Journal of APPLIED CORPORATE FINANCE

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1 VOLUME 25 NUMBER 4 FALL 2013 Journal of APPLIED CORPORATE FINANCE In This Issue: Risk Management Navigating the Changing Landscape of Finance 8 James Gorman, Chairman and CEO, Morgan Stanley Reforming Banks Without Destroying Their Productivity and Value 14 Charles W. Calomiris, Columbia University How Companies Can Use Hedging to Create Shareholder Value 21 René Stulz, Ohio State University Do Trading and Power Operations Mix? 30 John E. Parsons, MIT Sloan School of Management Aligning Incentives at Systemically Important Financial Institutions: A Proposal by the Squam Lake Group 37 The Squam Lake Group Managing Pension Risks: A Corporate Finance Perspective 41 Gabriel Kimyagarov, Citigroup Global Markets, and Anil Shivdasani, University of North Carolina at Chapel Hill Synthetic Floating-Rate Debt: An Example of an Asset-Driven Liability Structure 50 James Adams, J.P. Morgan Securities, and Donald J. Smith, Boston University Hedge Fund Involvement in Convertible Securities 60 Stephen J. Brown, New York University; Bruce D. Grundy University of Melbourne; Craig M. Lewis, Vanderbilt University; and Patrick Verwijmeren, Erasmus University Rotterdam Fine-Tuning a Corporate Hedging Portfolio: The Case of an Airline 74 Mathias Gerner, European Business School and Ehud I. Ronn, University of Texas at Austin A Primer on the Economics of Shale Gas Production Just How Cheap is Shale Gas? 87 Larry W. Lake, University of Texas; John Martin, Baylor University; J. Douglas Ramsey, EXCO Resources, Inc.; and Sheridan Titman, University of Texas Evidence from German Companies of Effects of Corporate Risk Management on Capital Structure Decisions 97 Julita M. Bock, Otto von Guericke University

2 A Primer on the Economics of Shale Gas Production Just How Cheap is Shale Gas? by Larry W. Lake, University of Texas; John Martin, Baylor University; J. Douglas Ramsey, EXCO Resources, Inc.; and Sheridan Titman, University of Texas 1 BT he U.S. government doubled its estimate of the country s economically recoverable natural gas reserves between 2009 and This increase is directly related to unconventional gas, specifically gas held in shale formations that are now recoverable using horizontal drilling and hydraulic fracturing (i.e., fracking ) techniques developed in the last decade. Moreover, the promise of unconventional gas and oil resources has led some to predict that the U.S. will be the top global oil and gas producer, surpassing Russia and Saudi Arabia. 3 Others caution that overly optimistic estimates of shale gas reserves combined with low gas prices may keep shale gas from becoming the game changer many believe it will be. 4 Specifically, there are three big issues that arise with respect to the production of natural gas from shale: 5 First, traditional methods used to estimate gas reserves may overstate recoverable shale gas reserves. Since the horizontal drilling and fracturing methods used to extract gas from shale formations is relatively new (often less than 5 years old), analysts have limited experience to draw upon when trying to estimate the volume of technically recoverable reserves. Moreover, production experience suggests that the production rate from shale wells declines much more rapidly than production from vertical gas wells. Second, the economic viability of producing shale gas has been questioned. Extracting natural gas from shale formations is both difficult and expensive. It requires horizontal drilling and fracturing of formations using large quantities of water. It is difficult to forecast the long-term production of shale gas wells. The productive life of shale gas may be very short with roughly 70% of available reserves extracted in the first year of production. This means that a dependable supply of natural gas from shale formations requires a sustained program of drilling, completion, and exploration. Finally, there are serious environmental concerns about the production of shale gas. The drilling techniques used to extract shale gas require large volumes of water and some chemicals that could result in ground water contamination. Potential environmental costs could seriously erode the economic viability of producing gas from shale formations. 6 Ultimately all of these concerns impact the economics of shale gas production. If shale gas reserves have been overestimated then this will result in reduced production and possibly higher gas prices. Environmental concerns will likely lead to regulatory changes that result in increased costs of extracting shale gas. In this paper we first develop a base case model to evaluate the economic viability of producing natural gas from shale formations. To construct our base model we use data from a shale gas well in the Haynesville shale region of North Louisiana. 7 Our analysis explores the valuation of the predicted gas volumes from that well using estimated production costs for the region in conjunction with estimated natural gas prices. To generalize the model we use both sensitivity analyses of the key value drivers, as well as simulation analysis. We find most shale gas wells are profitable under the assumed conditions of our model data. However, the key driver of NPV is the price of natural gas, which at the time of this writing is very nearly equal to breakeven levels (assuming the current method used to estimate production volume is correct). The conventional view of a hydrocarbon accumulation is that three things are required: a source rock, a reservoir, 1. We want to thank Patrick Gonzalez, John McCormack, Jeffrey Nelson, and L. J. R. Bert Scholtens for their thoughtful comments on an earlier draft of the paper. Responsibility for any remaining errors, however, is ours. 2. The American Energy Outlook (published by the U.S. Energy Information Administration or EIA) estimated total US recoverable US shale gas resources in 2009 to be trillion cubic feet, increased its estimate to 317 trillion cubic feet in 2010 and then doubled that again for 2011 ( The EIA also increased its estimates of worldwide recoverable shale gas volumes from 6,622 TCF in 2011 to 7,299 in Over the same time frame the worldwide recoverable tight oil reserves increased from 32 million barrels to 345 million. ( studies/worldshalegas/). 3. Guy Chazan, Big Oil Heads Back Home, The Wall Street Journal, December 5, 2011, R1. 4. Based upon his analysis of the production history of the Barnett Shale, Arthur Berman, staff member of The Oil Drum ( questions whether shale gas can ever meet the hype surrounding its current popularity. He argues that rather than 100 year supply of natural gas, shale gas offers as little as seven years. 5. Natural gas has been produced from shale formations for over one hundred years but recent technological advances have made the economics of its production much more attractive. 6. Although fracking has been around since the 1940 s its use has increased significantly since 2000 and become a focus of intense media scrutiny. Fracking fluid is 99.5% sand and water and most of the injected water is later extracted during production. There is always some risk, however, of ground water contamination, and objections to more traffic and noise related to drilling. See John Walton and Arturo Woocay, Environmental Issues Related to Enhanced Production of Natural Gas by Hydraulic Fracturing, Oil, Gas, & Mining, Volume 1, Issue 1, (August 2013). 7. The Haynesville shale spans a 9,000 square mile area in North Louisiana. Although not as large geographically as the Marcellus shale which covers 95,000 square miles, it has almost as much gas: an estimated 251 trillion cubic feet (Tcf) compared to just 262 Tcf for the much larger Marcellus shale. Journal of Applied Corporate Finance Volume 25 Number 4 Fall

3 and a seal. Hydrocarbons are generated in the source rock, usually organic-rich shale, by slow cooking over hundreds of thousands of years. Once converted, hydrocarbons are expelled from the source and migrate upwards until encountering and being trapped by the seal. The goal of conventional exploration was to find the seal. The actual location of the source rock was unimportant; sometimes it was hundreds of kilometers away from the reservoir, and for many conventional reservoirs the location of the source was unknown. Source rocks are very widely distributed across the world. But they were assumed to be so impermeable that many eons would be required for hydrocarbons to ooze out of them. And the hydrocarbons were not hydrocarbons in the usual sense; they were only precursors to hydrocarbons. That was the conventional view. We now know that source rocks contain a good deal of hydrocarbon itself, especially natural gas, not just its precursor. Source rocks are essentially impermeable however, but we can deal with this by brutalizing the rock through horizontal drilling and fracturing (often referred to as fracking). Interestingly it remains true that source rocks are abundant. The economics of conventional natural gas production differs from unconventional shale gas in several ways: I. Total production volumes a conventional gas well might produce 30 to 40 billion cubic feet of gas over its life whereas a shale well would produce a fraction of this amount. II. Rate of decline in production volumes shale gas wells have a very steep rate of decline compared to conventional wells, especially in the initial production period. III. Production methods shale gas is trapped in rock formations that must be fractured before the gas can flow. Fracturing, which involves injecting water and sand at high pressure into the formation, is expensive and may entail environmental risks. IV. Horizontal wells shale gas production typically uses horizontal drilling whereas conventional gas wells are drilled using vertical wells. V. Completion after drilling these wells must be fractured before the viability of producing the well can be determined. This means that the decision to drill the well is tantamount to a commitment to complete the well. This is different than a conventional gas well in which a drilling log and pressure measurements can be used to estimate the volume of recoverable reserves before the well is completed. 8 If the well is deemed uneconomic it can be plugged and abandoned thereby avoiding completion expenses. VI. Follow on investments since shale formations are typically very large, the probability of success of follow on wells (in what is commonly referred to as the resource play) is 8. This is a bit of an oversimplification for even with conventional wells the operator might choose to frack the well after drilling should the well not flow. Thus, conventional wells offer the operator the option to complete the well which may include fracking. In contrast, shale wells must be fracked before their economic viability can be determined. 9. The severance tax is a tax imposed by states for the extraction of natural resources much higher than in conventional wells that seek out smaller reservoirs. This means that the opportunity to make add-on investments is greater for shale gas wells than conventional wells. VII. Exploration costs. The vastness of shale formations means that there is little discovery risk and few wells are absolutely unproductive. These differences indicate that the economics of extracting shale gas can be quite different than that of extracting conventional gas deposits. The first five differences tend to decrease the value of shale gas in comparison with conventional formations but the last two favor shale very much. We built a model for a specific shale gas well found in the Haynesville shale region of North Central Louisiana (Haynesville #1). The key elements are the production decline curve forecast for the well, the cost of drilling and completing the well, the annual operating costs for producing the gas, and the price of natural gas. We wanted to build a general model of shale gas production to replicate a wide range of conditions encountered across different regions of the country. We first calibrated our base model to the actual Haynesville shale conditions and then vary the key value drivers. Panel A of Table 1 contains the original data estimates for the Haynesville #1 well. This data is from a single well and not the entire resource play. In year 0 the well calls for an investment of $1,912,500 which equals the owner s 15.75% working interest in the well multiplied by the total drilling and completion costs. Beginning in year 1 the annual cash flows from the example gas well are calculated as follows: Net Gas Price of Total Net Severance & Depletion Production Natural Gas Operating Ad Valorem (mcf) per mcf Expenses Expenses Allowance Corporate 1- Income Tax Rate + Depletion Allowance Net gas production is equal to the owner s proportionate working interest in the well revenues (15.75%) multiplied by the estimated gross annual gas production. Total net operating expenses include the owner s share of the cash expenses required to extract, transport and sell the gas production from the well. Severance and Ad Valorem expenses are taxes imposed on gas producers and the depletion allowance is a non-cash expense available to gas producers to reflect the depletion of the asset represented by the well. 9 Energy firms have sometimes computed return on investments in gas wells on a before corporate tax basis. This practice arose, in part, because their investments were often unprofitable. This has been much less true recently. For example, Chesapeake Energy paid average tax rates of 38% and 39% such as natural gas which in the State of Louisiana is $ per Mcf. The ad valorem tax is a tax levied on the difference between the price of natural gas and the cost of production. In Louisiana this tax is levied for each well as follows: In the first year the tax is $955 per month. In years two through twenty the tax declines by 4% per year and for all years thereafter it is equal to the year 20 total. (1) 88 Journal of Applied Corporate Finance Volume 25 Number 4 Fall 2013

4 Table 1 Base Case Model for Haynesville #1 Panel A Cash flow estimates Date Period Estimated Gross Gas (Mcf) Estimated Net Gas (15.75% of Gross Gas) (Mcf) Price of Natural Gas/ Mcf Estimated Total Net Revenue Estimated Total Net Operating Expense Estimated Severance & Ad Valorem Expense Estimated Depletion Allowance Estimated Equity Investment Estimated After-tax Net Cash Flow Dec-09 0 $(1,912,500) $(1,912,500) Dec ,405, ,857.3 $4.50 $1,704,858 $(13,568) $(1,908) $(483,695) 1,327,676 Dec , , ,968 (11,833) (36,625) $(155,467) 396,298 Dec , , ,653 (9,747) (25,794) $(95,514) 239,432 Dec , , ,695 (9,747) (19,644) $(69,140) 170,755 Dec , , ,121 (9,747) (15,791) $(54,224) 132,176 Dec , , ,255 (9,747) (13,165) $(44,616) 107,425 Dec , , ,604 (9,747) (11,265) $(37,906) 90,186 Dec , , ,146 (9,747) (9,827) $(32,952) 77,486 Dec , , ,727 (9,747) (8,701) $(29,145) 67,739 Dec , , ,091 (9,747) (7,797) $(26,128) 60,021 Dec , , ,452 (9,747) (7,054) $(23,677) 53,759 Dec , , ,295 (9,747) (6,433) $(21,646) 48,575 Dec , , ,270 (9,747) (5,906) $(19,937) 44,213 Dec , , ,127 (9,747) (5,454) $(18,478) 40,492 Dec , , ,861 (9,747) (5,076) $(17,267) 37,406 Dec , , ,308 (9,747) (4,761) $(16,259) 34,838 Dec , , ,971 (9,747) (4,463) $(15,312) 32,426 Dec , , ,828 (9,747) (4,182) $(14,421) 30,155 Dec , , ,868 (9,747) (3,916) $(13,581) 28,017 Dec , , ,080 (9,747) (3,665) $(12,790) 26,005 Dec , , ,455 (9,747) (3,428) $(12,045) 24,109 Dec , , ,983 (9,747) (3,204) $(11,344) 22,325 Dec , , ,654 (9,747) (2,993) $(10,683) 20,645 Dec , , ,462 (9,747) (2,793) $(10,061) 19,063 Dec , , ,396 (9,747) (2,605) $(9,475) 17,574 Dec , , ,452 (9,747) (2,427) $(8,923) 16,171 Dec , , ,620 (9,747) (2,259) $(8,404) 14,851 Dec , , ,895 (9,747) (2,101) $(7,914) 13,607 Dec , , ,271 (9,747) (1,952) $(7,453) 12,436 Dec , , ,741 (9,747) (1,811) $(7,019) 11,334 Dec , , ,300 (9,747) (1,678) $(6,611) 10,296 Dec , , ,943 (9,747) (1,553) $(6,226) 9,318 Dec , , ,665 (9,747) (1,434) $(5,863) 8,398 Dec , , ,462 (9,747) (1,323) $(5,522) 7,531 Dec , , ,328 (9,747) (1,218) $(5,200) 6,714 Dec , , ,261 (9,747) (1,119) $(4,897) 5,946 Dec , , ,256 (9,747) (1,025) $(4,612) 5,222 Dec , , ,309 (9,747) (937) $(4,343) 4,540 Panel B Project Valuation (Cost of capital = 10%) Corporate Tax Rate, % 30 0 NPV, $ 309, ,995 IRR, % Journal of Applied Corporate Finance Volume 25 Number 4 Fall

5 in 2010 and 2011 respectively. We believe our assumption of a 30% corporate tax rate is a conservative one. Panel B of Table 1 contains the estimated net present value (NPV) and internal rate of return (IRR) for the well. The NPV is $309,201 and the IRR 16.47%, which exceeds the 10% cost of capital used in the analysis. If one were to assume a zero tax rate, the NPV would be $893,995 and the IRR 30.86%. Obviously, the tax assumption will have a very large impact on the reported results. Table 2 presents the results of the model s forecast of the cash flow found in the Haynesville #1 well described in Table 1. There are three basic components that must be modeled to evaluate an investment in a shale gas well: Drilling and completion costs, gas revenues, and operating costs. Let s consider each in turn. Drilling costs are directly related to the depth of the shale formation and the number of fractures or fracks used to provide a permeable path for the gas to flow through the tight shale formation. The number of fracks in the pay zone tends to be 8-10 for most wells. However, the depth of the shale formation varies from one shale area to another. For example, the depth of the shale formation in the Haynesville region is 10,000-13,500 feet whereas in the Fayetteville shale the formations are 1,000-7,000 feet and in the New Albany shale, the wells can be as shallow as 500 feet. 10 To illustrate the range of drilling costs, the cost of drilling and completing a well in the Woodford shale (Oklahoma), where the shale is 6,000-11,000 feet deep is estimated to be $6.7 million, 11 whereas the cost of drilling and completing a new well in the Haynesville shale is estimated to be $9.5 million. 12 The cost of Haynesville #1, however, was slightly lower than the average at $8.5 million. Note that drilling costs change from month to month and also vary by location. The cost of drilling the well is approximately 60% of this total and completion costs make up the remaining 40%. For conventional gas wells the operator has a valuable option to shut-in the well if measurements taken during drilling indicate it will be uneconomic. Consequently, the division between drilling and completing costs is very important. With shale wells, however, the productivity of a shale gas deposit cannot be known until after the well has been fractured and this entails incurring the bulk of the costs of completing the well. Consequently, the option to shut-in the well prior to incurring the costs of completing the well is not as valuable for a shale gas well as it is for a conventional gas well. In a typical shale gas well in the US, the investor will have a complete working interest. A working interest less than 100% can represent an attempt to diversify risk exposure or simply to accommodate capital constraints. For example, in the model we assume that the investor owns 15.75% of well revenues but its share of expenses is 22.5% since royalty owners do not share the expenses. Gas well revenues are a function of two key variables: The price per thousand cubic feet (Mcf) of natural gas sold, and the volume of gas produced. We will assume that the price of natural gas is fixed at $4.50/Mcf over the life of the investment just as was done by the investor in the example well described in Table 1. Although gas prices can fluctuate widely, it is common practice to use rolling, forward contracts dated out to five years to hedge price risk. The five-year gas price assumption should reflect forward market prices at the time of evaluation since that is what can be hedged. The second key variable is the volume of gas it will produce. The common methods used to estimate oil and gas reserves rely on an empirical extrapolation based on physical characteristics of the reservoir. Over sixty years ago, J.J. Arps defined a set of empirical production decline curves based on the following hyperbolic function: 13 1 q t = q i (1+nD i t) n (2) where q t is the production rate at time t (i.e., Mcf/year); q i is the initial production rate at time t= 0; D i and n are two constants (the former is the initial rate of decline in production and n is the rate of change in D i over time); and t is the time period for which production is being estimated. The Appendix discusses the particulars of applying the hyperbolic decline curve to production estimates found in Panel A of Table The production estimates for Haynesville #1 are based on a combination of two types of production decline curves: Initially production declines based on a hyperbolic decline curve with the following parameters: q i (initial production rate at time 0) = 19,500 Mcf/day; D i (initial rate of decline in production) = 85% for the first year; 10. Based on a study published in April 2009 and prepared for the U.S. Department of Energy Office of Fossil Energy and National Energy Technology Laboratory titled Modern Shale Gas Development in the United States: A Primer, p Larry Benedetto, Unconventional Gas and its Impact on Domestic Supply, a report issued by Howard Weil ( May2008.pdf) 12. This is the cost estimate of our example well. However, the average cost of shale wells in the Haynesville shale has been reported to be somewhat higher. In 2010 both Petrohawk (HK) (Enercom Oil & Gas Conference: August 24, 2010) and EXCO (XCO) (Fourth Quarter and Full Year 2009 Review: February 2010) reported an average cost of their shale gas wells in the Haynesville Shale of $9.5 million. 13. R.E. Allen is credited with mentioning four types of decline curves in 1931 and that J.J. Arps later expounded upon. See R. E. Allen, Control of California Oil Curtailment, Trans. A.I.M.E., 92, 47, 1931 and J. J. Arps, Estimation of Primary Oil Reserves in Petroleum Transactions, AIME, Vol. 207, The method we use to estimate production volumes follows industry practice; however, new methods have been proposed that claim to improve the accuracy of volume projections. These include the one mentioned in the M.S. thesis of A.J. Clark. See A. J. Clark, Decline Curve Analysis in Unconventional Resource Plays using Logistic Growth Models, M.S. thesis, University of Texas at Austin, 2011; A. J. Clark, Larry W. Lake, and Tad Patzel, Production Forecasting with Logistic Growth Models, SPE , presented at the 2011 Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Denver, Colorado; and Peter Valko and W. John Lee, A Better Way to Forecast Production from Unconventional Gas Wells, SPE134231, presented at the 2010 E Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Florence, Italy. 90 Journal of Applied Corporate Finance Volume 25 Number 4 Fall 2013

6 Figure 1 Estimated Gross Gas Production (Mcf/year) for Haynesville #1. 3,000,000 Annual Production Estimates Gross Gas Production (Mcf/Year) 2,500,000 2,000,000 1,500,000 1,000, ,000 Production function switches from hyperbolic to exponential between years 13 and 14 y = 2,015,779.16x R = and n (the rate of change in D i ) = The production decline curve switches to an exponential decline when the annual rate of decline in production falls to 7% at which time the decline function switches to the following exponential function with a rate of decline of 6%, i.e., 16 q t =q t-1 e.06 The switch from the hyperbolic to the exponential decline function occurs between years 13 and 14 for Haynesville #1. 17 Figure 1 contains the estimated production volumes for 2010 through Note the initial steep production rate decline as noted above. Using estimates based on this hyperbolic decline curve in the model we can later consider the effects of deviations from the estimated parameters on the value of the shale gas well. Multiplying the annual production volumes by the $4.50/ Mcf price for natural gas provides an estimate of the gross gas revenues from the well. Adjusting these estimates for the working interest of the investor produces the net gas revenue. There are three categories of annual operating expenses (see Equation 1). These are Total Net Operating Expense; Severance and Ad Valorem Expense; and Depletion Allowance. Based on the estimates provided for Haynesville #1 we 15. The slope term, n, being equal to one indicates that the hyperbolic decline function reduces to the special case of a harmonic decline function, which is discussed in the appendix. 16. Given the relatively brief time that horizontal, hydraulically fractured gas wells have been producing, the productive life of these wells is still unknown. Although conventional wells have produced for 30 years and longer, the initial evidence from the Barnett Shale is that the average productive life of a well is 7.5 years and the early evidence from the Marcellus suggests its wells also might have similar (short) lifespans (see A short life span does not mean these wells are not economic, but to be profitable the volumes of initial production have to carry the investment. 17. This switch to the exponential decline function is important because a hyperbolic curve with value of n greater than one implies an infinite recovery amount, (i.e., commonly referred to as the well s estimated ultimate recovery or EUR). model total net operating expenses as a percent of revenues for the first three years followed by a fixed dollar amount for years four and beyond that is equal to the year three expense. The percentages of revenues used in the analysis are consistent with actual estimates for the example well whose data provides the basis for our model. We combine severance and ad valorem taxes and model them as a quadratic function of net gas revenues as shown in Figure 2. The fit of the relationship to the data provided for Haynesville #1 was nearly perfect. This is unsurprising as these taxes are a function of revenues that are estimated using the production data provided to us for Haynesville #1. The production estimates were made using the production technique described in the Appendix. In 2010 the sum of these taxes is much smaller than in subsequent years because in Louisiana, where Haynesville #1 is located, there is no severance tax for the first year s production. The depletion allowance is like depreciation expense in that it represents the allocation of the cost of drilling and completing the gas well against revenues over the life of the well. For modeling purposes we use cost depletion expense per unit of production for the year multiplied by the total amount of gas produced Although we report actual production volumes on the vertical axis, engineers typically report log production. This practice probably arose out of the convenience where an exponential production decline function was used and the log transformation resulted in a linear or near-linear function that was easy to extrapolate future production by hand. 19. There are two methods for computing depletion: the cost method and percent of revenue method. The cost method, which we use, bases the allowance on the original cost of the income-generating property and any subsequent capitalized costs incurred (e.g., work over expense) can be used by all energy companies. The percent of revenues method is not tied to the original cost of the well such that the total depletion for a well is not limited to the original investment in the well using this method. The percent of revenue method can be used by an independent producer or royalty owner. However, certain refiners and certain retailers and transferees of proven oil and gas properties cannot claim percentage depletion. We use cost depletion to be conservative. Journal of Applied Corporate Finance Volume 25 Number 4 Fall

7 Figure 2 Actual and Estimated Severance and Ad Valorem Expenses. Equation in the figure is for the fitted line. 0 Severance & Ad Valorem Taxes (5,000) (10,000) (15,000) (20,000) (25,000) (30,000) (35,000) (40,000) 100, , , , , ,000 y = 0.00x x - 1, R 2 = 0.99 Net Gas Revenues Table 2 shows the NPV and IRR generated by the model. The model estimates are very close to the calculated values for NPV and IRR found when using the original data supplied for the project. As we estimate drilling plus completion costs total $1,912,500, our share of the 16.17% increase in these costs would reduce the NPV to zero. Table 2 NPV, $ IRR, % Summary Measures for the Original Data and Model of Haynesville #1 Original Data Estimates Model Estimates 308, , The well s NPV is sensitive to two key parameters of the hyperbolic production decline curve found in equation (2). These are the initial production rate and the initial decline in production for year Table 3 shows how much each of the two parameters would have to change to reduce the NPV to zero. Table 3 Parameter Initial Production Rate (q i ) Initial Decline in Production in Year 1 (D i ) Sensitivity Analysis of the Production Estimate Original Parameter Estimate 19,500 Mcf/ day Break-even Parameter Value 16,551 Mcf/ day Percent Change in Parameter Value Percent Change in Estimated Ultimate Recovery (EUR) % % 85% 87.7% 3.15% -13.2% Clearly, the NPV of the project is very sensitive to production volumes. An increase in the initial rate of decline in production for year one from 85% to 87.7% (an increase of just 3.15%) leads to a zero NPV estimate. Furthermore, a drop of 15.12% in the initial rate of production from 19,500 Mcf/day to 16,551 Mcf/day can also result in a zero NPV. 21 Although we have used the same hyperbolic decline function (as in equation 2) widely used with conventional gas wells, 22 to estimate the output of our shale gas well, we do not yet know whether this or some other function is more appropriate for unconventional shale gas wells. Some geoscientists suggest that a more rapid exponential function would be more appropriate. Only time will tell as we gain more production experience Recall that the production decline function used to model Haynesville #1 is a hybrid model containing a mixture of a hyperbolic and exponential function. In the sensitivity analysis used here we do not alter the exponential portion of the decline curve, which describes the tail of the curve. In the initial estimates we found that the exponential function is used between 13 and 14 years in to the productive life of the well. 21. Recall from equation (2) that there is a third variable in the hyperbolic decline curve equation. This variable determines the rate of change in the annual decline rate in production and was designated by n. When we evaluated the sensitivity of NPV to this variable we found that there was no positive value for n for which NPV was equal to zero. NPV declined with smaller values of n, but it reached a minimum near $100,000 as n approached zero. Remember that we were only allowing n to vary while holding all other variables constant so that estimates of this variable are important even though in this example this variable was not able to drive the NPV to zero. 22. We used a switching model that is initially a hyperbolic function and then converts to an exponential function where the rate of decline in production falls to 6%. 23. John Dizard of the Financial Times described the dissention within the petroleum engineering profession in 2010 regarding the amount of natural gas that will ultimately be recovered from shale formations and at what cost. See Debate over Shale Gas Decline Fires Up, FT.com (October 10, 2010). 92 Journal of Applied Corporate Finance Volume 25 Number 4 Fall 2013

8 We assumed a constant natural gas price for all future periods equal to $4.50 per Mcf. Should gas prices drop 15.66% to an average of $3.80, the NPV of the well falls below zero. Historically, gas prices have been volatile. The average annual per Mcf well-head price of natural gas was $4.00 in 2001 but rose to more than $10.00 in 2008 and then collapsed to $3.60 in October Although the sensitivity analysis provides some indication of the range of outcomes, it says little about the probabilities of extreme outcomes. To gain insight into possible extreme outcomes we used Monte Carlo simulation. We chose the triangular distribution to model uncertainty in the three key production function variables (the initial production rate (q i ), the initial decline in production experienced in the first year of production (D i ), and the slope coefficient that determines the change in the rate of decline in production (n)). The triangular distribution offers flexibility in modeling a wide variety of outcomes. Knowledgeable engineers and management personnel easily understand its parameters (minimum, most-likely, and maximum) and they can readily provide estimates. Table 4 contains the values used to define the distributions for each of these parameters. Table 4 Parameter Estimates for the Production Function Variables Parameter Minimum Value Most-Likely Value Maximum Value Initial Production Rate (Mcf/day) (q i ) Initial Decline in Production in Year 1 (D i ), % 4,053 19,500 31, Slope Coefficient (n) The parameter estimates for the initial production rate (q i ) are based upon a conversation with the chief reservoir engineer for the Haynesville gas well. He indicated that the initial year of production for wells such as ours could be as small as 500,000 Mcf (0.5 Bcf) or as large as 3,900,000 Mcf (3.9 Bcf) although the most likely level of production is roughly 2,500,000 Mcf (2.5 Bcf). These annual production estimates correspond to the three daily production estimates found in Table 4 for the minimum, most likely, and maximum values. 24 For the distribution around the initial decline in production in year one, we assumed maximums and minimums that were 10% larger and smaller than the most likely value. Figure 3 Frequency Distribution of NPV Producers often use a gas price assumption that matches the forward prices at which the firms could actually hedge future price risk (i.e., enter into forward contracts to sell gas). However, production for Haynesville #1 is estimated out 38 years, which is far beyond any firm s ability to lock in gas prices such that the firm is subjected to price risk. To model natural gas prices, we use a geometric Brownian motion model 25 that has two parameters: the mean rate of change and standard deviation in the rate of change in gas prices (volatility). We assume that the mean rate of change in future gas prices is zero and the annual volatility in future gas price changes is modeled using a triangular distribution using an assumed minimum value of.05, most likely value equal to.10, and maximum value of.30. Figure 3 shows frequency distributions for the NPV of the shale gas well. The expected NPV is $267,776 but the probability of a NPV of zero or greater is 60.13%, meaning there is a 39.87% probability that the well will produce a negative NPV. This estimate of project NPV is about $40,000 lower than the earlier deterministic estimate. The earlier estimate, however, corresponds to the results from one particular gas well in the Haynesville shale, whereas we have, through the engineer s experience, modeled the experience of several wells throughout the entire area. 26 It has long been recognized that oil and gas production typically offers valuable real options to the developer. 27 These options can be thought of in terms of options that exist before a shale gas drilling project has been launched and options that arise after the investment launch See the appendix for a description of the method used to calculate q i 25. Technically we are modeling forward prices or future spot prices for different dates in the future. Following common practice we assume that the mean drift or rate of change in prices over the forecast period is zero. See C. Blanco, S. Choi, and D. Soronow, Energy Price Processes Used for Derivatives Pricing & Risk Management, Commodities Now, (March 2001), The simulated value of the mean NPV and the original estimate diverged because of skewness in the probability distributions used in the simulation. 27. For an excellent overview of the use of option pricing analysis to evaluating oil and gas investments, see J. McCormack, Raoul LeBlanc, and Craig Heiser, Turning Risk into Shareholder Wealth in the Petroleum Industry, Journal of Applied Corporate Finance, 15, 2 (Winter 2002). 28. This discussion follows the dichotomy set forth by S. Titman and J. Martin, pages of Valuation: The Art and Science of Corporate Investment Decisions 2 nd edition, (Upper Saddle River, NJ: Prentice Hall, 2011). Journal of Applied Corporate Finance Volume 25 Number 4 Fall

9 Prior to drilling, both conventional and shale gas wells possess three fundamental types of options: staged investment options, timing options, and operating options. However, there are differences in value between the options attached to conventional and shale gas wells. Oil and gas drilling programs provide classic examples of staged investment options. Initial exploratory wells determine the potential of an investment play before full drill out and production commences. The sheer size of shale formations make the likelihood of successful follow-on wells quite valuable. For example, the Marcellus shale formation covers an area of more than 90,000 square miles. Once a productive site has been identified, multiple horizontal wells are often drilled from the same site going out in different directions into the shale formation. Timing options arise out of the legal right to postpone an investment in order to maximize value. Both conventional and shale gas well investment options involve finite term drilling leases that typically extend for three years. If the energy firm fails to drill within this three-year window, its lease with the land-owner lapses. So there is substantial pressure on the lessee to do at least minimal exploration in order to hold the lease to enjoy the opportunity to fully develop a property at some date. But the full production potential of the property does not have to be exploited in the initial lease period. Once some minimal level of success has been established then the option to defer or delay investing in drilling out the property is fully available to both the conventional and shale gas producer. Because shale gas wells produce high volumes in the first year and because they usually also present extensive followon drilling opportunities, they may possess an important timing option not possessed by conventional wells. That is, shale gas producers may have the ability to time the drilling of shale gas wells in response to short-term price movements for natural gas. The key determinants of the timing option are the cost of drilling and completing the shale gas well, the likelihood of success, and the volatility of gas prices. In a world of highly volatile natural gas prices the option to develop gas producing properties quickly and with a high degree of certainty as to the productive capacity of the new wells in response to price spikes can be extremely valuable. This analogy is very similar to the use of electric generation peaker plants that can be switched on and off in response to price spikes for power. Note, however, that the value of the timing option is diminished if drilling costs are positively correlated with the price of natural gas. If a high gas price results in a high demand to drill gas wells, and this leads to an increase in the rates charged for drilling rigs, this would reduce the value 29. See J. McCormack and Gordon Sick, Valuing PUD Reserves: A Practical Application of Real Option Techniques, Journal of Applied Corporate Finance, 13, 4 (Winter 2001), of the timing option. However, researchers have not found evidence of a strong association between drilling costs and the price of oil and gas. 29 Finally, exercising a timing option in a shale gas play is made difficult by virtue of the fact that it involves the coordination of multiple outside contractors including drilling contractors and companies that provide fracking services. Since it can be very difficult to move drilling and fracking rigs around the country in a timely way, this friction (and its associated cost) diminishes the value of the timing option. Operating options refer to the potential to design a drilling and production program in such a way as to provide the firm with the flexibility to respond to changing economic circumstances. For example, the development of drilling pads for drilling multiple shale gas wells from a single location can dramatically reduce the cost of drilling out a lease when compared to conventional drilling methods. Once a gas well has been drilled there are a host of different sources of operating flexibility or options available to the operator of the well. Some of the more important types of options include growth options, shutdown options, and abandonment options. Because the areas covered by shale formations are so large, shale gas investments offer a potentially valuable option to extend production once a viable well has been developed. This is due to the high probability of successful wells in the immediate vicinity of a successful well. This attribute of shale wells has important implications for the option value of shale versus conventional gas wells that favors shale. In addition to the timing option, the operator has an option to select the site that is most advantageous at the time of the drilling. For the most part, the selection is determined by the mix of hydrocarbons at the potential sites and the price of those hydrocarbon resources at the time of the drilling. Shale formations not only yield dry gas but often produce hydrocarbon liquids, so called rich gas or gas condensates, as well as oil. Depending on where you drill, you will produce a mix that may be almost exclusively dry gas, or may be almost exclusively liquids. Hence, once the play has been explored and liquid rich areas identified, the developer has the option to choose specific sites depending on the relative prices of the various hydrocarbon liquids and gas that will be produced. 30 The source of value to this option arises from the volatility of the market price difference between hydrocarbon liquids and gas. In recent history this difference has been quite volatile, and currently, the market price of the liquids is quite high relative to the gas. For example, the energy equivalent of 1 barrel of hydrocarbon liquids is about 7 Mcf gas. Using this figure and $5.3/Mcf, the price of 1 barrel of 30. Some shale plays, such as the Haynesville shale, produce only dry gas, whereas the northern most region of the Eagle Ford Shale in South Texas produces oil, the middle region produces wet gas (some liquids) and the southernmost region is dry gas only. 94 Journal of Applied Corporate Finance Volume 25 Number 4 Fall 2013

10 liquid should be about $35/barrel, a figure that is about 1/3 of the world oil price. It is no surprise that operators in shale gas plays are moving to liquids production when it is possible and deemphasizing dry gas production. However, the price ratio of gas and liquids can easily change over time, and if the gas prices change, drillers have the option to move their rigs to areas with dryer gas. The option to shut down operations or shut in a gas well comes in two basic forms: temporary and permanent. The ability to temporarily shut in a gas well is a timing option. The owner can produce gas when prices are high and shut in when prices are very low. To a limited degree it has long been recognized that conventional gas wells offer some degree of flexibility in timing production. But the timing option for shale gas wells is not yet fully understood because horizontal drilling and fracking technology is relatively new. We do not know what will happen to production volumes if wells are shut down for a period of time and then re-opened. Conceivably, intermediate ways of shutting down wells such as choking may actually increase the long-term production of the shale gas well. Both shale and conventional gas wells that also produce liquids through pumping present opportunities to temporarily suspend production. These shut in wells can later be brought back on line should gas prices rise to economic levels. Wells that require pumping are more costly to operate than dry gas wells that do not, and sufficiently high costs may make shutting the well in economic. It is not clear though, whether the well will produce at the same level just prior to the shut in after it is re-opened. 31 It is clear that options attached to both conventional and shale gas wells are potential sources of value but we cannot generalize. Each drilling play must be evaluated individually. Our most important finding is that a large number of drilling opportunities such as those in Haynesville shale region of North Louisiana have positive net present values even in a historically low gas price environment. Nevertheless, we acknowledge that our analysis is limited in some important ways. First, our model used production and cost estimates from a single well. That said, our results are more generally applicable because of our thorough sensitivity and simulation analysis. Second, we did not consider the possibility of producing very valuable liquids along with gas. The economics of liquids are critical in certain shale regions such as the Eagle Ford of south Texas. Third, we based our production decline curve on the combination of a hyperbolic and exponential curve that extended out over three decades. However, the Haynesville shale production is in its relative infancy, and it remains to be seen whether the production curves of these wells will follow this path. Recognizing this, we used different parameter estimates for the production decline curve. Finally, the price path of natural gas is modeled using a simple diffusion process that does not attempt to incorporate the possibility of shifts in price paths because of major changes in either the supply of, or demand for, natural gas. Conclusion Breakthroughs in shale gas extraction techniques such as horizontal drilling and fracturing ( fracking ) have dramatically increased estimates of recoverable gas reserves in the US. Although some observers have concluded from this that the US will enjoy great supplies of low-priced gas for a longtime to come, others are not so sure. The model of US shale gas drilling economics and NPV simulations presented here indicate that shale gas exploitation is probably sustainable (with a 60% likelihood) but major questions remain. NPVs are highly sensitive to gas price assumptions and projected production volumes. The base case assumes the current gas futures price curve, but a fall in price of just 17% along that curve would reduce the well NPV to zero. The model uses standard engineering assumptions about conventional wells for the relationship between first year production declines and subsequent production. Although it is clear that production from shale wells declines faster than from conventional wells, engineers have too little history to forecast ultimate production from shale wells with great confidence. Nevertheless, shale gas drilling opportunities also present energy companies with valuable follow-on real options that are not captured in NPV analysis. This additional source of value is inherent in vast shale gas formations where one successful well leads to additional development opportunities on attractive terms. Larry W. Lake holds the Sharon and Shahid Ullah Chair in Petroleum Engineering at the University of Texas at Austin. John Martin is Collins Professor of Finance at Baylor University. J. Douglas Ramsey is Director of Strategic Planning and Special Projects at EXCO Resources, Inc. Sheridan Titman holds the McAllister Chair in Finance at the University of Texas at Austin. 31. We are grateful to John McCormack for pointing out this second type of shut-in option to us. See J. McCormack and Gordon Sick, Valuing PUD Reserves: A Practical Application of Real Option Techniques, Journal of Applied Corporate Finance, 13, 4 (Winter 2001), Journal of Applied Corporate Finance Volume 25 Number 4 Fall

11 Appendix Production Decline Curves The methods used by reservoir engineers to estimate oil and gas reserves often rely on an empirical extrapolation based on physical characteristics of the reservoir. Over sixty years ago, J.J. Arps defined a set of empirical production decline curves based on the following three-parameter hyperbolic function: 32 1 q t = q i (1+nD i t) n (1A) Figure 1A Production Decline Curve (Initial Production = 8.6 Mmcf/day; Initial Decline rate = 50%; and the Hyperbolic Exponent =.90) where q t is the instantaneous production rate at time t (i.e., Mmcf/year); q i is the initial production rate at time 0; D i and n are two constants (the former is the initial rate of decline in production and n is the rate of change in D i over time); and t is the time period for which production is being estimated. Equation (1A) can be reduced in two special cases where n = 0 and n = 1. When n = 0 equation (1A) becomes an exponential decline, i.e., Estimated Mmcf/Day q t = q i e -D it (2A) When n = 1 equation (1A) reduces to the harmonic decline function, i.e., Year q t = q i (1+D i t) -1 (3A) In 1924, W.W. Cutler documented empirical support for the hyperbolic function with exponent values for n between 0 and 0.7 with most wells falling being between 0 and Using Equation (3A) to estimate production decline rates can be confusing because of how companies choose to report the initial rate of decline, D i. Specifically, the initial decline rate reported is typically the effective rate of decline based on the secant method. That is, if the initial rate of production per year is 10 at year 0 and the production rate is 5 at the end of one year, then the initial decline rate reported would be 50%. However, this is not the nominal rate of decline that should be used in Equation (3A). We calculate the nominal rate of decline from the reported rate using equation (4A): -n -1 D i = 1-D esi for n 0 (4A) n where D esi is the effective initial decline rate calculated using the secant method described above. Equation (1A) is the basis often used for reporting of decline curves to the media. For example, the Petrohawk Energy Corporation (HK) in a report dated April 24, 2010, said that its initial recovery wells in the Haynesville shale had an initial production rate of 8.6 Mmcf/d, an initial decline rate of 50%, and a hyperbolic exponent (n) of Figure 1A contains the production decline curve for the above inputs: The estimated ultimate recovery (EUR) for the Petrohawk example reported in Figure 1A was 9.9 Bcf. When the hyperbolic exponent n is greater than one Eq. (1A) extrapolates to an infinite estimated ultimate recovery (EUR). The EUR is the integral of Eq. (1A) over all time. When this occurs and it appears to for more than one-half of wells examined 35 the production decline curve must be converted to another type of function at some point so as to restrict the EUR to be finite. The switching point is arbitrarily set. For alternates that do not have this arbitrariness see the papers already mentioned by Clark, Lake, and Patzel and by Valko and Lee. 32. R.E. Allen described four types of production decline curves in J.J. Arps later expounded upon three of these (the exception being the first, the constant decline curve). 33. W.W. Cutler, Jr., Estimation of Underground Oil Reserves by Well Production Curves, USBM Bull, 228 (1924). 34. Petrohawk Energy Corporation, Enercom Oil & Gas Conference presentation (April 24, 2010). 35. A. J. Clark, Decline Curve Analysis in Unconventional Resource Plays using Logistic Growth Models, M.S. thesis, University of Texas at Austin, Journal of Applied Corporate Finance Volume 25 Number 4 Fall 2013

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