date that will contain an estimate greater than ARI's estimate, likely putting it close to China's estimated 1,275Tcf of potential reserves.

All this potential gas has led politicians, investment professionals and E&P company executives to announce that the United States has in excess of 100 years of natural gas supply. In his presentation at the AARP, Art Berman showed that by reading the PGC report it becomes clear that gas shale reserves will likely only supply about 20 years of demand at the current 23Tcf of annual consumption.

Mr. Berman's pricking of the gas shale 100-year supply bubble should be having a greater impact, but instead the air is barely slipping out of the balloon. In fact, President Barack Obama has endorsed the huge potential gas supply mantra. In a recent presentation about the nation's energy situation, President Obama said, "We have a lot of natural gas here in this county." In doing so, however, he touched on the key issue now swirling around the gas shale revolution, which is the use of hydraulic fracturing to release the trapped gas from the formation President Obama's observation was, "The problem is…extracting it [shale gas] from the ground. The technologies aren't as developed as we'd like and so there are some concerns that it might create pollution in our groundwater, for

Exhibit 2.  Gas Shale Reserves Less Than 100 Years
Gas Shale Reserves Less Than 100 Years
Source:  Art Berman

example. So we've got to make sure that if we're going to do it [fracking], we do it in a way that doesn't poison people." There is plenty of evidence to refute the President's observation, but it is having a hard time being recognized.

A recent article by Stephen Hayward of the American Enterprise Institute highlighted the two problems confronting gas shale development. First is the issue of the safety of hydraulic fracturing. The other issue is what to do about the gas bounty being developed. The gas shale revolution has put these issues on the front pages of the papers and has drawn into the discussion the one factor that can derail the revolution – politics, such as the views of the President.

The battle over the safety of hydraulic fracturing grew in intensity the closer gas shale drilling moved to the East Coast. The emergence of the Marcellus shale as probably the largest gas field in the United States brought drilling rigs and pressure pumping equipment into the hilly topography of New York, Pennsylvania, Ohio and West Virginia. Despite the American oil industry getting its start in 1859 when Col. Drake drilled the first oil well in northwestern Pennsylvania, the region is not used to the intensity of drilling and producing activity experienced in regions such as the Southwest and Gulf Coast. The lack of equipment and workers has created a huge in-migration of both, creating an unsettled feeling among the local population. New oilfield service company equipment bases, heavy traffic consisting of large trucks with loads of equipment and supplies driving through small towns and rural areas, and lots of temporary workers from foreign places such as Texas, Oklahoma, Louisiana and Canada is changing the pace of everyday living in the Northeast.

The low price of natural gas, combined with the high-efficiency gas power plant designs, makes gas-fired power plants cheaper than coal-fired power plants. This has been the case for at least two decades, but due to the volatility of natural gas prices, these plants have been limited to peak electricity generating roles. Now it appears gas could be used for more baseload generation, replacing aging coal plants that are under pressure from costly new Environmental Protection Agency (EPA) clean air requirements and the long-standing environmental crusade against coal plants.

For the first time ever, natural gas producers and utilities have joined with environmentalists to alter the status quo over replacing coal-fired power plants with gas-fired ones. This alliance will not last for long, however, as cheap natural gas makes the favorite energy sources of environmentalists – wind and solar – that much less competitive. Environmentalists used to love natural gas so long as it was expensive and used merely as a backstop for "clean" wind and solar power. Now that it may displace their favorite fuels, they don't love natural gas as much.

Mr. Hayward refers to this attitude about natural gas on the part of environmentalists as "the theorem of environmental duplicity: namely, there is no form of 'clean' or 'alternative' energy that environmentalists won't decide to oppose if it becomes practical and affordable on a large scale." Last week's Chesapeake gas shale well blowout certainly gives more ammunition to the environmental movement to oppose the use of hydraulic fracturing. The Chesapeake well was plugged late last week and the company and state regulators are monitoring the pollution as well fluids were spilled and migrated across the land.

Environmental opposition to hydraulic fracturing has been helped along by a sympathetic media that writes "investigative" reports that often create false impressions about the safety of hydraulic fracturing and even the exploitation of gas shale formations. Every study conducted about hydraulic fracturing has found no problems. The reason is simple: the target shale formations are thousands of feet below the surface and thousands of feet below the aquifer. Both the distance and the nature of the rock that separates the formations prevent fracturing fluids from migrating to the aquifer, as demonstrated in Exhibit 3. What has been a problem in certain wells where natural gas has migrated into drinking water was the primary cement job for the surface pipe, which is designed to isolate the gas well from the ground water. Due to cement bond failures, it is possible for flowing natural gas to leak out and into the ground water, which then can flow to a homeowner's water faucets.

Other than gas migrating into ground water formations, water associated with gas shale activity has become a major challenge for the E&P industry. Water is needed for drilling and for hydraulic fracturing completions. As a result of the large volumes of water required in the completion process, huge volumes of contaminated

Exhibit 3.  Gas Shale Wells Are Well Below Groundwater
Gas Shale Wells Are Well Below Groundwater
Source:  Ohio Department of Natural Resources

water are returned in the initial well flow. This flow-back water needs to be disposed of either by cleaning it up to meet standards for dumping into local waste water disposal systems or by placing it into streams and rivers. An alternative disposal method is to inject it into special disposal wells. Because Pennsylvania has few disposal wells, flow-back water and water produced in association with oil and gas output is either cleaned up or hauled to disposal wells, many of which are located in neighboring Ohio.

While water and hydraulic fracturing concerns are, and will continue to be, an ongoing issue, the more critical consideration is the economic viability of gas shale drilling. When Mitchell Energy solved the key critical variables in unlocking natural gas trapped in the shale formation underlying the Barnett basin in Texas, they probably had little comprehension of the revolution they were starting. That revolution was perceived to have certain characteristics that would unlock tremendous gas resources. Those characteristics included: uniform shale formations that blanketed the areas underlying oil and gas producing basins; that formations would yield significant gas volumes, which was directly correlated with the number of wells drilled and hydraulic fracturing treatments administered; that horizontal drilling exposed greater amounts of the shale formation helping release more of its trapped gas; and that all wells in shale formations would be equally productive enabling rapid drilling employing uniform drilling techniques producing low drilling costs. The combination of these characteristics was supposed to translate into large volumes of low-cost natural gas.

After about five years of active drilling in the oldest shale basins has begun to disprove certain of these characteristics and their implications on well economics. We have learned that gas shale basins still need a trapping mechanism in order to be productive. Drilling has also shown that gas shale plays have "sweet" spots that produce higher well volumes than wells drilled outside of the "sweet" spots. These realizations have begun to dispel the manufacturing concept for how gas shale fields would be developed.

We have learned that by drilling longer lateral sections and applying greater numbers of hydraulic fracturing treatments to wells, gas volumes can be maximized. The problem has been that the cost to secure the acreage to drill these gas shale wells and the drilling and completion costs are not particularly cheap. Since natural gas prices are so low due to growing gas production and weak gas demand, the economics of many gas shale wells have been called into question. We are also finding that many gas shale wells are not producing the volumes projected. This latter observation is highly contentious among participants within the oil and gas industry. However, the more data that is collected, the greater the confidence the critics of gas shale profitability have that these plays may not be the goldmines proponents claim.

In Art Berman's AAPG presentation, he presented the chart in Exhibit 4 showing that within the Barnett Shale play, when the production from newly drilled wells during the last 12 months is excluded, gas production declined at a 44% annual rate. The importance of this static well analysis is that it highlights the need for producers to continually drill new wells in order to grow production, or maybe merely to offset production declines. The significance of the analysis is that the E&P industry is on a treadmill of new well drilling with the likelihood that the slope of drilling activity is rising with cost implications unknown.

Exhibit 4.  Without Drilling Production Falls Rapidly
Without Drilling Production Falls Rapidly
Source:  Art Berman

Another analysis of the Barnett Shale play shows how the wells are not producing the necessary volumes of natural gas to support the Economically Ultimately Recoverability (EUR) reserve estimates being used by producers. In determining profitability, producers estimate the total number of reserves they will produce from their wells and divide that figure into the total cost estimate for finding, developing and producing the reserves. The resulting cost per Mcf of gas produced is amortized against the revenue earned from its sale. If any of the assumptions is wrong, the profitability calculation can be way off.

If we examine two slides from Chesapeake's 2010 institutional investor and analyst meeting in October 2010, we can see how the EUR and well costs interact to impact profitability of gas shale developments. The first chart (Exhibit 5) shows the decline curves and basic data about the four major gas shale plays in which Chesapeake is involved. The data on this chart shows that Chesapeake expects the EUR for its Barnett Shale wells to be 3.0 billion cubic feet (Bcf).

Exhibit 5.  3Bcf EUR Estimated For Barnett Shale
3Bcf EUR Estimated For Barnett Shale
Source:  Chesapeake Energy

The next chart (Exhibit 6) shows the sensitivity of its profitability to the price of natural gas and the EUR. As the data for the Barnett Shale shows, Chesapeake believes that with a EUR of 3.0 Bcf and a price of $5.05/Mcf, the company will earn a 10% rate of return. By moving along the green curve on the chart, one can see that a smaller EUR needs a much higher natural gas price to achieve the same 10% rate of return.

An analysis of the Barnett Shale field shows how production from 1992 through November 2010 has climbed. The chart (Exhibit 7)

Exhibit 6.  Economics Of Gas Shale Plays
Economics Of Gas Shale Plays
Source:  Chesapeake Energy

shows that the number of new well completions has decline sharply in the past two years with a corresponding decline in natural gas output.

Exhibit 7.  Barnett Shale Gas Production
Barnett Shale Gas Production
Source:  Robert Gray

This analysis, prepared by Robert Gray, an associate of Art Berman's, focused on examining the performance of a static universe of producing wells in the Barnett Shale. In Exhibit 8, he tracked the production from a universe of wells that he stopped growing in November 2009. One can see the historic gas production in blue, which had begun to decline prior to 2009, and the monthly gas production subsequent to creating the static well universe.

Exhibit 8.  Barnett Shale Static Well Production
Barnett Shale Static Well Production
Source:  Robert Gray

By using the production data through November 2009, Mr. Gray was able to generate models for predicting the future decline rates, which, over the remaining production life of the wells, produces an estimate of the EURs for the wells.

Exhibit 9.  Production Basis For Curve Projections
Production Basis For Curve Projections
Source:  Robert Gray

Shown in Exhibit 10 are the two type curves – hyperbolic and exponential – calculated from the historic data as of November 2009.  Under the hyperbolic curve, the estimated EUR per well is 2.395 Bcf. The exponential curve shows a future EUR of only 1.133 Bcf.  Both of these EUR estimates are well below the EUR projected by Chesapeake for its wells in this field.

Exhibit 10.  2009 Production Decline Curves
2009 Production Decline Curves
Source:  Robert Gray

Now that we have an additional year's worth of production data, Mr. Gray was able to estimate new decline curves incorporating that information. As seen in Exhibit 11, the new 2010 hyperbolic and exponential curves fall below those estimated from the 2009 data. We now have EUR estimates of 1.452 Bcf for the hyperbolic curve and only 0.850 Bcf for the exponential curve.

Exhibit 11.  2010 EUR Curves Well Below Estimates
2010 EUR Curves Well Below Estimates
Source:  Robert Gray

If we go back to the rate of return chart from the Chesapeake presentation, it does not show what gas price is required for EURs smaller than 2.4 Bcf. Even at that EUR, the 10% rate of return requires a gas price slightly below $6.00/Mcf. Our guess is that a producer will need a gas price somewhere around $7/Mcf to achieve a modest return on investment given the exponential EUR Mr. Gray has calculated. In a more recent update, Mr. Gray has increased his exponential EUR estimate to about 1.0 Bcf. Even that increased estimate is still only a third of Chesapeake's EUR estimate.

Exhibit 12.  Well Production Short Of EUR Estimates
Well Production Short Of EUR Estimates
Source:  Art Berman

In prior presentations, Mr. Berman has shown the chart in Exhibit 12. It presents the range of EURs claimed in investor presentations by the major producers in the Barnett Shale plotted against their cumulative production. The data shows how production does not seem to be coming anywhere close to the estimated EURs. Quite possibly this helps to explain why 16 significant E&P companies active in the gas shale plays have written off goodwill and the value of their reserves to the tune of $67 billion over 2008-2010. If producers acted in a more rational manner and cut back their drilling, the rapid decline in gas shale production as demonstrated by Mr. Berman's chart should lead to higher natural gas prices. Therein lays the conundrum for the gas market – drill to grow and satisfy Wall Street or cut back, secure higher prices and stop destroying shareholders' capital.

G. Allen Brooks G. Allen Brooks
Managing Director,
Parks Paton Hoepfl & Brown
G. Allen Brooks works as the Managing Director at Parks Paton Hoepfl & Brown. Reprinted with permission of PPH & B.

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